-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: keymaster@town.hall.org Originator-Key-Asymmetric: MFkwCgYEVQgBAQICAgADSwAwSAJBALeWW4xDV4i7+b6+UyPn5RtObb1cJ7VkACDq pKb9/DClgTKIm08lCfoilvi9Wl4SODbR1+1waHhiGmeZO8OdgLUCAwEAAQ== MIC-Info: RSA-MD5,RSA, M8ZojE9NKWNLP2MPwfXgiyBsMnOUxqTGLitJdh3P8EPtMktG7SQYgm8DzVBrHVEt Sqm3kg+UpBOeHFOz8xmAnw== 0000018675-94-000018.txt : 19940404 0000018675-94-000018.hdr.sgml : 19940404 ACCESSION NUMBER: 0000018675-94-000018 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 5 CONFORMED PERIOD OF REPORT: 19931231 FILED AS OF DATE: 19940331 FILER: COMPANY DATA: COMPANY CONFORMED NAME: CENTRAL MAINE POWER CO CENTRAL INDEX KEY: 0000018675 STANDARD INDUSTRIAL CLASSIFICATION: 4911 IRS NUMBER: 010042740 STATE OF INCORPORATION: ME FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 34 SEC FILE NUMBER: 001-05139 FILM NUMBER: 94519771 BUSINESS ADDRESS: STREET 1: EDISON DR CITY: AUGUSTA STATE: ME ZIP: 04336 BUSINESS PHONE: 2076233521 10-K 1 TEXT UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K (Mark One) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 [FEE REQUIRED] For the fiscal year ended December 31, 1993 TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED] For the transition period from to Commission file number 1-5139 CENTRAL MAINE POWER COMPANY (Exact name of registrant as specified in its charter) Maine 01-0042740 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 83 Edison Drive, Augusta, Maine 04336 (Address of principal executive (Zip Code) offices) Registrant's telephone number, including area code:(207) 623-3521 Securities registered pursuant to Section 12(b) of the Act: Name of each exchange Title of each class on which registered Preferred Stock, 7 7/8% Series New York Stock Exchange Common Stock, $5 Par Value New York Stock Exchange Securities registered pursuant to Section 12(g) of the Act: 6% Preferred Stock, $100 Par Value (Voting, Noncallable) (Title of class) Dividend Series Preferred Stock, $100 Par Value (Callable) (Title of class) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K __. State the aggregate market value of the voting stock held by non-affiliates of the registrant. The aggregate market value of the voting stock held by non-affiliates of the Company was $425,195,134 on March 21, 1994 (based, in the case of the common stock of the Company, on the last reported sale price thereof on the New York Stock Exchange on March 21, 1994). (APPLICABLE ONLY TO CORPORATE REGISTRANTS) Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date. The number of shares of the Company's Common Stock, $5 par value (being the only class of common stock of the Company), outstanding on March 21, 1994, was 32,442,752 shares. DOCUMENTS INCORPORATED BY REFERENCE List hereunder the following documents if incorporated by reference and the Part of the Form 10-K (e.g., Part I, Part II, etc.) into which the document is incorporated: (1) Any annual report to security holders; (2) Any proxy or information statement; and (3) Any prospectus filed pursuant to Rule 424(b) or (c) under the Securities Act of 1933. Portions of the Company's Annual Report to Shareholders for the year ended December 31, 1993 are incorporated by reference in Part I and Part II hereof. Portions of the definitive proxy statement for the Company's 1994 Annual Meeting of Shareholders are incorporated by reference in Part III hereof. CENTRAL MAINE POWER COMPANY INFORMATION REQUIRED IN FORM 10-K Item Number Page Part I Item 1. Business . . . . . . . . . . . . . . . . . 1 Item 2. Properties . . . . . . . . . . . . . . . . 16 Item 3. Legal Proceedings . . . . . . . . . . . . . 24 Item 4. Submission of Matters to a Vote of Security Holders . . . . . . . . . . . . . 26 Item 4.1.Executive Officers of the Registrant . . . . 26 Part II Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters . . . . . . . . . . . . . . . . . . 28 Item 6. Selected Financial Data . . . . . . . . . . 28 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations . . . . . . . . . . . . . . . 30 Item 8. Financial Statements and Supplementary Data . . . . . . . . . . . . . . . . . . . 30 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure . . . . . . . . . . . 30 Part III Item 10. Directors and Executive Officers of the Registrant . . . . . . . . . . . . . . 31 Item 11. Executive Compensation . . . . . . . . . . 31 Item 12. Security Ownership of Certain Beneficial Owners and Management . . . . . . . . . . . 31 Item 13. Certain Relationships and Related Transactions . . . . . . . . . . . . . . . 31 Part IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K . . . . . . . . . . 31 Signatures . . . . . . . . . . . . . . . . . . . . . 34
PART I Item 1. BUSINESS. Introduction General. Central Maine Power Company (the "Company") is an investor-owned Maine public utility incorporated in 1905. The Company is 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. Its principal executive offices are located at 83 Edison Drive, Augusta, Maine 04336, where its general telephone number is (207) 623-3521. The Company has more customers and greater revenues than any other electric utility in Maine, serving approximately 500,000 customers in its 11,000 square-mile service area in southern and central Maine and having $894 million in consolidated electric operating revenues in 1993 (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 936,000 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 66 percent of the Company's industrial sales and approximately 27 percent of total service- area sales. Cost Reduction and Restructuring. Overall demand for energy from the Company's system increased at a rate of 0.4 percent in 1993, after an increase of 0.8 percent in 1992. The low rate of increase can be attributed to continued weakness in the Maine economy, significant competition from alternative fuel sources, the effects of the Company's demand-side management programs and other factors. The Company's earnings per share declined from $1.85 in 1992 to $1.65 in 1993. The rate of return on common equity for 1993 was 9.77 percent compared with 11.25 percent earned in 1992. The reduced earnings level for 1993 is attributable to higher costs, weak sales and cost disallowances associated with two proceedings before the Maine Public Utilities Commission ("Maine PUC", "MPUC" or "PUC") during 1993. For a discussion of those proceedings, see "Base Rates" and "MPUC NUG Contracts Investigation" under "Regulation and Rates", below. The combination of weak sales due to economic and competitive pressures and the disappointing and inadequate base- rate-case decision in December 1993 offers the Company no reasonable opportunity to achieve a level of 1994 earnings near the 1993 level or the current allowed rate of return of 10.05 -1- percent on common equity. Moreover, the unfavorable outlook for the Company's near-term earnings capacity takes into account the significant reductions in previously planned 1994 operations, maintenance, and capital expenditures being implemented by the Company as part of its broad cost-reduction program. As a result of such factors, the Company's credit ratings came under significant pressure during 1993 and early 1994 when its senior secured debt was downgraded by all three agencies that rate the Company's securities, one of which lowered the rating to below investment grade. The Company's junior securities came under even more pressure late in the year, being assigned, in most cases, non-investment-grade ratings. The decline in the Company's credit ratings will impair its access to the capital markets, make the terms and conditions of borrowing more stringent, and increase its cost of capital, and has already substantially reduced, if not eliminated, the Company's access to the commercial-paper markets. The credit-rating agencies cited the stagnant economy, inadequate rate relief and pricing flexibility, increased competition, and uncertainty of recovery of non-utility purchased-power costs as reasons for the credit downgrades. For a more detailed discussion of the downgrades, see "Financing and Related Considerations" - "Rating Agency Actions", below. After review of the Company's overall financial position and outlook, including the impacts associated with the MPUC's rate- case order and the expected near-term revenue impacts of weak sales, the Company's Board of Directors voted on December 15, 1993, to reduce the quarterly common-stock dividend from 39 cents to 22.5 cents per share. The dividend reduction is part of a broad-based cost-reduction and restructuring program designed to stabilize the Company's rates and enhance its financial condition. The program is composed of three major initiatives: (1) reduce the Company's operating costs while maintaining appropriate levels of service; (2) reduce the Company's largest external expense, non-utility power costs; and (3) work with regulators on innovative, competitive new pricing and service options. The first step in implementing the cost-reduction strategy was to restructure the Company's organization along functional lines and eliminate 225 full-time-equivalent jobs, or approximately 10 percent of the Company's work-force, which was accomplished in March 1994. In addition, the Company's operating budget for 1994 was cut $22 million, or 12 percent, from previously planned levels, and the 1994 capital budget for plant, equipment, and conservation programs by $14 million, or 19 percent, from previously planned levels. The second component of the plan, reducing the cost of non- utility power, stresses continued efforts to renegotiate, buy out or terminate high-cost purchased power contracts. It also includes support for Maine legislative action on bills that could have the effect of reducing such costs. The final segment includes continuing efforts to achieve changes in regulation that would redefine the basis for overall price changes and provide flexibility in setting specific prices and in the acquisition and use of resources. As detailed below -2- under "Regulation and Rates" - "Rate Stability Plan", the Company has indicated interest in pursuing a modified price-cap approach to the regulation of its electric rates and, consistent with the terms of the PUC's December 1993 order in the base-rate case, has been engaged in discussions with rate-case intervenors as to the structure of such a plan. The Company expects to file a rate- stability plan with the PUC sometime in the first half of 1994. The Company is committed to its cost-reduction and restructuring program. It believes that its ability to restore earnings to competitive levels and improve its overall financial health is closely tied to the success of the program. 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 pages 1 through 49 of Exhibit 13-1 hereto (the Company's Annual Report to Shareholders for the year ended December 31, 1993), which pages are hereby incorporated herein by reference. Topic Page Non-utility Generation . . . . . . 3 Maine Yankee Atomic Power Company Competition . . . . . . . . . . . . 4 Regulation and Rates . . . . . . . 5 Financing and Related Considerations . . . . . . . . . 11 Environmental Matters . . . . . . . 13 Water Quality Control . . . . . . 14 Air Quality Control . . . . . . . 14 Hazardous Waste Regulations . . . 14 Electromagnetic Fields . . . . . 15 Capital Expenditures . . . . . . 15 Employee Information . . . . . . . 15
Non-utility Generation The Company has been an industry leader in developing supplies of energy from non-utility generators, including cogeneration plants and small power producers. These sources supplied 4.0 billion kilowatt-hours of electricity to the Company in 1993, representing 40.2 percent of total generation, an increase from 38.2 percent in 1992. The Company expects to obtain approximately 44 percent of its energy from this source in 1994. The Company's contracts with non-utility generators, however, which were entered into pursuant to 1978 federal legislation and vigorous state implementation thereof, have contributed the largest part of the Company's increased costs in recent years. This has caused the Company to pursue re- negotiations or buyouts of such contracts wherever practicable. For further discussion of independent power production, see Item 2, Properties, "Non-utility Generation". For a discussion of a regulatory proceeding involving the Company's management of its contracts with non-utility generators, see "Regulation and Rates" - "MPUC NUG Contracts Investigation", below. -3- Maine Yankee Atomic Power Company The Company owns a 38 percent stock interest in Maine Yankee Atomic Power Company ("Maine Yankee"), which owns and operates a nuclear generating plant in Wiscasset, Maine (the "Maine Yankee Plant"). The Maine Yankee Plant has been in commercial operation since 1972 and has consistently produced power at a cost among the lowest in the country for nuclear plants. In 1993 the Maine Yankee Plant produced 5.7 billion kilowatt-hours of electric power, the highest total ever for a year that included a scheduled refueling and maintenance shutdown, at an average cost of 3.4 cents per kilowatt-hour. The average capacity factor for the Maine Yankee plant in 1993 was 76 percent. For further discussion of Maine Yankee, see "Regulation and Rates", below, and Item 2, Properties, "Existing Facilities". Competition In October 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, (1) enhanced access to electric transmission to promote competition for wholesale purchasers and sellers, (2) statutory reforms to encourage utility participation in the formation of exempt wholesale generators, (3) tax credits for electricity generation from renewable energy sources, (4) tax incentives for the use of alternative fuels, and (5) required fleet vehicle conversion to alternative fuels. The Policy Act has been a significant factor in creating new areas of competition for the Company. The Company is facing competition in several areas of its traditional business and anticipates that the new competition will continue to place pressure on both sales and the price the Company can charge for its product. Alternative fuels and pre- Policy Act regulation that had restricted competition from outside of the Company's service territory have expanded customers' energy options. As a result, the Company has been involved in a number of negotiations with certain of its customers and will continue to pursue retention of its customer base. This increasingly competitive environment has resulted in the Company's entering into contracts with two of its wholesale customers, as well as with certain of its industrial and commercial customers, to provide their energy needs at prices and margins lower than the current averages. For a discussion of the potential loss of the largest wholesale customer of the Company to an out-of-state supplier, see "Regulation and Rates" - "Potential Loss of Wholesale Customer", below. In addition to negotiating a number of special agreements with large customers, the Company is also pursuing with the MPUC alternative pricing mechanisms that would allow the Company the flexibility to modify the price of its product in certain instances, when the competitive alternatives could result in the loss of a significant end use of electricity. In its preliminary discussions, the MPUC has indicated there may be instances in which the ability of the Company to adjust its price in response -4- to competitive pressures is advisable. In February 1994, the MPUC approved a specific competitive-pricing plan under which the Company will operate with respect to residential water-heating customers. The Company believes it may be granted the authority to develop additional market-responsive rates in certain circumstances in the future. For a discussion of relevant PUC orders, see "Regulation and Rates" - "Rate Design", below. Regulation and Rates The Company is subject to the regulatory authority of 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 as to some phases of its business, including licensing of its hydroelectric stations, accounting, rates relating to wholesale sales (which constitute less than one percent of operating revenues) and to interstate transmission and sales of energy and certain other matters, to the jurisdiction of the Federal Energy Regulatory Commission ("FERC") under Parts I, II and III of the Federal Power Act. 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 all of the Company's thermal 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 and local 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 27 FERC-licensed projects, some of which include more than one generating unit. Thirteen licenses were scheduled to expire in 1993, one in 1997, and thirteen after 2000. The Company 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 -5- action on relicensing by the FERC. 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. Base Rates. On March 1, 1993, the Company filed a request with the MPUC for a $95-million increase in base rates. The major components of the request were (1) compensating for lower-than-forecasted sales, (2) increased operation and maintenance expenses, (3) increased operating costs of the four operating nuclear plants in which the Company owns interests, (4) property additions and transmission, distribution and other improvements, (5) energy-management program costs and, (6) the expiration of the flow-through of certain tax benefits. Ultimately, the Company reduced the amount of its base-rate request from $95 million to $83 million. The decrease was the result of lower estimates of 1994 operation and maintenance expenses, further reductions in the Company's cost of capital, a decrease in the level of anticipated expenditures for energy management programs and the change in the federal income-tax rate from 34 percent to 35 percent. On December 14, 1993, the MPUC issued its order in the proceeding. The MPUC's analysis indicated a need for additional revenues of $51.5 million, yet found the Company to be entitled to a net revenue increase of only $26.2 million. The Commission found a total cost of capital of 8.52 percent and a cost of equity of 10.05 percent, after deducting a one-half percent (.5%) return-on-equity penalty established by the MPUC in a 1993 investigation of the Company's management of certain independent power-producer contracts. See "MPUC NUG Contracts Investigation" below, for further discussion of this investigation. To arrive at its revenue-requirement conclusion, the MPUC deducted $25.3 million "to adjust for management inefficiency" after finding the Company's performance in the areas of management efficiency and cost-cutting to have been "inadequate", based largely on the recommendations contained in a management audit of the Company conducted by a consultant retained by the MPUC. The Company strongly disagrees with the MPUC's management-inefficiency finding and with the resulting deduction of nearly one-half the revenue increase to which the Commission itself found the Company to be otherwise entitled using traditional ratemaking principles. The Company filed an appeal of the base-rate order with the Maine Supreme Judicial Court. The Company cannot, however, predict the result of that appeal. -6- Rate-Stability Plan. In connection with the base-rate proceeding, on July 21, 1993, the Company filed an alternative rate proposal designed to promote stability in the Company's rates. The proposal consisted of a combination of pricing and regulatory changes that would, among other things, limit future rate increases to annual changes based on the rate of inflation and mandated costs, and revise existing regulatory rules and policies to allow the Company to adjust prices more rapidly in response to customer needs and competitive factors. In its December 14, 1993, base-rate order, the MPUC ordered that a follow-up proceeding be held to implement by mid-1994 a rate-stability plan along the lines discussed in the order. The MPUC encouraged the Company and the parties wishing to participate in the proceeding to work together to develop a plan containing price-cap, profit-sharing, and pricing-flexibility components. The MPUC also directed that the initial plan have a duration of five years, subject to a brief annual proceeding to implement any applicable rate changes, and a detailed review at the end of the fourth year to evaluate the performance of the plan and initiate necessary changes. Participants in the rate-stability plan proceeding have prepared price-cap proposals in response to the MPUC's order and regular discussions are being held. The Company cannot predict the outcome of this process or the MPUC's ultimate decision on a rate-stability plan. Fuel Clause Adjustment. The Company's electric sales are subject to a fuel adjustment clause that enables the Company to recover from its customers both fuel costs and the increasing amounts of the fuel component of purchased-power costs, including non-utility generation. The Company also collects carrying costs on unbilled fuel and pays interest on fuel-related over- collections. In accordance with a January 1993 ratemaking stipulation, the MPUC approved, as part of the $40 million July 1993 revenue increase, $17 million to reduce deferred fuel-clause balances. Earlier, in July 1992, the MPUC issued an order authorizing an increase, effective September 1, 1992, in the Company's fuel cost adjustment of $13.2 million of the $38.7 million requested by the Company, along with the Electric Revenue Adjustment Mechanism ("ERAM") and demand-side-management incentives discussed below under "Incentive Regulation". The orders extended the smoothing approach that had begun in 1988, resulting in unrecovered fuel and purchased-power costs being deferred for future recovery. Rate Design. Effective in December 1991, the Company implemented a rate-design order from the PUC that was intended to realign customer class revenues and specific rate components more closely with marginal costs. These rate design changes, which raised or lowered some customers' rates by as much as eight percent, were intended to reallocate revenues from customer classes, but not to produce any change in aggregate revenues for the Company. In February 1992, the Company filed a request with the PUC to re-examine several rate-design changes in response to concerns regarding the impact of such changes on some classes of residential customers. After considering a number of proposals by the Company and other parties, the PUC reduced the highest winter time-of-use rates by a small percentage from the prior -7- winter's rates, effective in December 1992. The increases in on- peak rates in December 1991 resulting in part from the rate- design changes have caused a significant number of the Company's residential electric heating customers and water heating customers to convert to other fuel sources. On February 18, 1994, the PUC issued its order in an investigation of the Company's resource planning, rate structure, and avoided cost that was initiated in December 1992. The primary purpose of the investigation was to examine the Company's "long-term costs and their relationships to usage and prices, and to specify any implications for CMP's resource planning activities and general rate structure policies." In its order the PUC found, among other things, (1) "no reason to encourage electric utilities to pursue broad promotion of load growth . . . absent a clear and convincing demonstration that ratepayers as a group would benefit from such efforts"; (2) "that CMP's proposed strategy of encouraging marginal usage through broad adoption of declining block rates is not cost-justified . . ." but the PUC said it would "continue to encourage proposals for targeted, short-term rates that are carefully designed to retain movable load"; and (3) the PUC reaffirmed its "existing policy of encouraging narrowly-focused economic incentive rates for particular kinds of customers, when it can be shown that other ratepayers will not be harmed". The PUC also indicated that it would initiate a rulemaking proceeding to determine how "special rates for customers with competitive alternatives should best reflect the utility's obligation to serve, particularly with respect to backup and maintenance rates . . .." The Company cannot predict what changes it will ultimately be permitted to implement in the areas of resource planning, rate structure, and avoided cost. MPUC NUG Contracts Investigation. On October 28, 1993, in connection with an investigation of the Company's management of independent power-producer contracts, the MPUC issued an order finding that the Company had been unreasonable and imprudent in its management of two independent power-producer contracts and indicated that it would reduce the Company's allowed rate of return on equity by 0.5 percent in the then-pending base-rate case (approximately $4 million, before income taxes, over a 12-month period) and also directed the Company to charge against deferred fuel-cost balances approximately $4.1 million of payments from power providers that had previously been credited against purchased-power capacity costs, unless the Company could demonstrate that the crediting was proper. The Company recorded a reserve totalling $4.1 million during the third quarter of 1993, reflecting the impact of the order. Finally, the MPUC announced that it would review in the future the Company's administration and management of certain power-purchase contracts for purchases of ten megawatts or more. On December 20, 1993, the Chief Justice of the Maine Supreme Judicial Court (the "Court"), acting on the Company's request, issued an order staying the effectiveness of the 0.5-percent return-on-equity penalty pending final resolution of the Company's appeal of the October 28, 1993, MPUC order to the Court. In addition, the Court ordered that if the Company should not prevail on its appeal, it would be required to refund any -8- revenues collected as a result of the stay order, with interest. Finally, the Court ordered an expedited hearing on the appeal, scheduling oral argument before the Court for March 1994. On February 3, 1994, the MPUC filed a motion to dismiss with the Court, stating that by order dated February 3, 1994, the Commission had reopened and reconsidered its October 28, 1993 decision. As a result of its reconsideration, the MPUC decided to vacate the return-on-equity penalty conditioned on either the Company's acquiescence in the MPUC's jurisdiction or a finding by the Court that the MPUC had retained jurisdiction, and to consider alternative remedies. The MPUC argued that because of its February 3 order the Company's appeal of the return-on-equity penalty should be dismissed as moot. The Chief Justice declined to dismiss the appeal and added the jurisdictional question to the issues to be determined by the Court. The MPUC, in its February 3, 1994 order, indicated that an alternative under consideration by the MPUC "appears to present an opportunity to insulate ratepayers sufficiently from CMP's imprudence...," yet also noted, "We do not decide at this time that such a remedy . . . will be adopted." The order indicated an intent to seek additional information on the issue of annual differences between the contract rates and avoided costs. The case was argued on March 17 and a decision is expected by early summer 1994. The Company cannot predict the outcome of the appeal on either the issue of jurisdiction or the merits of the return-on-equity penalty, or the outcome if remanded to the PUC, including any subsequent appeal of any alternative remedy. Incentive Regulation. In May 1991 the MPUC ordered a three-year trial of the ERAM, which was a fundamental change in the way the Company's revenues were treated and set new incentives for effective utility-sponsored energy management. In July 1992 the MPUC issued an order authorizing the Company to begin collecting $7.8 million, which was only a portion of the $26.2 million of ERAM revenues accrued in its first year, and an energy-management incentive of $1.5 million, beginning in September 1992. Approximately $18.4 million of ERAM revenues accrued in the 12 months beginning in March 1991 were therefore carried over to the 1993 ERAM filing. In January 1993, the MPUC approved a stipulation that resolved several outstanding issues, including those in the Company's ERAM proceeding. The stipulation permitted recovery of accrued ERAM balances in accordance with the terms of a Financial Accounting Standards Board Emerging Issues Task Force consensus. The stipulation also authorized recovery of the costs associated with buy-outs by the Company of certain purchased-power contracts and requested the MPUC to grant an increase in the Company's fuel-cost adjustment. The stipulation also approved an accounting order permitting the Company to accelerate the flow-back of $5.9 million of certain deferred taxes associated with prior losses on reacquired debt. For 1992, the stipulation placed a limit of 11.25 percent on the Company's allowed rate of return on equity. Earnings in excess of the limit, up to approximately $10 million (the revenue requirement of the tax benefits), were applied on a monthly basis to reduce 1993 ERAM -9- accruals. In addition, approximately $317,000 of income, net of income taxes, in excess of the $10 million, was used to fund a portion of 1993 operation-and-maintenance expenses. The January 1993 stipulation also reduced the amount of ERAM accruals from January 1993 through November 1993 by $591,000 per month. The ERAM program continued until December 1, 1993, which was the effective date of the new base rates resulting from the Company's 1993 base-rate proceeding. As contemplated by the terms of the stipulation, the MPUC subsequently approved a revenue increase of $40 million, effective July 1, 1993, which included, among other things, $21.2 million toward recovery of deferred ERAM revenues. As of December 31, 1993, the Company had collected approximately $19.2 million of the ERAM revenues; the unbilled ERAM balance at that time was approximately $50.5 million. Potential Loss of Wholesale Customer. On July 28, 1993, the Town of Madison Electric Works (Madison), a wholesale customer of the Company, announced that it had selected a competitive bid from Northeast Utilities (NU) and was entering negotiations for NU to become its wholesale electric supplier for a period of up to ten years. The Company's bid was rejected by Madison for being submitted after the ten-day bidding period. NU, a Connecticut-based holding company with substantial excess generating capacity, had submitted a bid to provide up to 45 megawatts of capacity at a rate that would initially be well below the Company's existing rates. Substantially all of the 45 megawatts would supply a large paper-making facility in Madison's service territory that has been served directly by the Company under a special service agreement with Madison during the last 12 years. The Company understands that Madison intends to start taking power from NU in late 1994 for that portion required to serve the paper-making facility and in late 1996 for its remaining requirements. Losing Madison as a wholesale customer would reduce the Company's non-fuel revenues by approximately $11 million annually when fully in effect, based on current rates and 1993 sales, minus any amounts paid to the Company for transmission of the NU power from the New Hampshire border. The Company intervened in opposition to Madison's petition to the MPUC for approval of its contract with NU, but cannot predict what action the MPUC will take on the petition. The Company has also filed with the FERC for approval of a contract to provide transmission service for Madison over the Company's system. The filing seeks recovery of the full cost of providing transmission service as well as compensation for any "stranded investment" of the Company in facilities that would no longer be needed to serve the Madison area. FERC Power Contracts Settlement Agreement. In August 1991, the FERC issued an order requiring the Company to revise its rates to a level reflecting the filed cost of service associated with each of 14 contracts for non-territorial sales, rather than the negotiated market-based levels. In 1991 the Company established a $4.5 million reserve to reflect refunds associated with some of the contracts. In 1992 the Company reversed -10- approximately $1.9 million of that reserve as a result of a settlement agreement that required the Company to refund approximately $2.6 million related to that issue. After rejection by the FERC of the Company's continuing claims of disparate treatment based on its having been ordered to make refunds while several similarly situated utilities were not, on September 29, 1993, the FERC rescinded the Company's obligation to make refunds. In making its decision, the FERC invoked its "equitable discretion" and agreed that, based on its having granted a general amnesty from refunds to other utilities, circumstances had changed so dramatically since its approval of the Company's 1992 refund settlement that it would be "unfair to continue to single out Central Maine for refunds." The FERC order allowed the utilities that had shared the $2.6 million in refunds to repay the Company, with interest, over a 24-month period. The utility that received the major share of the amount refunded by the Company requested reconsideration of the FERC rescission order. The Company recorded approximately $3.0 million of income during the third quarter of 1993, reflecting the refund including interest. On March 22, 1994, the parties submitted to the FERC a settlement agreement which, if approved, would require the Company to deliver a combination of cash and power sales having an aggregate value of up to $1.2 million. Financing and Related Considerations During 1993, the Company met its capital requirements (including the refunding of several outstanding securities issues) from a variety of sources, including the issuance of additional General and Refunding Mortgage Bonds, utilization of its unsecured Medium-Term Note Program and its Dividend Reinvestment and Common Stock Purchase Plan, short-term unsecured debt borrowings, including commercial paper, and internally generated funds. Financings. During 1993, the Company continued its program of refinancing its outstanding debt to take advantage of lower interest rates. The Company issued $75 million of Series Q 7.05% Due 2008 General and Refunding Mortgage Bonds in March, $50 million of Series R Bonds, 7 7/8% Due 2023 in May, $60 million of Series S Bonds, 6.03% Due 1998 in August, and $75 million of Series T Bonds, 6.25% Due 1998 in November. None of those series has a sinking fund, and the Series S and Series T Bonds are not callable at the option of the Company. The Series Q and Series R Bonds are not callable at the option of the Company prior to March 1, 1998, and June 1, 2003, respectively, except under limited circumstances. The Company redeemed its $100-million Series I Bonds, 9 1/4% Due 2016 in the second quarter of 1993, $50 million of its Series M Bonds, 9.18% Due 1995 in the third quarter of 1993, and $27.5 million of its Series N Bonds, 8.50% Due 2001 in the fourth quarter of 1993. Premiums paid on redemptions totalled $9.6 million. These financing and refinancing transactions reduced the annual cost of the Company's mortgage debt to 7.1 percent at -11- December 31, 1993, from 8.5 percent at December 31, 1992. During the year, the Company also raised approximately $25.5 million of additional capital through its Dividend Reinvestment and Common Stock Purchase Plan, resulting in the issuance of 1.2 million new shares of common stock. Effective in January 1994, however, the Company elected to authorize an agent to purchase outstanding shares for this plan on the open market, rather than issue new shares. As a result, the Company's current plans call for no additional shares of common stock to be issued for the next several years. In 1993, the Company issued $48 million of notes under its $150-million medium-term note program at an average interest rate of 4.8 percent and an average life of 2.9 years. Notes in the amount of $26.5 million matured during the year, increasing the total outstanding medium-term notes at year-end 1993 to $146.0 million from $124.5 million at year-end 1992. The proceeds from the debt and equity issuances were used for general corporate purposes, which included financing construction and energy-management projects, retiring or refunding outstanding securities, repaying short-term debt, and buying out purchased-power contracts. Rating Agency Actions. Beginning in late August 1993, three major securities-rating agencies lowered their ratings on the Company's outstanding debt and preferred stock on a number of occasions. In October 1993, Duff & Phelps Credit Rating Co. lowered the Company's fixed income ratings as follows: General and Refunding Mortgage Bonds from "BBB+" to "BBB-"; unsecured notes from "BBB" to "BB+"; and preferred stock from "BBB" to "BB-." Standard & Poor's Corp. ("S&P") announced in late October 1993, the application of more stringent financial-risk standards to the investor-owned utility industry to reflect S&P's view of mounting business risk. S&P stated that it believed the industry's "credit profile" was being "threatened chiefly by intensifying competitive pressures but also by sluggish demand expectations, slow earnings growth prospects, high common dividend payout, environmental cost pressures, and nuclear operating cost and decommissioning challenges." As a result, S&P revised rating outlooks for about one-third of the industry and placed the Company and several other utilities on "CreditWatch with negative implications." On January 5, 1994, S&P removed the Company's ratings from "CreditWatch" and lowered them again as follows: senior secured debt to "BB+" from "BBB-"; senior unsecured debt to "BB-" from "BB+"; preferred stock to "B+" from "BB"; and commercial paper to "B" from "A-3." In addition, S&P assigned its preliminary "BB+" senior-secured-debt rating to the Company's $150-million General and Refunding Mortgage Bonds previously registered with the Securities and Exchange Commission as a "shelf" registration. On January 13, 1994, Moody's Investors Service ("Moody's") lowered its rating on the Company's preferred stock to "ba2" from "baa3" and its short-term debt rating for the Company's commercial paper to "Prime-3" from "Prime-2." At the same time, -12- Moody's confirmed its ratings on the Company's General and Refunding Mortgage Bonds at "Baa2", unsecured medium-term notes and pollution control revenue bonds at "Baa3", and the Company's Securities and Exchange Commission "shelf" registration for $150,000,000 of General and Refunding Mortgage Bonds to "(P)Baa2." The rating agencies explained that the downgrades primarily reflected the MPUC's "unsupportive" base-rate decision, which in their opinion will not allow the Company's financial parameters, adjusted for off-balance-sheet obligations, to remain at acceptable levels for a utility with a "below-average" business position. In addition, the rating agencies expressed the belief that the Company's business position also reflected a depressed Maine economy, a large industrial-customer base, difficulty in materially reducing its significant purchased-power obligations, relatively high production costs, increasing rate pressures, and a high dividend payout. Deferred Costs. Over the past few years, the amount of the Company's deferred charges and regulatory assets has increased under the regulatory policies of the MPUC. The Securities and Exchange Commission has periodically considered issues regarding the proper accounting treatment of charges deferred by regulatory policy. As a result, the Company has regularly requested the MPUC to issue accounting and ratemaking orders to provide appropriate authority to comply with changing accounting requirements and to allow the Company to appropriately reflect the amounts as deferred charges and regulatory assets. In recent years, the Company received such orders with respect to issues in the 1991 Early Retirement Incentive Program, ERAM, purchased-power contract buy-outs, environmental-site cleanup costs, taxes on losses on reacquired debt, and accounting for postretirement benefits and income taxes pursuant to the newly issued accounting standards. The Company will monitor situations that result in deferred charges and regulatory assets and will seek appropriate regulatory approvals. For further discussion of financing considerations affecting the Company, see the information incorporated by reference in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, and Item 8, Financial Statements and Supplementary Data (Notes 4 and 7 of Notes to Financial Statements), below. 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 -13- 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 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, a state regulation restricts the sulfur content of the fuel oil burned in Maine to 2.0 percent. However, all oil burned at William F. Wyman Unit No. 4 in Yarmouth, Maine, is required by license to have a sulfur content not exceeding 0.7 percent, and the other three units at Wyman Station are required to have a sulfur content not exceeding 1.5 percent when Wyman Unit No. 4 is in operation. The Company believes that it will continue to be able to obtain a sufficient supply of oil with the required sulfur contents, subject to unforeseen events and the factors influencing the availability of oil discussed under Item 2, Properties, "Fuel Supply", below. The operation of the Company's present fuel adjustment clause permits it to recover any additional cost of such fuel from its customers upon review by the MPUC. 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. -14- For a discussion of a 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 supports further research on this subject and 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 1989 through 1993 totaled approximately $22.9 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, 1993, the Company had 2,103 full-time employees, of whom approximately 46 percent are 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 1993 was due largely to the implementation of an early retirement program and other efficiency measures in 1991 and 1992. In the first quarter of 1994 the Company further reduced its staffing in connection with its restructuring and cost-reduction program described above under "Introduction" - "Cost Reduction and Restructuring". In 1989 the Company and its employees represented by the union agreed to a three-year contract, which was to expire on May 1, 1992. In November 1991, however, the Company and the union agreed to a three-year extension of the contract providing for annual wage increases of 3 percent, 3 percent, and 3.5 percent, respectively, for each of the three years ending on May 1, 1995, respectively. Item 2. PROPERTIES. Existing Facilities -15- 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, 1993, the Company had approximately 2,273 circuit-miles of overhead transmission lines, 18,605 pole-miles of overhead distribution lines and 1,182 miles of underground and submarine cable. The maximum one-hour firm system net peak load experienced by the Company during the winter of 1993-1994 was approximately 1,337 megawatts on January 27, 1994. At the time of the peak, the Company's net capability was 1,977 megawatts. The maximum such peak load experienced by the Company during the preceding three winters was approximately 1,456 megawatts on January 8, 1991, at which time the Company's net capability was 2,069 megawatts. The New England Power Pool ("NEPOOL"), of which the Company is a member, had sufficient installed capacity and firm purchases to meet the NEPOOL four- year peak load of 19,742 megawatts experienced on July 19, 1991, and its 1993-1994 winter peak load of 19,534 megawatts on January 19, 1994. See "NEPOOL", below. The Company operates 28 hydroelectric generating stations with an estimated net capability of 368 megawatts and purchases an additional 91 megawatts of hydroelectric generation in Maine. It is currently re-evaluating some of its older hydroelectric plants in conjunction with efforts to obtain new federal operating licenses, with the objective of increasing their output and extending their usefulness. The Company also operates one oil-fired steam-electric generating station, William F. Wyman Station in Yarmouth, Maine, after de-activating its Mason Station in Wiscasset, Maine, in 1991. The Company's share of William F. Wyman Station has an estimated net capability of 592 megawatts. The oil-fired station is located on tidewater, permitting waterborne delivery of fuel. The Company also has three internal combustion generating facilities with an estimated aggregate net capability of 41 megawatts. The Company has ownership interests in five nuclear generating plants in New England. The largest is a 38-percent interest in Maine Yankee, which generates power at its plant in Wiscasset, Maine. In addition, the Company owns a 9.5 percent interest in Yankee Atomic Electric Company ("Yankee Atomic"), which has permanently shut down its plant located in Rowe, Massachusetts, a 6 percent interest in Connecticut Yankee Atomic Power Company ("Connecticut Yankee"), with a plant in Haddam, Connecticut, and a 4 percent interest in Vermont Yankee Nuclear Power Corporation ("Vermont Yankee"), which owns a plant located 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. In February 1992, the Board of Directors of Yankee Atomic, after concluding that it would be uneconomic to continue to operate, decided to permanently discontinue power operation at -16- the Yankee Atomic plant and to decommission that facility. The Company had relied on Yankee Atomic for less than one percent of the Company's system capacity. Its 9.5-percent equity investment in Yankee Atomic is approximately $2.3 million. Currently, purchased-power costs billed to the Company, which include the estimated cost of the ultimate decommissioning of the unit, are collected by the Company from its customers through the Company's base-rate structure. On March 18, 1993, the FERC approved a settlement agreement regarding the 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 $32.8 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 recent base-rate case, the Company's share of costs related to the deactivation of Yankee Atomic is being recovered through rates based on the most recent projections of costs. The Company's share of the capacity of the four operating nuclear generating plants amounted to the following: Maine Yankee . . . . 330 MW Connecticut Yankee . . 35 MW Vermont Yankee . . . 21 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 a 25-year interconnection agreement. MEPCO transmits power between NB Power and various New England utilities under separate agreements. In 1990 MEPCO transferred to a newly formed partnership, of which a subsidiary of the Company is a 50-percent general partner, approximately $29 million of construction work in progress and an equal amount of deferred credits related to the construction of certain static var compensator facilities used for stabilization purposes in connection with the NEPOOL Hydro-Quebec purchase discussed in the succeeding paragraph. 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 -17- 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 $33.2 million, its share of the construction cost for the transmission facilities incurred through December 31, 1993. Maine Yankee Decommissioning. Effective in 1988 Maine Yankee began collecting $9.1 million annually for decommissioning based on a FERC-approved funding level of $167 million. In January 1994, Maine Yankee filed a notice of tariff change with the FERC to increase its annual collection to $14.9 million and to reduce its return on common equity to 10.65 percent, for a total net 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 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. Maine Yankee's accumulated decommissioning funds were $93.8 million as of December 31, 1993. 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. The Waste Act also set limits on the volume of waste each disposal facility must accept from each state, established milestones for the nonsited states to establish facilities within their states or regions (pursuant to regional compacts) and authorized increasing surcharges on waste disposal until 1992. After 1992 the states in which there are operating disposal sites are permitted to refuse to accept waste generated outside their states or compact regions. In 1987 the Maine Legislature created the Maine Low-Level Radioactive Waste Authority (the "Maine Authority") to provide for such a facility if Maine is unable to secure continued access to out-of-state facilities after 1992, and the Maine Authority engaged in a search for a qualified disposal site in Maine. Maine Yankee volunteered its site at the Plant for that purpose, but progress toward establishing a definitive site in Maine, as in other states, was difficult because of the complex technical nature of the search process and the political sensitivities associated with it. As a result, Maine did not satisfy its milestone obligation under the Waste Act requiring submission of a site license application by the end of 1991, and is therefore subject to surcharges on its waste and has not had access to regulated disposal facilities since the end of 1992. Thus, Maine Yankee now stores all waste generated at an on-site storage facility. At the same time, the State of Maine was pursuing discussions with the State of Texas concerning participation in a compact with that state and Vermont. In May 1993, the Texas Legislature approved a compact with the states of Maine and Vermont. The Maine Legislature in June 1993 ratified the compact and submitted it to ratification by Maine voters in a referendum held on November 2, 1993, in which the compact was ratified by a margin of approximately 73% to 27%. It must now be presented to the United States Congress for final ratification. -18- 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 Maine Yankee 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. Pending the ratification votes, the Maine Authority suspended its search for a suitable disposal site in Maine. In the event the required ratification by Congress is not obtained, subject to continued NRC approval, Maine Yankee can continue to utilize its capacity to store approximately ten to twelve years' production of low-level waste in its facility at the Maine Yankee Plant site, which it started in January 1993. 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 licensed operating life of the Maine Yankee Plant. On January 26, 1993, the NRC published for public comment a proposed rulemaking that, if adopted, would require a licensee such as Maine Yankee, as a condition of its license, to document that it had exhausted other reasonable waste management options in order to be permitted to store low-level waste on-site beyond January 1, 1996. Such options include taking all reasonable steps to contract, either directly or through the state, for disposal of the low-level waste. On February 9, 1994, the NRC, after affirming its preference for disposal of waste over storage, announced its decision to withdraw the proposed rulemaking. Maine Yankee has informed the Company that it expects the NRC to issue its formal notice of withdrawal in the spring of 1994. 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 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 $75.5 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 plant, the Company's retrospective premium could be as high as $6 million in any year, for a cumulative total of $45.3 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. -19- 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 mutual 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 $6.3 million annually. For a discussion of issues relating to Maine Yankee's spent nuclear fuel disposal, see "Fuel Supply" - "Nuclear", below. Non-utility Generation In the Public Utility Regulatory Policies Act of 1978 ("PURPA") the United States Congress provided substantial economic incentives to non-utility power producers by allowing cogenerators and small power producers to sell their entire electrical output to an electric utility at the utility's avoided-cost rate and purchase their entire electric energy requirement at the utility's established rate for that customer class. The Maine Legislature enacted a companion measure in 1979. The Company has entered into a number of long-term, noncancellable contracts for the purchase of capacity and energy from non-utility generators. The agreements generally have terms of five to 30 years and require the Company to purchase the energy at specified prices per kilowatt-hour. As of December 31, 1993, facilities having 596 megawatts of capacity covered by these contracts were in service, and another 15 megawatts is expected to be added by the end of 1994. The costs of purchases under all of these contracts amounted to $360.7 million in 1993, $341.5 million in 1992 and $332.4 million in 1991. Such costs are recoverable through the Company's fuel clause, after review and approval by the PUC. In connection with the Company's 1992 fuel cost adjustment proceeding, the MPUC announced it would review the prudence of administration and management of these contracts, as well as the terms and conditions of recent contracts. For a discussion of an imprudence finding by the MPUC in connection with its review, see Item 1, "Business", "Regulation and Rates" - "MPUC NUG Contracts Investigation", above. In an effort to control the price pressure related to purchases from non-utility generators, the Company negotiated long term contract buy-outs or restructuring with three non-utility generators in 1992, four in 1993, eleven in early 1994, and continues to renegotiate other contracts. The Company incurred buy-out costs of approximately $11.4 million in 1993 and $19 million in 1992. The 1994 renegotiation of prices and contract terms did not require cash payments. Total buy-outs, restructuring, and terminations made to date are expected to save the Company's customers more than $170 million in fuel costs during the next five years. Construction Program -20- 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 1994 capital investment outlays, including deferred demand-side management expenditures, to a level below that of 1993. During the five-year period ended December 31, 1993, the Company's construction and acquisition expenditures amounted to $425.1 million (including investment in jointly-owned projects and excluding MEPCO), including an Allowance for Funds Used During Construction ("AFC") of $13.6 million. The program is currently estimated at approximately $60 million for 1994 and $256 million for 1995 through 1998, including AFC estimated for the period 1994 through 1998 at $3 million, and including an estimated $35 million for conservation and energy management programs for the 1994 through 1998 period. The following table sets forth the Company's estimated capital expenditures as discussed above: 1994 1995-98 1994-98 Type of Facilities (Dollars in Millions) Generating Projects $11 $ 48 $ 59 Transmission 7 28 35 Distribution 23 100 123 General 12 52 64 Energy Management 7 28 35 Total $60 $256 $316
Demand-side Management The Company's demand-side-management efforts 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. Under the Company's "Power Partners" program, customers or energy service companies may submit energy management project bids in response to requests for proposals issued by the Company for specific blocks of power. Power Partners was the first program in the United States to allow energy management proposals to compete on an equal basis with cogeneration and small power production facilities in a bidding process for capacity and energy. The Company anticipates incurring expenses of approximately $17.5 million in 1994 in connection with conservation and -21- load-management programs and expects the costs of all of these programs to be recoverable through rates. Actual 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 NEPOOL, which is open to all investor-owned, municipal and cooperative electric utilities in New England under an agreement in effect since 1971 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. Fuel Supply The Company's total kilowatt-hour production by energy source for each of the last two years and as estimated for 1994 is shown below: Actual Estimated Source 1992 1993 1994 Nuclear (principally from 26% 28% 27% Maine Yankee) Hydro 15 14 17 Oil 19 16 12 Non-utility 38 40 44 Other purchases 2 2 0 100% 100% 100%
The 1994 estimated kilowatt-hour output from oil and purchased power may vary depending upon the relative costs of Company-generated power and power purchased through NEPOOL and independent producers. Oil. The Company's William F. Wyman Station in Yarmouth, Maine, and its internal combustion electric generating units are oil-fired. A one-year contract for the supply of the Company's fuel oil requirements at market prices expired on June 30, 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 1989 was $17.07, $17.33, $12.87, $14.02 and $13.12, 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 -22- 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 has assumed 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 $53.1 million of interest cost for the period April 7, 1983, through December 31, 1993. 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 $0.6 million through December 1997. Deposits are expected to total approximately $62.8 million, with the total liability, including interest due at the time of disposal, estimated to be approximately $115.9 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, on January 25, 1993, filed with the NRC seeking authorization to implement the plan. On March 15, 1994, the NRC granted the authorization. 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. -23- 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 provides for the possible development of a Monitored Retrievable Storage ("MRS") facility and abandons 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. 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. LEGAL PROCEEDINGS. Material proceedings before the Maine PUC involving the Company are discussed above in Item 1, Business. 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 EPA as containing soil contaminated by polychlorinated biphenyls (PCBs) from equipment originally owned by the Company. In 1990, the Company and the EPA signed a negotiated consent agreement, which was entered as an order by the United States District Court for the District of Maine in 1991. The agreement provides for studies, development of work plans, additional EPA review, and eventual cleanup of the site by the Company over a period of years, using the method and level of cleanup selected by the EPA. The Company has been investigating other courses of action that might result in lower costs and, in March 1992, acquired title to the site to pursue the possibility of developing it in a manner that would not require the same method and level of cleanup currently provided in the agreement. The Company also initiated a lawsuit against the original owners of the site and Westinghouse Electric Corp. (Westinghouse), which arranged for the equipment disposal, seeking contributions toward past and future cleanup costs. On November 8, 1993, the United States District Court for the District of Maine rendered its decision in the suit, holding that Westinghouse was responsible for 41 percent of the necessary past and future cleanup costs and the former owners 12.5 percent, other than a small amount (less than -24- 5 percent) of such costs not attributable to PCBs, for which Westinghouse was held not responsible and the former owners were held responsible for 33 percent. The Court further concluded that the Company had incurred approximately $3.3 million to that point in costs subject to sharing among the parties. At the same time, the Company has been actively pursuing recovery of its costs through its insurance carriers and has reached agreement with one for recovering a portion of those costs. It has also filed lawsuits seeking such recovery from other carriers. In August 1991, the Company requested permission from the MPUC to defer its cleanup-related costs, with accrued carrying costs, on the basis that such costs are allowable costs of service and should be recoverable in rates. In August 1992, the MPUC issued an order authorizing the Company to defer direct costs associated with the site incurred after August 9, 1991, with accrued carrying costs. Such costs incurred prior to the request were charged to a $3-million reserve established in 1985. Initial tests on the site have been completed and more complex technological studies are still in progress. Based on results to date and on the most likely cleanup method, the Company believes that its remaining costs of the cleanup will total between $7 million and $11 million, depending on the level of cleanup ultimately required and other variable factors. Such estimate is net of the agreed insurance recovery and considers any contributions from Westinghouse and the former owners, but excludes contributions from the insurance carriers the Company has sued, or any other third parties. As a result, in the fourth quarter of 1993, the Company decreased the liability recorded on its books from $14 million, the estimated liability prior to the November 1993 court ruling, to $7 million and recorded an equal reduction in a regulatory asset established to reflect the anticipated ratemaking recovery of such costs when ultimately paid. Approximately $1 million of costs incurred to date has been charged against the liability. The Company cannot predict the level and timing of the cleanup costs, the extent to which 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. Power Purchase Contract Suit. As previously reported, the Company and Caithness King of Maine Limited Partnership ("Caithness") engaged in a lawsuit in the United States District Court for the District of Maine over the Company's termination of a contract for the purchase of approximately 80 megawatts of electric power from a cogeneration project proposed for construction by Caithness at the Topsham, Maine. In the suit Caithness denied the validity of the termination and sought damages estimated by Caithness to be in excess of $100 million for breach of contract or, in the alternative, reformation of the contract, and other legal relief. Also as previously reported, on January 14, 1994, the -25- Company and Caithness entered into a Termination and Settlement Agreement under which the Company paid Caithness a total of $5 million, and the parties agreed to the termination of the power- purchase contract and to dismiss the suit and counterclaims. The contract would have required payments by the Company over the life of the contract that were projected to be significantly higher than the Company's estimated avoided costs and was therefore inconsistent with the Company's program of pursuing terminations or other restructurings of high-cost power-purchase contracts. 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 Carlton D. Reed, Jr., 63, 1991 Chairman of the Board of Directors Matthew Hunter, 59, 1978 Chairman of the Company, and Director David T. Flanagan, 46, 1984 President and Chief Executive Officer, and Director Arthur W. Adelberg, 42, 1985 Vice President, Law and Power Supply Richard A. Crabtree, 47, 1978 Vice President, Retail Operations David E. Marsh, 46, 1986 Vice President, Corporate Services, and Chief Financial Officer Curtis A. Mildner, 40, 1994 Vice President, Marketing Gerald C. Poulin, 52, 1984 Vice President, Production and Support Douglas Stevenson, 45, 1984 Treasurer Robert S. Howe, 54, 1975 Comptroller -26- William M. Finn, 57, 1984 Secretary and Clerk
Each of the executive officers, except Mr. Mildner, has for the past five years been an officer or employee of the Company. Curtis A. 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. Mr. Hunter has announced that he plans to retire effective May 1, 1994. -27- PART II 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 March 21, 1994, there were 35,146 holders of record of the Company's common stock. Price Range of and Dividends on Common Stock Market Price Dividends High Low Declared 1993 First Quarter $24 1/2 $21 3/4 $ .39 Second Quarter 24 3/8 21 .39 Third Quarter 24 21 7/8 .39 Fourth Quarter 22 1/4 14 3/8 .225 1992 First Quarter $22 7/8 $19 7/8 $ .39 Second Quarter 22 7/8 20 .39 Third Quarter 23 3/4 22 1/8 .39 Fourth Quarter 23 7/8 22 1/8 .39
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, 1993, $87.5 million of retained earnings 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. SELECTED FINANCIAL DATA. The following table sets forth selected consolidated financial data of the Company for the five years ended December 31, 1989 through 1993. This information should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the financial statements and related notes thereto included elsewhere herein. The selected consolidated financial data for the years ended December 31, 1989 through 1993 are derived from the audited financial statements of the Company. -28- Selected Consolidated Financial Data (Dollars in Thousands, Except Per Share Amounts) 1993 1992 1991 1990 1989 Electric operating revenues $ 893,577 $ 877,695$ 866,539 $ 780,821 $ 727,196 Net income 61,302 63,583 59,134 48,795 48,574 Long-term obligations 581,844 499,029 518,625 495,716 430,544 Redeemable preferred stock 80,000 40,750 43,500 44,875 11,250 Total assets 2,004,862 1,690,005 1,574,501 1,456,072 1,324,218 Earnings per common share $ 1.65 $1.85 $1.82 $1.68 $1.92 Dividends declared per common share $1.395 $1.56 $1.56 $1.56 $1.53
-29- Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. The information required to be furnished in response to this Item is submitted as pages 1 to 15 of Exhibit 13-1 hereto (the Company's Annual Report to Shareholders for the year ended December 31, 1993), which pages are hereby incorporated herein by reference. Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. The information required to be furnished in response to this Item is submitted as pages 15 through 48 of Exhibit 13-1 hereto (the Company's Annual Report to Shareholders for the year ended December 31, 1993), which pages are hereby incorporated herein by reference. For ease of reference, the following is a listing of financial information incorporated by reference to Exhibit 13-1 hereto, which shows the page number or numbers of said Exhibit on which such information is presented. Financial Information Page(s) of Exhibit 13-1 Report of independent public accountants 47 Management report on responsibility for financial reporting 48 Consolidated statement of earnings for the three years ended December 31, 1993, 1992 and 1991 15-17 Consolidated balance sheet as of December 31, 1993 and 1992 18-20 Consolidated statement of cash flows for the three years ended December 31, 1993, 1992 and 1991 17-18 Consolidated statement of capitalization and interim financing as of December 31, 1993 and 1992 20-21 Consolidated statement of changes in common stock investment for the three years ended December 31, 1993, 1992 and 1991 21-23 Notes to consolidated financial statements 23-46 Supplementary quarterly financial data (unaudited) 45-46
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. The information required to be furnished in response to this Item is submitted on page 49 of Exhibit 13-1 hereto (the Company's Annual Report to Shareholders for the year ended December 31, 1993), which page is hereby incorporated by -30- reference. PART III 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 25, 1994, and Item 4.1, Executive Officers of the Registrant, above, both of which are hereby incorporated herein by reference. 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 25, 1994, which is hereby incorporated herein by reference. 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 25, 1994, which is hereby incorporated herein by reference. 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 28, 1994, which is hereby incorporated herein by reference. PART IV Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K. (a) Listing of Exhibits. The exhibits which are filed with this Form 10-K or are incorporated herein by reference are set forth in the Exhibit Index, which immediately precedes the exhibits to this report. (b) Reports on Form 8-K. The Company filed the following reports on Form 8-K during the last quarter of 1993 and thereafter to date: Date of Report Items Reported October 27, 1993 Item 5 Lowering of debt and preferred stock ratings. On October 27, 1993, Duff & Phelps Credit Rating Co. announced that it was lowering the ratings of the Company's debt and preferred stock. Date of Report Items Reported -31- October 28, 1993 Item 5 (a) Debt and preferred stock ratings. On October 29, 1993, Moody's Investors Service ("Moody's") lowered the ratings on the Company's long-term debt and preferred stock, citing concerns about the Company's "ability to safeguard its competitive position and to gain the regulatory support needed to avoid further pressure on cash flow and debt-protection measurements". (b) Base-rate case. The Company reported on positions taken by certain parties in the Company's base-rate case before the PUC. (c) PUC order on independent power producer contracts. On October 28, 1993, the PUC issued its written order incorporating the conclusions of its October 5, 1993, deliberations. Date of Report Items Reported November 30, 1993 Item 5 Public Utilities Commission order in base-rate case and securities downgrading. On November 30, 1993, the MPUC issued its basic revenue requirements order finding the Company entitled to an annual revenue increase of $26.2 million in the Company's $83 million base-rate case. On December 1, 1993, Standard & Poor's Corp. ("S&P") further lowered its ratings of the Company's securities. Date of Report Items Reported December 15, 1993 Item 5 Common stock dividend reduction. On December 15, 1993, the Company's Board of Directors reduced the quarterly dividend on the Company's common stock from 39 cents to 22.5 cents per share. Date of Report Items Reported December 16, 1993 Item 5 (a) On December 16, 1993, the Company announced that David T. Flanagan had been elected President, Chief Executive Officer and a director, effective January 1, 1994, succeeding Matthew Hunter, who planned to retire May 1, 1994. (b) The Company reported that effective December 27, 1993, the Company's 450,000 shares of outstanding Flexible Money Market Preferred Stock, Series A, would no longer be subject to the restriction that it be conveyed only in Units of 1,000 shares. (c) On December 20, 1993, the Chief Justice of the Maine Supreme Judicial Court issued an order temporarily staying the .5% return-on-equity penalty that had been imposed on the Company by the MPUC on October 28, 1993, in its independent power producer contracts investigation. -32- Date of Report Items Reported January 5, 1994 Item 5 On January 5, 1994, S&P further lowered its ratings on the Company's securities, including the senior secured debt rating to "BB+" from BBB-". Date of Report Items Reported January 13, 1994 Items 4 and 5 Item 4. On January 19, 1994, the Company's Board of Directors voted to engage Coopers & Lybrand as the Company's principal accountants in 1994. The Item also contained information on a disagreement in 1991 with the Company's predecessor accountants. (This item amended by Form 8-K/A, Amendment No. 1, also dated January 13, 1994. Item 5. (a) On January 13, 1994, Moody's lowered its ratings on the Company's preferred stock and commercial paper, while confirming its rating on the Company's General and Refunding Mortgage Bonds at "Baa2". (b) On January 14, 1994, the Company and Caithness King of Maine Limited Partnership entered into a Termination and Settlement Agreement terminating power-contract litigation. Date of Report (Form 8-K/A) Items Reported January 13, 1994 Item 4 The Company amended its January 13, 1994, Form 8-K to provide further information on its change of principal accountants and a 1991 disagreement with the Company's predecessor accountants. Date of Report Items Reported February 3, 1994 Item 5 On February 4, 1993, the Chief Justice of the Maine Supreme Judicial Court denied the MPUC's motion to dismiss the Company's approval of the MPUC's October 28, 1993, return-on-equity penalty. The MPUC had contended that it had reconsidered its order imposing the penalty and was considering alternative remedies. -33- 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 30th day of March, 1994. CENTRAL MAINE POWER COMPANY By David E. Marsh Vice President, Corporate Services and Chief Financial Officer -34- 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. Signature Title Date ________________________ President and March 30, 1994 David T. Flanagan Chief Executive (Principal Executive Officer; Director Officer) _________________________ Vice President, March 30, 1994 David E. Marsh Corporate Services, (Principal Financial and Chief Financial Officer) Officer _________________________ Comptroller March 30, 1994 Robert S. Howe (Principal Accounting Officer) _________________________ Chairman of the March 30, 1994 Carlton D. Reed, Jr. Board of Directors _________________________ Chairman of the March 30, 1994 Matthew Hunter Company; Director _________________________ Director March 30, 1994 Charles H. Abbott _________________________ Director March 30, 1994 Charleen M. Chase _________________________ Director March 30, 1994 E. James Dufour _________________________ Director March 30, 1994 Robert H. Gardiner _________________________ Director March 30, 1994 David M. Jagger _________________________ Director March 30, 1994 Charles E. Monty _________________________ Director March 30, 1994 Robert H. Reny _________________________ Director March 30, 1994 Anne Szostak _________________________ Director March 30, 1994 Kathryn M. Weare
-35- The following report and consent and financial schedules of Central Maine Power Company are filed herewith and included in response to Item 14(d). Page Report of independent public accountants F-2 Consent of independent public accountants F-3 Schedule V - Consolidated Property, Plant and Equipment F-4 to F-6 Schedule VI - Consolidated Reserves for Depreciation of Property and Amortization of Nuclear Fuel F-7 to F-9 Schedule VIII - Valuation and Qualifying Accounts F-10 to F-12 Schedule IX - Consolidated Short-Term Borrowings F-13
Any and all other schedules are omitted because the required information is inapplicable or the information is presented in the financial statements or related notes. -36- REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Board of Directors of Central Maine Power Company: We have audited, in accordance with generally accepted auditing standards, the consolidated financial statements included in Central Maine Power Company's annual report to shareholders incorporated by reference in this Form 10-K, and have issued our report thereon dated February 4, 1994. Our audits were made for the purpose of forming an opinion on those statements taken as a whole. The schedules listed on the accompanying index of schedules included in reports to Item 14(a) in Form 10-K are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic financial statements. These schedules have been subjected to the auditing procedures applied in the audit of the basic financial statements and, in our opinion, fairly state, in all material respects, the financial data required to be set forth therein in relation to the basic financial statements taken as a whole. ARTHUR ANDERSEN & CO. Boston, Massachusetts February 4, 1994 -37- CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation of our reports included and incorporated by references in this Form 10-K, into the Company's previously filed Registration Statements File No. 33-44944, File No. 33-44754, File No. 33-51611, File No. 33-39826 and File No. 33-36679. ARTHUR ANDERSEN & CO. Boston, Massachusetts, March 28, 1994 -38- Central Maine Power Company CONSOLIDATED PROPERTY, PLANT AND EQUIPMENT (H) For the Year Ended December 31, 1993 (Dollars in Thousands) Balance at Other Changes Balance at Beginning Additions Retirements Miscellaneous End Classification Classification of Period at Cost or Sale Adjustments of Period Electric Property (A) (B)&(I) Intangible Property $ 4,767 $ 2,799 $ 0 $ 0 $ 7,566 Generating Plant-Steam 202,367 703 (290) 594 203,374 Generating Plant-Hydro 197,486 5,995 (95) (12)(C) 203,374 Generating Plant-Internal Combustion 4,080 1 0 0 4,081 Generating Plant-Nuclear 97,750 381 0 0 98,131 Transmission 270,948 6,353 (1,195) (2,590)(D) 273,516 Distribution 600,297 29,194 (9,503) 196 620,184 Other Property and Equipment 139,250 22,367 (5,698) (1,270)(E) 154,649 Electric Plant Acquisition Adjustment 0 0 0 0 Total Electric Property in Service 1,516,945 67,793 (16,781) (3,082) 1,564,875 Unfinished Construction 34,550 (14,558) 0 (303) 19,689 Total Electric Property 1,551,495 53,235 (16,781) (3,385) 1,584,564 Nuclear Fuel (F) 8,443 621 0 0 9,064 Miscellaneous Properties (G) 3,898 112 (144) 1,086 4,952 Total Property, Plant and Equipment $1,563,836 $53,968 $(16,925) $(2,299) $1,598,580 Notes: (A) Includes Operating Property and Property Held for Future Use land retirements/sales of $9. (B) Transfers (to)/from various classifications contained on this page. (C) Includes the writedown of Hydro land and water rights. (D) Includes annual reductions of ($1,610) for Transmission Facilities under Capital Leases. (E) Includes annual reductions for 1) General Facilities under Capital Leases of ($995) and 2) a long term asset associated with the General Office Settlement of ($79). (F) Includes Nuclear Fuel in Processing, in Stock, in Reactor, and Spent Fuel. (G) Included in Deferred Charges and Other Assets on Balance Sheet. Report for depreciation policies. (H) Refer to Note 1 of Notes to Consolidated Financial Statements in the 1993 Annual Report for depreciation policies. (I) As a result of the Company's adoption of FAS 109, property classifications were adjusted as follows: (Steam) $570; (Hydro) $5; (Transmission) $136; (Distribution) $38; and (General) $52. F-4 -39- Central Maine Power Company CONSOLIDATED PROPERTY, PLANT AND EQUIPMENT (H) For the Year Ended December 31, 1992 (Dollars in Th Balance at Other Changes Balance at Beginning Additions Retirements Miscellaneous End Classification of Period at Cost or Sale Adjustments of Period Electric Property (A) (B) Intangible Property $ 4,388 $ 379 $ 0 $ 0 $ 4,767 Generating Plant-Steam 200,409 3,324 (1,380) 14 202,367 Generating Plant-Hydro 191,855 5,909 (314) 36 (C) 197,486 Generating Plant-Internal Combustion 4,080 0 0 0 4,080 Generating Plant-Nuclear 97,555 195 0 0 97,750 Transmission 263,137 10,974 (1,807) (1,356)(D) 270,948 Distribution 575,994 32,986 (8,478) (205) 600,297 Other Property and Equipment 133,649 10,616 (4,587) (428)(E) 139,250 Electric Plant Acquisition Adjustment 226 0 (226) 0 Total Electric Property in Service 1,471,293 64,383 (16,792) (1,939) 1,516,945 Unfinished Construction 26,383 8,180 0 (13) 34,550 Total Electric Property 1,497,676 72,563 (16,792) (1,952) 1,551,495 Nuclear Fuel (F) 7,975 468 0 0 8,443 Miscellaneous Properties (G) 3,806 7 (10) 95 3,898 Total Property, Plant and Equipment $1,509,457 $73,038 $(16,802) $(1,857) $1,563,836 Notes: (A) Includes Operating Property and Property Held for Future Use land retirements/sales of $43. (B) Transfers (to)/from various classifications contained on this page. (C) Includes the writedown of Hydro land and water rights. (D) Includes annual reductions of ($1,579) for Transmission Facilities under Capital Leases. (E) Includes annual reductions for 1) General Facilities under Capital Leases of ($925) and 2) a long term asset associated with the General Office Settlement of ($79) and to record the investment of purchased vehicles formerly leased $659. (F) Includes Nuclear Fuel in Processing, in Stock, in Reactor, and Spent Fuel. (G) Included in Deferred Charges and Other Assets on Balance Sheet. (H) Refer to Note 1 of Notes to Consolidated Financial Statements in the 1992 Annual Report for depreciation policies. F-5 -40- Central Maine Power Company CONSOLIDATED PROPERTY, PLANT AND EQUIPMENT (A) For the Year Ended December 31, 1991 (Dollars in Thousands) Balance at Other Changes Balance at Beginning Additions Retirements Miscellaneous End Classification of Period at Cost or Sale Adjustments of Period Electric Property (B) (C) Intangible Property $ 2,327 $ 2,054 $ 0 $ 7 $ 4,388 Generating Plant-Steam 193,708 7,446 (466) (279) 200,409 Generating Plant-Hydro 191,627 1,673 (681) (764)(D) 191,855 Generating Plant-Internal Combustion 4,079 0 0 1 4,080 Generating Plant-Nuclear 97,445 110 0 0 97,555 Transmission 257,529 7,413 (939) (866)(E) 263,137 Distribution 546,746 37,043 (7,836) 41 575,994 Other Property and Equipment 123,570 16,686(F) (4,801) (1,806)(G) 133,649 Electric Plant Acquisition Adjustment 226 0 0 0 2 Total Electric Property in Service 1,417,257 72,425 (14,723) (3,666) 1,471,293 Unfinished Construction 19,410 6,903 0 70 26,383 Total Electric Property 1,436,667 79,328 (14,723) (3,596) 1,497,676 Nuclear Fuel (H) 7,877 99 0 0 7,976 Miscellaneous Properties (I) 2,682 186 (387) 1,324 3,805 Total Property, Plant and Equipment $1,447,226 $79,613 $(15,110) $(2,272) $1,509,457 Notes: (A) Refer to Note 1 of Notes to Consolidated Financial Statements in the 1992 Annual Report for depreciation policies. (B) Includes Operating Property and Property Held for Future Use land retirements/sales of $19. (C) Transfers (to)/from various classifications contained on this page. (D) Includes the transfer of Columbia and Lincoln Hydro stations to Deferred Charges and Other Assets of ($739) and the writedown of Hydro land and water rights. (E) Includes annual reductions of ($566) for Transmission Facilities under Capital Leases. (F) Includes an addition of Property under Capital Leases for mainframe computer equipment of $4,167. (G) Includes annual reductions for 1) General Facilities under Capital Leases of ($861) and 2) a long term asset associated with the General Office Settlement of ($79). (H) Includes Nuclear Fuel in Processing, in Stock, in Reactor, and Spent Fuel. (I) Included in Deferred Charge
F-6 -41- Central Maine Power Company CONSOLIDATED RESERVES FOR DEPRECIATION OF PROPERTY AND AMORTIZATION For the Year Ended December 31, 1993 (Dollars in Thousands) Additions to Reserves Deductions from Reserves Balance Retirements, Ch at Charged to Renewals and Balance Beginning Profit and Charged to Other Accounts Replace- Other at Close of Period Loss Description Amount ments Description Amount of Period (A) Electric $474,036 $42,008 $16,772 $ Salvage of Cost of Retired Materials Removing and Equipment $2,488 Retired Plant $2,483 Auto Adjust Reserve- Depreciation/ Assets Amortization Transferred to Charged to Nonoperat- Clearing Accounts 2,996 ing 84 Adjust Reserve- Millstone Unit No. III Decommissioning Trust Fund (A/C 128) 1,091 474,036 42,008 6,575 16,772 2,567 503,280 Nuclear Fuel 6,544 698 7,242 Miscel- Adjust Reserve- laneous Assets Propert- Transferred from ies Operating (B) 410 45 Property 84 3 536 $480,990 $42,751 $6,659 $16,775 $2,567 $511,058 Notes: (A) Retirements are made at original cost. (B) Included in Deferred Charges and Other Assets on Balance Sheet.
F-7 -42- Central Maine Power Company CONSOLIDATED RESERVES FOR DEPRECIATION OF PROPERTY AND AMORTIZATION OF NUCLEAR FUEL For the Year Ended December 31, 1992 (Dollars in Thousands) Additions to Reserves Deductions from Reserves Balance Retirements, Charg at Charged to Charged to Other Accounts Renewals and Other Balance Beginning Profit and Replace- at Close of Period Loss Description Amount ments Description Amount of Period (A) Electric $447,276 $40,321 $16,749 $ Salvage of Cost of Retired Materials Removing and Equipment $2,151 Retired Plant $2,820 Auto Adjust Reserve- Depreciation/ Assets Amortization Transferred to Charged to Nonoperat- Clearing Accounts 3,183 ing 2 Adjust Reserve- Loss on Disposal of Property 12 Assets Transferred to Donations 5 Investment of purchased vehicles formerly leased 659 447,276 40,321 6,010 16,749 2,822 474,036 Nuclear Fuel 5,798 746 6,544 Miscel- Adjust Reserve- laneous Assets Proper- Transferred from ties Operating (B) 371 37 Property 2 410 $453,445 $41,104 $6,012 $16,749 $2,822 $480,990 Notes: (A) Retirements are made at original cost. (B) Included in Deferred Charges and Other Assets on Balance Sheet.
F-8 -43- Central Maine Power Company CONSOLIDATED RESERVES FOR DEPRECIATION OF PROPERTY AND AMORTIZATION OF NUCLEAR FUEL For the Year Ended December 31, 1991 (Dollars in Thousands) Additions to Reserves Deductions from Reserves Balance Retirements, at Charged to Charged to Other Accounts Renewals and Other Balance Beginning Profit and Replace- at Close of Period Loss Description Amount ments Description Amount of Period (A) Electric $421,840 $39,000 $14,704 $ Salvage of Cost of Retired Materials Removing and Equipment $2,314 Retired Plant $4,015 Auto Adjust Reserve- Depreciation/ Assets Amortization Transferred to Charged to Nonoperating Clearing Accounts 3,123 (A/C 122) 369 Adjust Reserve- Deferred Debits (A/C 186) 107(B) Assets Donations Transferred to (A/C Deferred Debits 426.1) (A/C 186) 195(B) 1 421,840 39,000 5,632 14,704 4,492 447,276 Nuclear Fuel 5,480 318 5,798 Miscel- Adjust Reserve- laneous Assets Proper- Transferred from Sale of ties Operating Nonoperating (C) 174 15 Property 369 Property 187 371 $427,494 $39,333 $6,001 $14,704 $4,679 $453,445 Notes: (A) Retirements are made at original cost. (B) To be recovered effective January 1, 1991 in accordance with the Maine Public Utilities Commission rate order in Docket No. 89-68. (C) Included in Deferred Charges and Other Assets on Balance Sheet.
F-9 -44- Central Maine Power Company VALUATION AND QUALIFYING ACCOUNTS For the Year Ended December 31, 1993 (Dollars in Thousands) Additions Charged to Balance at Charged to other Balance at beginning costs and accounts- Deductions- end of Description of period expenses describe describe period Reserves deducted from assets to which they apply: Reserve for uncollectible accounts $ 2,250 $5,548 $ $ 5,094(A) $ 2,704 Reserves not applied against assets: Reserve for casualty and insurance $ 1,077 $1,123 $ 272(B) $ 1,397(C) $ 1,075 Reserve for workers' compensation 6,400 6,400 Reserve for hazardous material clean-up 2,981 5,019(D) 1,172(E) 6,828 Reserve for Millstone III sales tax 423 423(F) Reserve for obsolete inventory 250 250(G) Reserve for revenue adjustment of tax flowback 9,990 9,990(H) Total $21,121 $1,123 $5,291 $13,232 $14,303 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. (F) Amounts reversed, charged to nuclear operating expenses. (G) Amounts charged off as Distribution Expense. (H) Refer to Note 3 of Notes to Consolidated Financial Statements in the 1993 Annual Report.
F-10 -45- Central Maine Power Company VALUATION AND QUALIFYING ACCOUNTS For the Year Ended December 31, 1992 (Dollars in Thousands) Additions Charged to Balance Balance at Charged to other at end beginning costs and accounts- Deductions- of Description of period expenses describe describe period Reserves deducted from assets to which they apply: Reserve for uncollectible accounts $ 2,336 $ 5,576 $ $5,662(A) $ 2,250 Reserves not applied against assets: Reserve for casualty and insurance $ 1,075 $ 1,524 $393(B) $1,915(C) $ 1,077 Reserve for workers' compensation 6,400 6,400 Reserve for hazardous material clean-up 4,500 1,519(D) 2,981 Reserve for Millstone III sales tax 487 46 110(E) 423 Reserve for rate refund 4,500 4,500(F) Reserve for obsolete inventory 250 250 Reserve for revenue adjustment of tax flowback 9,990 9,990 Total $16,962 $11,810 $393 $8,044 $21,121 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 paid, charged against the reserve net of estimated insurance recoveries. (E) Amounts paid to Northeast Utilities related to Millstone Unit 3 Sales and Use Tax settlement agreement dated June 12, 1992. (F) Amount of refund paid per Federal Energy Regulatory Commission stipulation of $2,076 and reversal of prior year reserve accrual of $2,424.
F-11 -46- Central Maine Power Company VALUATION AND QUALIFYING ACCOUNTS For the Year Ended December 31, 1991 (Dollars in Thousands) Additions Charged Charged to Balance Balance at to costs other at end beginning and accounts- Deductions- of Description of period expenses describe describe period Reserves deducted from assets to which they apply: Reserve for uncollectible accounts $ 1,259 $5,690 $ $4,613(C) $ 2,336 Reserves not applied against assets: Reserve for casualty and insurance $ 1,075 $1,520 $ 392(D) $1,912(E) $ 1,075 Reserve for workers' compensation 4,750 1,650(G) 6,400 Reserve for hazardous material clean-up 3,000 (912)(B) 4,500(A) 2,088(B) 4,500 Reserve for Millstone III sales tax 359 128 487 Reserve for wheeling 1,600 111 1,711(F) Reserve for rate refund 4,500 4,500 Total $10,784 $5,347 $6,542 $5,711 $16,962 Notes: (A) Amounts deferred, net of anticipated insurance recovery, in anticipation of future rate treatment. (B) Amounts previously charged to Account 186, Deferred Charges and Other Assets were charged against the reserve and the remaining balance ($912) was credited to expense. (C) Amounts charged off as uncollectible after deducting customers' deposits and recoveries of accounts previously charged off. (D) Amounts charged to capital accounts. (E) Principally payments for various injuries and damages and expenses in connection therewith. (F) Payment of contract settlement. (G) Charged to Account 186, Deferred Charges and Other Assets.
F-12 -47- CENTRAL MAINE POWER COMPANY CONSOLIDATED SHORT-TERM BORROWINGS For the Years Ended December 31, (Dollars in Thousands) Weighted Maximum amount Average amount Weighted average Balance at end average outstanding outstanding interest rate Category of aggregate short- of interest during the during the during the term borrowings (A) period rate (B) period (C) period period 1993 Commercial paper $15,500 3.74% $105,940 $39,623(D) 3.54%(E) Notes payable to banks 10,000 3.70 29,000 18,492(D) 3.86 (E) 1992 Commercial paper 61,000 3.76 65,400 46,932(D) 3.99 (E) Notes payable to banks 27,500 4.11 43,500 28,589(D) 4.63 (E) Medium-term notes - - 7,500 3,340(D) 6.98 (E) 1991 Commercial paper 38,500 5.77 38,500 24,614(D) 6.30 (E) Notes payable to banks 45,000 5.61 45,000 12,734(D) 6.03 (E) Medium-term notes (G) 7,500 7.79 27,500 18,035 8.01 (F) Notes: (A) Refer to Note 7 of Notes to Consolidated Financial Statements for general terms of short- term borrowing. (B) At end of period. (C) Maximum amount outstanding at any month end for each category. (D) Average daily balance of net proceeds during the period. (E) Based on the daily amount of net proceeds outstanding during the period. (F) Embedded cost rate. (G) Medium-term notes interest rates and average balances are calculated on a 360-day year.
F-13 -48- 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, 1993 CENTRAL MAINE POWER COMPANY File No. 1-5139 (Exact name of Registrant as specified in charter) EXHIBITS F-13 -49- 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. Prior Exhibit Description of Exhibit No. Document SEC Docket No. EXHIBIT 2: PLAN OF ACQUISITION, REORGANIZATION, ARRANGEMENT, LIQUIDATION OR SUCCESSION Not Applicable. EXHIBIT 3: ARTICLES OF INCORPORATION AND BY-LAWS Incorporated herein by reference: 3-1 Articles of Incorporation, as Annual Report on 3.1 amended. Form 10-K for year ended December 31, 1992 3-2 Bylaws, as amended. Annual Report on 3.2 Form 10-K for the year ended December 31, 1990 EXHIBIT 4: INSTRUMENTS DEFINING THE RIGHTS OF SECURITY HOLDERS F-13 -50- Prior Exhibit Description of Exhibit No. Document SEC Docket No. Incorporated herein by reference: 4-1 General and Refunding Mortgage 2-58251 2.18 between the Company and The First National Bank of Boston, as Trustee, dated as of April 15, 1976, relating to the Series A Bonds. 4-2 First Supplemental Indenture 2-60786 2.19 dated as of March 15, 1977 to the General and Refunding Mortgage. 4-3 Supplemental Indenture to the Annual Report on A General and Refunding Mortgage Form Indenture dated as of October 1, 10-K for the year 1978 relating to the Series B ended December 31, Bonds. 1978 4-4 Supplemental Indenture to the Quarterly Report on A General and Refunding Mortgage for the quarter Indenture dated as of October 1, ended Septem- 1979, relating to the Series C ber 30, 1979 Bonds. 4.10 Supplemental Indenture to the 33-9232 4.16 General and Refunding Mortgage Indenture dated as of December 1, 1986, relating to the Series I Bonds. F-13 -51- Prior Exhibit Description of Exhibit No. Document SEC Docket No. 4.14 Indenture, dated as of Augst 1, 33-29626 4.1 1989, between the Company and The Ban of New York, Trustee, relating to the Medium-Term Notes. 4.15 First Supplemental Indenture, Current Report on 4.15 dated as of August 7, 1989, Form relating to the Medium-Term 8-K dated Notes, Series A, and August 16, 1989 supplementing the Indenture relating to the Medium-Term Notes. 4.15.1 Second Supplemental Indenture, Current Report on 4.1 dated as of January 10, 1992, Form relating to the Medium-Term 8-K dated Notes, Series B, and January 28, 1992 supplementing the Indenture relating to the Medium-Term Notes. 4.17 Supplemental Indenture to the Current Report on 4.1 General and Refunding Mortgage Form Indenture, dated as of 8-K dated September September 15, 1991, relating to 17, 1991 the Series N Bonds. 4.18 Supplemental Indenture to the Current Report on 1.2 General and Refunding Mortgage Form Indenture, dated as of 8-K dated December 1, 1991, relating to December 10, 1991 the Series O Bonds. F-13 -52- Prior Exhibit Description of Exhibit No. Document SEC Docket No. 4.19 Supplemental Indenture to the Annual Report on 4.19 General and Refunding Mortgage Form Indenture, dated as of 10-K for year ended December 15, 1992, relating to December 31, 1992 the Series P Bonds. 4.20 Supplemental Indenture to the Current Report on 4.1 General and Refunding Mortgage Form Indenture, dated as of February 8-K dated March 1, 15, 1993, relating to the Series 1993 Q Bonds. 4.21 Supplemental Indenture to the Current Report on 4.1 General and Refunding Mortgage Form Indenture, dated as of May 20, 8-K dated May 20, 1993, relating to the Series R 1993 Bonds. 4.22 Supplemental Indenture to the Current Report on 4.1 General and Refunding Mortgage Form Indenture, dated as of August 8-K dated November 15, 1993, relating to the Series 30, 1993 S Bonds. 4.23 Supplemental Indenture to the Current Report on 4.2 General and Refunding Mortgage Form Indenture, dated as of November 8-K dated November 1, 1993, relating to the Series 30, 1993 T Bonds. EXHIBIT 9: VOTING TRUST AGREEMENT Not applicable. EXHIBIT 10: MATERIAL CONTRACTS F-13 -53- Prior Exhibit Description of Exhibit No. Document SEC Docket No. Incorporated herein by reference: 10-1 Agreement dated April 1, 1968 2-30554 4.27 between the Company and Northeast Utilities Service Company relating to services in connection with the New England Power Pool and NEPEX. 10-2 Form of New England Power Pool 2-55385 4.8 Agreement dated as of September 1, 1971 as amended to November 1, 1975. 10-3 Agreement setting forth 2-50198 5.10 Supplemental NEPOOL Understandings dated as of April 2, 1973. 10-4 Sponsor Agreement dated as of 2-32333 4.27 August 1, 1968 among the Company and the other sponsors of Vermont Yankee Nuclear Power Corporation. 10-5 Power Contract dated as of 2-32333 4.28 February 1, 1968 between the Company and Vermont Yankee Nuclear Power Corporation. 10-6 Amendment to Exhibit 10.5 dated 2-46612 13-21 as of June 1, 1972. F-13 -54- Prior Exhibit Description of Exhibit No. Document SEC Docket No. 10-7 Capital Funds Agreement dated as 2-32333 4.29 of February 1, 1968 between the Company and Vermont Yankee Nuclear Power Corporation. 10-8 Amendment to Exhibit 10.7 dated 70-4611 B-3 as of March 12, 1968. 10-9 Stockholder Agreement dated as 2-32333 4.30 of May 20, 1968 among the Company and the other stockholders of Maine Yankee Atomic Power Company. 10-10 Power Contract dated as of May 2-32333 4.31 20, 1968 between the Company and Maine Yankee Atomic Power Company. 10-10.1 Amendment No. 1 to Exhibit 10-10 Annual Report on 10-1.1 dated as of March 1, 1984. Form 10-K for the year ended December 31, 1985 of Maine Yankee Atomic Power company (File No. 1-6554) F-13 -55- Prior Exhibit Description of Exhibit No. Document SEC Docket No. 10-10.2 Amendment No. 2 to Exhibit 10-10 Annual Report on 10-1.2 dated as of January 1, 1984. Form 10-K for the year ended December 31, 1985 of Maine Yankee Atomic Power Company (File No. 1-6554) 10-10.3 Amendment No. 3 to Exhibit 10-10 Annual Report on 10-1.3 dated as of October 1, 1984. Form 10-K for the year ended December 31, 1985 of Maine Yankee Atomic Power Company (File No. 1-6554) 10-10.4 Additional Power Contract Annual Report on 10-1.4 between the Company and Maine Form Yankee Atomic Power Company 10-K for the year dated February 1, 1984. ended December 31, 1985 of Maine Yankee Atomic Power Company (File No. 1-6554) 10-11 Capital Funds Agreement dated as 2-32333 4.32 of May 20, 1968 between the Company and Maine Yankee Atomic Power Company. F-13 -56- Prior Exhibit Description of Exhibit No. Document SEC Docket No. 10-11.1 Amendment No. 1 to Exhibit 10-11 Annual Report on 10-2.1 dated as of August 1, 1985. Form 10-K for the year ended December 31, 1985 of Maine Yankee Atomic Power Company (File No. 1-6554) 10-25 Agreement dated as f May 1, 1973 2-48966 13-57 for Joint Ownership, Construction and Operation of New Hampshire Nuclear Units among Public Service Company of New Hampshire and certain other utilities, including the Company. 10-42 Twentieth Amendment to Exhibit Annual Report on 10-42 10-25 dated as of September 19, Form 1986. 10-K for the year ended December 31, 1986 10-46 Participation Agreement, dated 2-35073 4.23.1 June 20, 1969 among Maine Electric Power Company, Inc., the Company and certain other utilities. F-13 -57- Prior Exhibit Description of Exhibit No. Document SEC Docket No. 10-47 Power Purchase and Transmission 2-35073 4.23.2 Agreement dated August 1, 1969, among Maine Electric Power Company, Inc., the Company and certain other utilities, relating to purchase and transmission of power from The New Brunswick Electric Power Commission. 10-48 Agreement amending Exhibit 10-47 2-37987 4.41 dated June 24, 1970. 10-49 Agreement supplementing Exhibit 2-51545 5.7.4 10-47 dated December 1, 1971. 10-50 Assignment Agreement dated March 2-51545 5.7.5 20, 1972, between Maine Electric Power Company, Inc., and the New Brunswick Electric Power Commission. 10-51 Capital Funds Agreement dated as 2-24123 4.19.1 of September 1, 1964 among Connecticut Yankee Atomic Power Company, the Company and certain other utilities. 10-52 Power Contract dated as of 2-24123 4.19.2 July 1, 1964 among Connecticut Yankee Atomic Power Company, the Company and certain other utilities. F-13 -58- Prior Exhibit Description of Exhibit No. Document SEC Docket No. 10-53 Stockholder Agreement dated as 2-24123 4.19.3 of July 1, 1964 among the stockholders of Connecticut Yankee Atomic Power Company, including the Company. 10-54 Connecticut Yankee Transmission 2-24123 4.19.4 Agreement dated as of October 1, 1964 among the stockholders of Connecticut Yankee Atomic Power Company, including the Company. 10-55 Agreements with Yankee Atomic Electric Company each dated June 30, 1959, as follows: 10-55.1 Stock Agreement. 2-15553 4.17.1 10-55.2 Power Contract. 2-15553 4.17.2 10.55.3 Research Agreement. 2-15553 4.17.3 10-56 Transmission Agreement with 2-15553 4.18 Cambridge Electric Light Company and other sponsoring stockholders of Yankee Atomic Electric Company. 10-57 Agreement for Joint Ownership, 2-52900 5.16 Construction and Operation of Wyman Unit No. 4 dated November 1, 1974 among the Company and certain utilities. F-13 -59- Prior Exhibit Description of Exhibit No. Document SEC Docket No. 10-58 Amendment to Exhibit 10-57 dated 2-55458 5.48 as of June 30, 1975. 10-59 Amendment to Exhibit 10-57 dated 2-58251 5.19 as of August 16, 1976. 10-60 Amendment to Exhibit 10-57 dated 2-68184 5.31 as of December 31, 1978. 10-61 Transmission Agreement dated 2-54449 13-57 November 1, 1974 among the Company and certain other utilities, relating to Wyman Unit No. 4. 10-62 Sharing Agreement--1979 2-50142 2.43 Connecticut Nuclear Unit dated September 1, 1973 among the Company and certain other utilities, relating to Millstone Unit No. 3. 10-63 Amendment to Exhibit 10-62 dated 2-51999 5.16 as of August 1, 1974, relating to Millstone Unit No. 3. 10-64 Agreement dated as of 2-58251 5.24 February 25, 1977 among the Company, the Connecticut Light and Power Company, the Hartford Electric Light Company and Western Massachusetts Electric Company, relating to Millstone Unit No. 3. F-13 -60- Prior Exhibit Description of Exhibit No. Document SEC Docket No. 10-70 Project Agreement dated Annual Report on 10-69 December 5, 1984 among the Form Company, the Cities of Lewiston 10-K for the year and Auburn, Maine and certain ended December 31, other parties, relating to 1984 development of hydro-electric plant. 10-73 Trust Indenture dated as of 2-60786 5.27 June 1, 1977 between the Town of Yarmouth and Casco Bank & Trust Company, as trustee, relating to the Town of Yarmouth's 6 3/4% Pollution Control Revenue Bonds (Central Maine Power Company, 1977 Series A). 10-74 Installment Sale Agreement dated 2-60786 5.28 as of June 1, 1977 between the Town of Yarmouth and the Company. 10-75 Agreements Relating to $11,000,000 Floating/Fixed Rate Pollution Control Revenue Refunding Bonds: 10-75.1 Bond Purchase Agreement dated as Quarterly Report on 28.3 of May 1, 1984. Form 10-Q for the quarter ended June 30, 1984 F-13 -61- Prior Exhibit Description of Exhibit No. Document SEC Docket No. 10-75.2 Loan Agreement dated as of Quarterly Report on 28.4 May 1, 1984. Form 10-Q for the quarter ended June 30, 1984 10-76 Agreements Relating to $8,500,000 Floating/Fixed Rate Pollution Control Revenue Bonds: 10-76.1 Bond Purchase Agreement dated Annual Report on 10-77.1 December 28, 1984. Form 10-K for year ended December 31, 1984 10-76.2 Loan Agreement dated as of Annual Report on 10-77.2 December 1, 1984. Form 10-K for year ended December 31, 1984 10-77.1 Indenture of Trust dated as of Annual Report on 10-1.4 March 14, 1988 between Maine Form Yankee Atomic Power Company and 10-K for year ended Maine National Bank relating to December 31, 1987, decommissioning trust funds. of Maine Yankee Atomic Power Company (1-6554) 10-77.1(a) Amended and Restated Indenture Annual Report on 10-6.1 of Trust dated as of January 1, Form 1993 between Maine Yankee Atomic 10-K for year ended Power Company and The Bank of December 31, 1992, New York relating to of Maine Yankee decommissioning trust funds. Atomic Power Company (1-6554) F-13 -62- Prior Exhibit Description of Exhibit No. Document SEC Docket No. 10-77.2 Indenture of Trust dated as of Annual Report on 10-7 October 16, 1985 between the Form Company and Norstar Bank of 10-K for year ended Maine relating to the spent fuel December 31, 1985, disposal funds. of Maine Yankee Atomic Power Company (1-6554) 10-78 Form of Agreement of Purchase Annual Report on 0.79 and Sale dated February 19, 1986 Form between the Company and Eastern 10-K for the year Utilities Associates, relating ended December 31, to the sale of the Company's 1985 Seabrook Project interest. 10-79 Addendum to Agreement of Quarterly Report on 2.1 Purchase and Sale dated June 23, Form 10-Q for the 1986, among the Company, Eastern quarter ending Utilities Associates and EUA June 30, 1986 Power Corporation, amending Exhibit 10-78. 10-80 Agreement, dated as of Quarterly Report on 2.1 October 29, 1986, between the Form 10-Q for the Company and EUA Power quarter ended Corporation, relating to the September 30, 1986 sale of the Company's interest in the Seabrook Project. F-13 -63- Prior Exhibit Description of Exhibit No. Document SEC Docket No. 10-81 Credit Agreement, dated as of Quarterly Report on 2.2 October 15, 1986, among the Form 10-Q for the Company, various banks and quarter ended Continental Illinois National September 30, 1986 Bank and Trust Company of Chicago, as agent, establishing the terms of a $40 million unsecured credit facility. 10-86 Labor Agreement dated as of Annual Report on 10.86 May 1, 1989 between the Company Form (Northern, Western and Southern 10-K for the year Division) and Local 1837 of the ended December 31, International Brotherhood of 1989 Electrical Workers. 10-86.1 Agreement dated as of Annual Report on 10.86.1 November 25, 1991 extending Form Labor Contract. 10-K for year ended December 31, 1991 10-89 1987 Executive Incentive Plan, Annual Report on 10.89 as amended January 20, 1993.* Form 10-K for year ended December 31, 1992 10-90 Deferred Compensation Plan for Annual Report on 10.90 Non-Employee Directors, as Form amended and restated effective 10-K for year ended February 1, 1992.* December 31, 1992 10-91 Retirement Plan for Outside Annual Report on 10.91 Directors, as amended and Form restated effective April 24, 10-K for year ended 1991.* December 31, 1992 F-13 -64- Prior Exhibit Description of Exhibit No. Document SEC Docket No. 10-92 Employment Agreement between the Filed herewith Company and Matthew Hunter dated as of October 20, 1993.* 10-93 Central Maine Power Company Filed herewith Long-Term Incentive Plan.* 10-94 Central Maine Power Company Filed herewith Supplemental Executive Retirement Plan, as amended and restated effective January 1, 1993.* *Management contract or compensatory plan or arrangement required to be filed in response to Item 14(c) of Form 10-K. EXHIBIT 11: STATEMENT RE COMPUTATION OF PER SHARE EARNINGS Not Applicable. EXHIBIT 12: STATEMENTS RE COMPUTATION OF RATIOS Not Applicable. EXHIBIT 13: ANNUAL REPORT TO SECURITY HOLDERS, FORM 10-Q OR QUARTERLY REPORT TO SECURITY HOLDERS F-13 -65- Prior Exhibit Description of Exhibit No. Document SEC Docket No. 13-1 Management's Discussion and Filed herewith Analysis of Financial Condition and REsults of Operations and Financial Statements from Annual Report of Central Maine Power Company to Shareholders for the year ended December 31, 1993 (pages 1-49). EXHIBIT 16: LETTER RE CHANGE IN CERTIFYING Current Report on 16.1 ACCOUNTANT Form 8-K/A dated January 13, 1994 EXHIBIT 18: LETTER RE CHANGE IN ACCOUNTING PRINCIPLES Not Applicable. EXHIBIT 21: SUBSIDIARIES OF THE REGISTRANT List of subsidiaries of Annual Report on 22.1 registrant. Form 10-K for year ended December 31, 1992 EXHIBIT 22: PUBLISHED REPORT CONCERNING MATTERS SUBMITTED TO VOTE OF SECURITY HOLDERS Not Applicable. EXHIBIT 23: CONSENTS OF EXPERTS AND COUNSEL F-13 -66- Prior Exhibit Description of Exhibit No. Document SEC Docket No. 23-1 Consent of Arthur Andersen & Co. Filed herewith at to the incorporation by page F-3 reference of their reports included or incorporated by reference herein in the Company's Registration Statements (File Number 33- 36679, 33-39826, 33-44754, 33- 44944 and 33-51611). EXHIBIT 24: POWER OF ATTORNEY Not Applicable. EXHIBIT 27: FINANCIAL DATA SCHEDULE Not Applicable. EXHIBIT 28: INFORMATION FROM REPORTS FURNISHED TO STATE INSURANCE REGULATORY AUTHORITIES Not Applicable. EXHIBIT 99: ADDITIONAL EXHIBITS To be filed under cover of a Form 10-K/A amendment of this Form 10-K within 180 days after December 31, 1993, pursuant to Rule 15d-21 under the Securities Exchange Act of 1934: F-13 -67- Prior Exhibit Description of Exhibit No. Document SEC Docket No. 99-1 and -2 Information, financial statements and exhibits required by Form 11-K with respect to certain employee savings plans maintained by the Company.
F-13 -68- EX-10.92 2 HUNTER AGREEMENT Exhibit 10-92 EMPLOYMENT AGREEMENT THIS AGREEMENT made as of this 20th day of October, 1993 by and between MATTHEW HUNTER ("Hunter") of Chelsea, in the County of Kennebec and State of Maine, and CENTRAL MAINE POWER COMPANY, a corporation organized and existing under the laws of the State of Maine and having its principal place of business at Augusta, in the County of Kennebec and State of Maine ("CMP"); W I T N E S S E T H: WHEREAS, Hunter is presently serving as President and Chief Executive Officer of CMP and the parties desire to continue that relationship, and to reach a written agreement as to the terms and conditions of that employment; WHEREAS, Hunter and CMP have an existing Employment Agreement dated August 28, 1991, which the parties desire to terminate; and WHEREAS, Hunter has foregone any salary increase during the past three years, notwithstanding his serving CMP in an exemplary fashion. NOW THEREFORE, in consideration of these premises and the covenants herein contained, the parties agree as follows: 1. Hunter and CMP agree that the Employment Agreement dated August 28, 1991 is hereby terminated and neither party shall have any further obligations, rights or responsibilities with respect to the provisions thereof. 2. Subject to the terms and conditions hereof, CMP hereby employs Hunter as its President and Chief Executive Officer to serve for a period of time at the pleasure of the CMP Board of Directors, but in no event to continue after February 1, 1995. Hunter shall also be elected to such other offices and directorships of subsidiary and affiliated entities as the Board shall deem appropriate. Hunter accepts such employment, and shall serve as President and Chief Executive Officer subject to the Company's By-Laws, any position description as adopted or amended by the Board of Directors now or in the future, and to the direction of the Board of Directors and its Governance Committee. The parties recognize that Section 4.3 of the CMP By-Laws provides that the officers may be elected annually by the Board. 3. Hunter agrees during the period he is employed hereunder to devote his full time and attention to the business of CMP. Hunter shall retain the right to expend reasonable amounts of time for professional, charitable and civic activities, in accordance with his past practices, provided such activities do not interfere with the services required to be performed hereunder, and provided further that Hunter will not accept any future commitments requiring the expenditure of significant amounts of time, without the consent of the CMP Governance Committee. 4. During the period Hunter is employed hereunder, CMP shall pay to Hunter, as compensation for the services hereunder, a base salary at the annual rate of Two Hundred Eighty-Five Thousand Dollars ($285,000). 5. During the period Hunter is employed hereunder, Hunter shall participate in all of CMP's regular fringe benefit programs and employee benefit plans, in accordance with the terms of such programs and plans as they presently exist or may hereafter be amended which are applicable to CMP's senior officers. Hunter shall be entitled to maintain all his existing rights and benefits in said regular fringe benefit programs and employee benefit plans as they may exist as of the effective date hereof, and as they may be subsequently amended or terminated. 6. Upon Hunter's retirement, on February 1, 1995 or prior thereto with the mutual consent for Hunter and CMP, Hunter shall be entitled to receive an annual benefit (the "Benefit"), payable in equal monthly payments, of: (i) sixty-five (65%) percent of Hunter's total compensation earned during the immediately preceding twelve months including any incentive compensation and deferred compensation, if any, but specifically excluding from such compensation any payments actually received by or accrued for Hunter pursuant to any long term incentive plan adopted by the Board of Directors of CMP; with the Benefit undiminished by (x) any amount receivable by Hunter or his spouse pursuant to Social Security, (y) any so-called early retirement reduction such as that provided in CMP's Retirement Income Plan for Non- Union Employees (the "Plan"), or (z) any so-called joint and survivor formula reduction such as that provided in the Plan; from the Benefit shall be subtracted: (ii)(a) any benefits to which Hunter would be entitled pursuant to the fifty percent (50%) joint and survivor annuity benefit with Hunter's wife as contingent annuitant, all pursuant to the Plan, which election Hunter agrees to make, provided nevertheless, if Hunter is then unmarried there shall be subtracted the life annuity benefit to which Hunter would be entitled pursuant to the Plan, whether or not such election has been made; (b) any benefits payable under any supplemental employee benefit plan instituted by CMP after the date hereof; and (c) any benefits under any disability income protection plan maintained by CMP. In the event that prior to February 1, 1995, CMP terminates Hunter's employment for any reason other than cause as described in Section 12(c) hereof, Hunter shall be entitled to receive the Benefit, above described. 7. In the event Hunter dies prior to February 1, 1995, and prior to his receipt of any benefits hereunder, Hunter's spouse shall be entitled to receive for her lifetime, one-half of the amount to which Hunter would have been entitled pursuant to Section 6 hereof. In the event Hunter dies after the date of this Agreement, having received benefits hereunder, Hunter's spouse shall be entitled to receive for her lifetime, one-half of the amount which Hunter was then receiving. 8. Any benefit payable to Hunter or his spouse pursuant to this Employment Agreement shall be determined by the actuary then providing services to CMP in connection with the administration of the Plan. The actuary's good faith determination of the amounts payable hereunder shall be final and binding upon the parties. 9. Upon the termination of Hunter's employment for any reason whatsoever, any benefit which Hunter received pursuant to this Agreement shall be in total satisfaction of any and all rights which Hunter may have against CMP, the Board or any Committee thereof. 10. During the period Hunter is employed hereunder, CMP shall provide Hunter with an automobile and the payment of, or reimbursement for, travel and other out-of-pocket expenses reasonably incurred by Hunter in the performance of his duties hereunder. 11. Hunter agrees that during the employment period and for a term of two years after any termination of Hunter's employment with CMP for any reason, voluntarily or involuntarily, he shall not, without the prior written consent of CMP's Governance Committee, directly or indirectly, acquire any interest in as stockholder, director, consultant, agent, employee, partner, owner of real estate, or otherwise act, with or without compensation, for any corporation, entity or business which is at the time or thereafter involved with any business related to the production, generation, co-generation, or distribution of electrical energy within the geographical area in which CMP does business now or in the future, or engage in activities which in CMP's reasonable judgment, may be deemed competitive with the activities of CMP; with the exception that Hunter may acquire and own minority stock holdings in companies whose shares are listed for trading on the American or New York Stock Exchanges, or traded "over the counter," and regularly reported by NASDAQ. The parties agree that the subject matter, duration of, and geographic area covered by this covenant are reasonable in light of the facts as they exist on the date hereof. However, if at any time a court or other body having jurisdiction over this Agreement shall determine that any of the subject matter, duration or geographic area hereof is unreasonable in any respect, it shall be reduced, and not terminated, as such court or body determined may be reasonable. 12. Except as otherwise specifically provided herein, this Agreement and Hunter's services hereunder (a) shall terminate forthwith upon his death, in which event the benefits payable to Hunter's spouse would be determined in accordance with the provisions of Section 6 or 7 hereof, whichever is applicable; and (b) may be terminated by CMP if Hunter becomes totally disabled in which event he shall be entitled to receive a benefit as determined in accordance with Section 6 hereof; and (c) may be terminated by CMP for cause, which for the purposes of this Agreement shall include any of the following: failure to follow the express directions of the Board of Directors or the Governance Committee, dishonest or illegal conduct, a material violation of any of the provisions of this Agreement, or the conviction of a crime, other than a minor traffic violation; in which event no payments shall be due Hunter or his spouse under this Agreement. 13. Any notice or other communication provided for herein or contemplated hereby shall be sufficiently given or made if in writing and delivered or mailed, certified mail - return receipt requested as follows: To CMP: Central Maine Power Company General Office Edison Drive Augusta, Maine 04336 Attention: Chairman of the Governance Committee To Hunter: Mr. Matthew Hunter R.F.D. #2, Box 430 Augusta, Maine 04330 14. This Agreement shall be binding upon and inure to the benefit of the parties hereto, and their respective heirs, legal representatives, successors and assigns. 15. This Agreement shall be governed by and construed in accordance with the laws of the State of Maine, and may be amended only in writing. This Agreement contains the entire agreement and understandings of the parties with respect to the subject matter hereof, and supersedes any and all prior agreements and understandings whether oral or written between Hunter and CMP. IN WITNESS WHEREOF, Matthew Hunter and Central Maine Power Company have executed this agreement as of the date first written above. WITNESS: Laurie E. Halligan Matthew Hunter Matthew Hunter "Hunter" CENTRAL MAINE POWER COMPANY William M. Finn By: Carlton D. Reed, Jr. Its Chairman of the Board "CMP" EX-10.93 3 LONG TERM INCENTIVE PLAN Exhibit 10-93 CENTRAL MAINE POWER COMPANY LONG-TERM INCENTIVE PLAN CENTRAL MAINE POWER COMPANY LONG-TERM INCENTIVE PLAN Table of Contents Section Page 1. Purpose . . . . . . . . . . . . . . . . . . . . . . . . 1 2. Definitions . . . . . . . . . . . . . . . . . . . . . 2 3. Grant of Awards . . . . . . . . . . . . . . . . . . . . 4 a. Authority . . . . . . . . . . . . . . . . . . . . . 4 b. Eligibility . . . . . . . . . . . . . . . . . . . . 5 c. Amount of Award . . . . . . . . . . . . . . . . . . 5 d. Limitations on Awards . . . . . . . . . . . . . . . 6 4. Restriction Period . . . . . . . . . . . . . . . . . . 7 a. Transfer Restrictions . . . . . . . . . . . . . . . 7 b. Termination of Employment . . . . . . . . . . . . . 7 c. Stock Certificates . . . . . . . . . . . . . . . . 8 5. Award Payouts . . . . . . . . . . . . . . . . . . . . . 9 6. Beneficiary . . . . . . . . . . . . . . . . . . . . . 10 a. Designation . . . . . . . . . . . . . . . . . . . 10 b. No Beneficiary . . . . . . . . . . . . . . . . . 10 7. Administration of the Plan . . . . . . . . . . . . . 11 a. Section 16 Compliance . . . . . . . . . . . . . . 11 b. Decisions and Interpretations . . . . . . . . . . 11 c. Procedure . . . . . . . . . . . . . . . . . . . . 12 d. Advisors . . . . . . . . . . . . . . . . . . . . 12 e.Indemnification . . . . . . . . . . . . . . . . . . 12 8. Amendment or Discontinuance . . . . . . . . . . . . . 13 9. Purchase of Stock . . . . . . . . . . . . . . . . . . 14 a. Agent and Purchases by Agent . . . . . . . . . . 14 b. Custody and Sales by Agent . . . . . . . . . . . 14 - i - 10. Miscellaneous . . . . . . . . . . . . . . . . . . . . 15 a. No Claim or Right . . . . . . . . . . . . . . . . 15 b. Leave . . . . . . . . . . . . . . . . . . . . . . 16 c. Incapacity . . . . . . . . . . . . . . . . . . . 16 d. No Assignment . . . . . . . . . . . . . . . . . . 17 e. Plan Documents . . . . . . . . . . . . . . . . . 17 f. Applicability of Laws . . . . . . . . . . . . . . 17 g. Notices . . . . . . . . . . . . . . . . . . . . . 17 h. Successors Bound . . . . . . . . . . . . . . . . 17 i. Captions . . . . . . . . . . . . . . . . . . . . 18 11. Effective Date and Shareholder Approval . . . . . . . 18 - ii - CENTRAL MAINE POWER COMPANY LONG-TERM INCENTIVE PLAN 1. Purpose The purpose of the Central Maine Power Company Long-Term Incentive Plan is to motivate Key Employees of Central Maine Power Company to attain and surpass long-range performance objectives intended to provide the shareholders of the Company sound returns on their investment. Under the Plan, the motivation of Key Employees to improve performance is enhanced by providing them with incentive awards that are payable only to the extent that performance results in shareholder benefits. The Plan further aligns the interests of Key Employees with those of the Company's shareholders by providing for such incentive awards to be paid in the form of the Common Stock of the Company subject to performance and other restrictions set forth in the Plan. The Plan is also designed to attract and retain persons of ability as Key Employees of the Company by providing them with compensation opportunities that are competitive with those offered by other utilities. The long-range performance objectives under the Plan are intended to complement certain performance objectives under the Company's 1987 Executive Incentive Plan that are designed to benefit the Company's customers. Together, the Plan and the 1987 Executive Incentive Plan place a greater portion of total pay offered to Key Employees at risk by providing for that portion of compensation to be paid only to the extent that performance has resulted in benefits for the Company's shareholders and customers. 2. Definitions When used herein, the following terms shall have the following meanings: "Award" means a contingent grant to any Key Employee, in accordance with the provisions of the Plan, of Performance Restricted Stock or other Common Stock of the Company, as may be determined by the Compensation and Benefits Committee. "Award Payout" means any shares of Performance Restricted Stock including the shares of Performance Restricted Stock resulting from the reinvestment of dividends, after the lapse of the Restriction Period applicable thereto, and any additional shares of the Common Stock of the Company, actually distributed to any Key Employee based on the level of performance achieved for the relevant Performance Period as measured by reference to the Performance Measure and any other performance standards established by the Compensation and Benefits Committee. "Beneficiary" means the beneficiary or beneficiaries designated pursuant to Section 6 to receive an Award Payout or Award Payouts, if any, under the Plan upon the death of a Key Employee. "Company" means Central Maine Power Company and its successors and assigns. "Compensation and Benefits Committee" means the Central Maine Power Company Compensation and Benefits Committee appointed by the Board of Directors of the Company and responsible for the administration of the Plan. "Key Employee" means an employee, including without limitation any officer, of the Company whose contributions and -1- responsibilities have a significant impact on the future of the Company, in the judgment of the Compensation and Benefits Committee. "Market Value" means, as of any specified date, the reported closing price based upon composite transactions on the New York Stock Exchange for one share of the common stock of any specified electric utility, including without limitation the Company, on such exchange, or, if no sales of that utility's common stock have taken place on such exchange on that date, the reported closing price on the most recent earlier trading day on which sales of such common stock were reported. "Performance Measure" means the Company's Total Shareholder Return or a change, on a basis determined by the Compensation and Benefits Committee, in the Company's Total Shareholder Return as ranked against the Total Shareholder Return of other electric utilities designated by the Compensation and Benefits Committee or a change in such other utilities' Total Shareholder Return, and, alternatively, also means improvement in the ranking of the Company's Total Shareholder Return or in the ranking of the level of change therein, in each case based on levels of performance established by the Compensation and Benefits Committee. "Performance Period" means a period of three (3) or more years, as determined by the Compensation and Benefits Committee, beginning on the first day of the first year of such period or at such other time as may be determined by the Compensation and Benefits Committee, over which performance is measured by reference to the Performance Measure and any other performance standards established by the Compensation and Benefits Committee. "Performance Restricted Stock" means the Common Stock of the Company granted under the Plan for no consideration but subject to the requirements and restrictions of Sections 3 and 4 hereof and such other restrictions as the Compensation and Benefits Committee deems appropriate or desirable, and includes additional shares of Performance Restricted Stock resulting from the reinvestment of dividends. "The Plan" or "this Plan" means the Central Maine Power Company Long-Term Incentive Plan, as the same may be amended, administered or interpreted from time to time. "Restriction Period" means the period described in Section 4.a of this Plan. "Total Disability" means the complete and permanent inability of a Key Employee to perform all of his or her duties under the terms of his or her employment with the Company, as determined by the Compensation and Benefits Committee upon the basis of such evidence, which may include independent medical reports and data, as the Compensation and Benefits Committee deems appropriate or necessary. "Total Shareholder Return" means the appreciation or depreciation in the Market Value of the common stock of an electric utility, including without limitation the Company, plus dividends thereon, as measured at any point in, or as averaged over, a Performance Period. 3. Grant of Awards a. Authority. Subject to the provisions of the Plan, the Compensation and Benefits Committee shall have the full power and -2- authority to (i) determine and designate from time to time the Key Employees or groups of Key Employees to whom Awards may be granted; (ii) determine the amount, terms and conditions of each Award, including, in addition to the Performance Measure and any part thereof, any performance standards pertaining to the Company or otherwise and any other criteria that must be satisfied as a condition to any Award Payout; (iii) determine the form or forms of Awards that may be granted; and (iv) determine the timing of any Award and Award Payout, including Performance Periods and whether and to what extent an Award or Award Payout shall be deferred and the conditions of any such deferral. b. Eligibility. The Compensation and Benefits Committee shall determine and designate from time to time the Key Employees or groups of Key Employees eligible to participate in the Plan, based upon the Key Employee's contribution towards the achievement of the Company's long-range corporate objectives, the recommendations of the President and Chief Executive Officer of the Company with respect to Key Employees other than the President and Chief Executive Officer, and such other factors as the Compensation and Benefits Committee, in its discretion, deems relevant. c. Amount of Award. Subject to the provisions of the Plan, Key Employees participating in the Plan shall be granted an Award of a specified number of shares of Performance Restricted Stock for each Performance Period under the Plan. The number of shares of Performance Restricted Stock granted to any Key Employee shall be determined by the Compensation and Benefits Committee, taking into account the purposes of the Plan and such factors as the Compensation and Benefits Committee, in its discretion, deems relevant. Such factors may include the value of the Key Employee's position with the Company, market levels of similar compensation, and the Market Value of the Company's Common Stock, and the Compensation and Benefits Committee may develop a formula based on these or other factors deemed relevant by the Compensation and Benefits Committee. Any such formula shall not be revised more than once in any six (6) month period. Subject to the restrictions set forth in or established by the Compensation and Benefits Committee pursuant to this Plan, each Key Employee who receives an Award shall, upon the issuance of a certificate for the shares of Performance Restricted Stock awarded as provided in Section 4.c hereof, have all of the rights of a shareholder with respect to such shares, including the right to vote the shares and receive dividends and other distributions for his or her account. Dividends on shares of Performance Restricted Stock shall be payable at the same rate as paid on the unrestricted shares of the Common Stock of the Company and shall be reinvested in additional shares of Performance Restricted Stock during the Performance Period until any Award Payout. Such additional shares shall be added to the shares of Performance Restricted Stock constituting the Award and shall be subject in all respects to the provisions of Sections 4.a, 4.b and 5 of this Plan and to other applicable provisions hereof. d. Limitations on Awards. Subject to the provisions of this Section 3.d, in any calendar year, grants of Awards, together with additional shares of Performance Restricted Stock resulting from the reinvestment of dividends, shall not exceed -3- one percent (1%) of the number of outstanding shares of the unrestricted Common Stock of the Company on the last day of the preceding calendar year. In the event of any recapitalization, reclassification, split-up or consolidation of shares of the Common Stock of the Company, merger or consolidation of the Company into, or consolidation of the Company with, or sale by the Company of all or substantially all of its assets to, another company, or other restructuring or event which could distort the implementation of the Plan or the value of the Awards or affect the realization of the objectives of the Plan, the Compensation and Benefits Committee may make such adjustments in any Awards, or in the terms, conditions or restrictions pertaining to the Performance Restricted Stock or the Awards, as the Compensation and Benefits Committee deems equitable. 4. Restriction Period a. Transfer Restrictions. Each Award of Performance Restricted Stock and additional shares of Performance Restricted Stock resulting from the reinvestment of dividends on the shares constituting the Award as provided in Section 3.c of this Plan shall be subject to a Restriction Period, which shall mean a period commencing on the date the Award is granted and ending as of the date of any Award Payout relating to such Award. No shares of Performance Restricted Stock received or held for the account of a Key Employee as provided in this Plan shall be sold, assigned, exchanged, pledged or otherwise transferred or disposed of during the Restriction Period. The Compensation and Benefits Committee may provide for the lapse of restrictions in installments in circumstances it deems appropriate. b. Termination of Employment. If a Key Employee's employment with the Company terminates due to the Key Employee's death, Total Disability, retirement, voluntary resignation or for any other reason, all Awards granted for Performance Periods that have not yet closed as of the date of any such event and all additional shares of Performance Restricted Stock resulting from the reinvestment of dividends on shares constituting such Awards shall be forfeited by the Key Employee and all such shares shall be acquired by the Company unless the Compensation and Benefits Committee, in its sole discretion, otherwise determines. In making any determination under this Section 4.b, the Compensation and Benefits Committee may, in its discretion, permit an Award Payout relating to all or a portion of any relevant Performance Period and impose any terms and conditions, consistent with the provisions of this Plan, as it deems appropriate. c. Stock Certificates. After compliance with any applicable requirements of federal and state securities laws and regulations and the rules of any stock exchange on which the Common Stock of the Company is then listed, a certificate for the number of shares of Performance Restricted Stock granted to a Key Employee shall be issued and shall be registered in the name of the Key Employee and bear an appropriate legend reciting the restrictions applicable to such shares or shall be registered in nominee name. All certificates issued under the Plan shall be subject to appropriate stop-transfer orders, including such stop- transfer orders and other restrictions as the Compensation and Benefits Committee may deem advisable under any applicable -4- federal or state securities laws and rules, regulations or other requirements of the Securities and Exchange Commission and any stock exchange on which the Common Stock of the Company is then listed. All certificates representing Awards and all additional shares of Performance Restricted Stock resulting from the reinvestment of dividends shall be received and held by the Company or a bank or other institution, as determined by the Compensation and Benefits Committee, during the Restriction Period for the account of each individual Key Employee who was granted an Award. 5. Award Payouts Following the close of each Performance Period, the Compensation and Benefits Committee shall evaluate performance results by reference to the Performance Measure and any other performance standards established for that Performance Period. Based on its evaluation and the consideration of any other factors it may deem appropriate, the Compensation and Benefits Committee shall determine whether and to what extent any Award Payouts shall be made. Each Award Payout to be made shall be reduced, prior to being made, by the number of shares of the Common Stock of the Company whose Market Value is sufficient to satisfy all applicable federal and state tax withholding requirements. Notwithstanding the attainment of a level of performance under the Performance Measure or any other performance standard established by the Compensation and Benefits Committee otherwise sufficient for any Award Payout, no Award Payout shall be made for a Performance Period during which the dividend on the Common Stock of the Company may have been reduced. In such event, the Compensation and Benefits Committee shall consider whether and to what extent to defer an Award Payout and shall determine the conditions of any such deferral, taking into account circumstances it deems appropriate. If the Compensation and Benefits Committee determines that no Award Payout shall be made at any time with respect to a Performance Period, the Award for that Performance Period and any additional shares of Performance Restricted Stock resulting from the reinvestment of dividends shall be forfeited by the Key Employee and acquired by the Company. 6. Beneficiary a. Designation. Each Key Employee shall file with the Compensation and Benefits Committee a written designation of one or more persons as the Beneficiary who shall be entitled to receive an Award Payout or Award Payouts, if any, under the Plan upon such Key Employee's death. A Key Employee may from time to time revoke or change his or her Beneficiary designation, without the consent of any prior Beneficiary (unless such consent is otherwise required by law) by filing a new designation with the Compensation and Benefits Committee. The last such designation received by the Compensation and Benefits Committee shall be controlling; provided, however, that no designation, or change or revocation thereof, shall be effective unless received by the Compensation and Benefits Committee prior to the Key Employee's death, and in no event shall it be effective as of a date prior to such receipt. -5- b. No Beneficiary. If no Beneficiary designation is in effect at the time of a Key Employee's death, or if such designation conflicts with law, or if no designated Beneficiary survives the Key Employee, the Key Employee's estate shall be entitled to receive an Award Payout or Award Payouts, if any, under the Plan upon the Key Employee's death. If the Compensation and Benefits Committee is in doubt as to the right of any person to receive any Award Payout, the Company may retain such Award Payout, without liability for any interest thereon, until the Compensation and Benefits Committee determines the rights thereto, or the Company may turn over such Award Payout to any court of appropriate jurisdiction and such turnover shall be a complete discharge of any liability of the Company in connection with such Award Payout. 7. Administration of the Plan a. Section 16 Compliance. The Plan shall be administered by the Compensation and Benefits Committee in conformance with the requirements of Rule 16b-3 under the Securities Exchange Act of 1934 as said Rule may be interpreted or amended from time to time, the intent of this Plan being that all transactions hereunder shall comply with all applicable conditions of said Rule 16b-3 or its successor. b. Decisions and Interpretations. All decisions, determinations or actions of the Compensation and Benefits Committee made or taken pursuant to grants of authority under this Plan shall be made or taken in the sole discretion of the Compensation and Benefits Committee and shall be final, conclusive and binding on all persons for all purposes. In addition, the Compensation and Benefits Committee shall have full power, discretion and authority to establish rules and guidelines, consistent with this Plan, for the administration of the Plan and to interpret, construe and administer the Plan and such rules and guidelines and any part thereof, and its interpretations and constructions thereof shall be final, conclusive and binding on all persons for all purposes. The decisions and determinations of the Compensation and Benefits Committee under the Plan need not be uniform with respect to Key Employees, whether or not such Key Employees are similarly situated. c. Procedure. The Compensation and Benefits Committee shall keep minutes of its actions under the Plan. The act of a majority of the members of the Compensation and Benefits Committee present at a meeting duly called and held shall be the act of the Compensation and Benefits Committee, provided that at least a majority of the members of the entire Compensation and Benefits Committee is in attendance at such meeting. Any decision or determination reduced to writing and signed by all members of the Compensation and Benefits Committee shall be fully as effective as if made by unanimous vote at a meeting duly called and held. d. Advisors. The Compensation and Benefits Committee may employ such legal counsel, whether independent legal counsel or counsel regularly employed by the Company, and consultants and agents as the Compensation and Benefits Committee may deem appropriate for the administration of the Plan and shall be fully -6- protected in relying upon any opinion received from any such counsel or consultant and any computations received from any such consultant or agent. All expenses incurred by the Compensation and Benefits Committee in interpreting and administering the Plan, including without limitation meeting fees and expenses and professional fees, shall be paid by the Company. e. Indemnification. No member or former member of the Compensation and Benefits Committee shall be liable for any action or determination made in good faith with respect to the Plan or any Award or Award Payout under the Plan. Each member or former member of the Compensation and Benefits Committee shall be indemnified and held harmless by the Company against all cost and expense (including counsel fees) and liability (including any sum paid in settlement of a claim with the approval of the Board of Directors of the Company) arising out of any action taken or omitted in connection with the Plan unless arising out of such member's or former member's own willful misconduct. Such indemnification shall be in addition to any rights of indemnification the members or former members of the Compensation and Benefits Committee may have as directors or under the bylaws of the Company. 8. Amendment or Discontinuance The Board of Directors of the Company may, at any time, amend or terminate the Plan. The Plan may also be amended by the Compensation and Benefits Committee, provided that all such amendments shall also be reported to and acted upon by the Board of Directors. No amendment shall, without approval by the holders of a majority of the shares of the Common Stock and 6% Preferred Stock of the Company present, or represented, and entitled to vote at a meeting duly called and held, (i) materially modify the requirements as to eligibility for participation in the Plan, (ii) materially increase the benefits provided under the Plan, or (iii) materially increase the maximum number of shares of Performance Restricted Stock which are available under the Plan. No amendment or termination shall retroactively impair any rights of any person with respect to an Award or Award Payout, and all amendments shall comply with the requirements of Rule 16b-3 of the Securities Exchange Act of 1934 as said Rule may be interpreted or amended from time to time. 9. Purchase of Stock a. Agent and Purchases by Agent. Notwithstanding any other provision of this Plan, the Compensation and Benefits Committee shall appoint an agent for Key Employees, and not for the Company, for the purchase of Common Stock of the Company to be granted under the Plan and for the purchase of additional shares of Common Stock representing reinvested dividends. Such agent shall not be an affiliate of the Company. The agent (and not the Company or any affiliate thereof) shall exercise all direct and indirect control and influence over the times when, and the prices at which, the agent may purchase or cause to be purchased Common Stock for the benefit or account of Key Employees under the Plan, the amount of any such Common Stock to be purchased, the manner in which any such Common Stock is to be purchased, and the selection of a broker or dealer through which such purchases -7- may be executed; provided, however, that the Compensation and Benefits Committee may provide the agent with any formula adopted by the Compensation and Benefits Committee pursuant to Section 3.c of the Plan for determining the number of shares of Common Stock to be purchased by the agent under the Plan and may provide the agent with instructions which are not inconsistent with the provisions of this Section 9. b. Custody and Sales by Agent. The agent (or its delegate) shall hold all shares of Common Stock purchased in connection with Awards granted for the initial Performance Period under the Plan and all additional shares of Common Stock resulting from the reinvestment of dividends thereon, in each case on behalf of the particular Key Employee who was granted an Award. In the event that the shareholders of the Company approve the Plan pursuant to Section 11 hereof, then such Common Stock shall be held on behalf of the Key Employees as directed by the Compensation and Benefits Committee, in accordance with the terms of the Plan. In the event that such shareholder approval is not obtained, the agent shall sell all shares of Common Stock purchased, including shares representing reinvested dividends. The agent (and not the Company or any affiliate thereof) shall exercise all direct and indirect control and influence over the times when, and the prices at which, the agent may sell or cause to be sold such Common Stock, the manner in which any such Common Stock is to be sold, and the selection of a broker or dealer through which such sales may be executed. All proceeds of such sales shall be paid to the Company. 10. Miscellaneous a. No Claim or Right. Nothing in this Plan and no Award or Award Payout hereunder shall confer upon any Key Employee any right to continue in the employ of the Company, or shall interfere in any way with the right (subject to any separate contractual arrangement with such Key Employee) of the Company to terminate his or her employment at any time. No Award or Award Payout under the Plan shall be deemed salary or compensation for the purpose of computing benefits under any employee benefit plan, including any retirement or supplemental or excess retirement benefit plan, or other arrangement of the Company for the benefit of its employees unless the Compensation and Benefits Committee shall determine otherwise. No Key Employee shall have any claim or right to any Award or Award Payout until an Award Payout relating to a particular Award is actually made under the Plan, and any such right shall be no greater than the right of an unsecured general creditor of the Company. Nothing contained in this Plan, and no action taken pursuant to its provisions, shall create or be construed to create a trust of any kind between the Company and any Key Employee. b. Leave. Absence on leave approved by the President and Chief Executive Officer of the Company shall not be considered interruption or termination of employment for any purposes of the Plan; provided, however, that the Compensation and Benefits Committee shall determine, in its discretion, whether an Award may be granted or an Award Payout may be made to a Key Employee if he or she is absent on leave during the Performance Period. c. Incapacity. If the Compensation and Benefits Committee -8- shall find that any person entitled to receive any Award Payout under the Plan is unable to care for his or her affairs because of illness or accident, or is a minor, then any Award Payout due him or her may, if the Compensation and Benefits Committee so directs the Company, be paid to his or her spouse, an institution maintaining or having custody of such person, or any other person deemed by the Compensation and Benefits Committee to be a proper recipient on behalf of such person otherwise entitled to such Award Payout, unless a prior claim therefor has been made by a duly appointed legal representative. Any such Award Payout shall be a complete discharge of any liability of the Company in connection with such Award Payout. d. No Assignment. The interest of any Key Employee or other person in any Award or Award Payout under the Plan may not be assigned, transferred, pledged or encumbered, except as provided in Section 6 with respect to the designation of a Beneficiary or as may otherwise be required by law, and any such assignment, transfer, pledge or encumbrance shall be void. e. Plan Documents. Copies of the Plan and all amendments, administrative rules and guidelines, and interpretations shall be made available to all Key Employees at all reasonable times at the Company's headquarters. f. Applicability of Laws. The Plan and Awards and Award Payouts hereunder shall be subject to all applicable federal and state laws, rules and regulations and to such approvals by any governmental or regulatory agency as may be required. g. Notices. All requests, notices and other communications from a Key Employee, Beneficiary or other person to the Compensation and Benefits Committee, required or permitted under the Plan, shall be in such form as may be prescribed from time to time by the Compensation and Benefits Committee and shall be mailed by first class mail or delivered to the Company's headquarters or such other location as may be specified by the Compensation and Benefits Committee. h. Successors Bound. The terms of the Plan shall be binding upon the Company and its successors and assigns. i. Captions. Captions preceding the Sections and subsections hereof are inserted solely as a matter of convenience and in no way define or limit the scope or intent of any provision hereof. 11. Effective Date and Shareholder Approval The effective date of this Plan shall be January 1, 1993; provided, however, that grants of Awards shall be conditioned upon approval of the Plan by the holders of a majority of the shares of the Company's Common Stock and 6% Preferred Stock present, or represented, and entitled to vote at the 1994 Annual Meeting of the Shareholders of the Company. Notwithstanding anything in the Plan to the contrary, Key Employees may be selected for participation in the Plan, Award criteria may be determined and Awards conditioned on such shareholder approval may be granted, all as provided herein, prior to submission of the Plan for approval by the shareholders. In the event that such shareholder approval is not obtained, all Awards and any additional shares of Performance Restricted Stock resulting from the reinvestment of dividends shall be forfeited and the Plan -9- shall be cancelled. -10- EX-10.94 4 SUPP EXEC RETIREMENT PLAN Exhibit 10-94 CENTRAL MAINE POWER COMPANY SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN As Amended and Restated Effective January 1, 1993 PREAMBLE The primary objective of the Central Maine Power Company Supplemental Executive Retirement Plan is to provide a competitive level of retirement income in order to attract and retain selected executives. The plan is designed to provide a benefit which, when added to other retirement income of an executive, will meet this objective. Participation in the plan shall be limited to senior officers of the Company who are selected by the Board of Directors. This plan is effective as of January 1, 1993. ARTICLE I Definitions 1.1 "Basic Plan" shall mean the Retirement Income Plan for Non-Union Employees of Central Maine Power Company, as amended from time to time. 1.2 "Basic Plan Benefit" shall mean the amount of benefit payable annually from the Basic Plan to the Participant in the form of a Single Life Annuity. 1.3 "Benefit Service" shall mean benefit service as defined in the Basic Plan. 1.4 "Board" or "Board of Directors" shall mean the Board of Directors of Central Maine Power Company. 1.5 "Code" shall mean the Internal Revenue Code of 1986, as amended. 1.6 "Committee" shall mean the Compensation and Benefits Committee of the Board of Directors. 1.7 "Company" shall mean Central Maine Power Company. 1.8 "Credited Service" shall mean credited service as defined in the Basic Plan. 1.9 "Earnings" shall mean a Participant's earnings as defined in the Basic Plan, but determined without regard to those provisions in the Basic Plan incorporating the limits of Section 401(a)(17) of the Code, and including amounts deferred by the Participant under any elective deferred compensation plan maintained by the Company and any amounts received by the Participant from the Executive Incentive Plan. -1- 1.10 "Effective Date" shall mean January 1, 1993. 1.11 "ERISA" shall mean the Employee Retirement Income Security Act of 1974, as amended. 1.12 "Final Average Earnings" shall mean the average of a Participant's highest thirty-six (36) consecutive months of Earnings while employed by the Company. 1.13 "Participant" shall mean an employee of the Company who is a member of the select group of management employees identified in Schedule A, attached hereto and made a part hereof, and who is vested under the Basic Plan. 1.14 "Plan" shall mean the Central Maine Power Company Supplemental Executive Retirement Plan as set forth herein and hereafter amended. 1.15 "Retirement" shall mean the termination of a Participant's employment with the Company and the commencement of benefit payments under the Plan. 1.16 "Retirement Date" shall mean one of the dates specified in Article II. 1.17 "Single Life Annuity" shall mean a series of equal monthly payments, beginning on the Participant's Retirement Date and ending with the monthly payment immediately preceding the Participant's death. 1.18 "Surviving Spouse" shall mean the surviving spouse of the Participant but only if the Participant and the surviving spouse had been married throughout the one-year period ending on the date of the Participant's death. A former spouse will be treated as the Surviving Spouse with specific reference to this Plan only to the extent provided under a qualified domestic relations order as described in Section 206(d)(3) of ERISA and applicable regulations thereunder. ARTICLE II Eligibility for Benefits A Participant is eligible to retire from the Company and receive a benefit under the Plan beginning on one of the following dates: 2.1 "Normal Retirement Date," which is the first day of the month coinciding with or next following the date on which the -2- Participant reaches age 65. 2.2 "Early Retirement Date," which is the first day of any month, prior to the Participant's Normal Retirement Date, coinciding with or following the date on which the Participant has both reached age 55 and completed five (5) years of Credited Service. 2.3 "Deferred Retirement Date," which is the first day of the month, after the Participant's Normal Retirement Date, coinciding with or next following the date on which the Participant terminates employment with the Company. The benefit to which the Participant will be entitled upon his or her Retirement Date shall be determined in accordance with Article III. ARTICLE III Supplemental Plan Benefits 3.1 Retirement Benefit. On Retirement a Participant shall be entitled to an annual benefit under this Plan equal to the amount determined under subsection (a) less the amounts determined under subsections (b), (c), and (d): (a) 2.6% of the Participant's Final Average Earnings, multiplied by-- (i) the Participant's completed years of Benefit Service (excluding any partial years), not in excess of 25; and (ii) except as provided in Section 3.2, if a Participant retires before age 62, the applicable early retirement reduction factor specified in the Basic Plan. (b) 100% of the Participant's Basic Plan Benefit, determined in accordance with all applicable provisions of the Basic Plan. (c) 100% of the amount payable annually as a Single Life Annuity that is the actuarial equivalent of the Participant's retirement benefit under any other nonqualified retirement plan of (or employment agreement with) the Company, determined in accordance with all applicable provisions of the nonqualified retirement plan or employment agreement, as the case may be. -3- (d) 100% of the amount payable annually as a Single Life Annuity that is the actuarial equivalent of any amount released to the Participant under any split-dollar life insurance agreement with the Company. For purposes of this Section, actuarial equivalence shall be determined in accordance with the actuarial assumptions specified in the Basic Plan. 3.2 Disability Retirement Benefit. If a Participant retires before age 62 with a disability benefit payable from the Basic Plan, the amount determined under subsection (a) of Section 3.1 shall not be reduced by the application of any early retirement reduction factor. 3.3 Pre-Retirement Death Benefit. If a Participant dies prior to the date his or her Retirement benefits commence under this Plan, a death benefit shall be payable to his or her Surviving Spouse in an amount equal to fifty percent (50%) of the amount the Participant would have received under the Plan had he or she been eligible to and elected early retirement the day before the date of his or her death with a benefit payable in the form of a qualified joint and survivor annuity, as described in the Basic Plan. 3.4 Post-Retirement Death Benefit. If the Participant dies after his or her Retirement benefits commence under this Plan a death benefit shall be payable only to the extent that such benefit is provided under the form of benefit payment in effect under Section 3.5. 3.5 Payment of Benefits. The benefits payable under the Plan shall be paid at such time and in such form as the benefits payable under the Basic Plan that the benefits payable hereunder are intended to supplement, unless the Committee shall otherwise determine. No benefit shall be paid hereunder until an application shall be made to the Committee in writing. In addition, the Committee may require an applicant for a benefit hereunder to furnish such information as it may reasonably request, and may delay the commencement of benefits, if necessary, until such information is made available. ARTICLE IV Administration 4.1 The complete authority to control and manage the operation and administration of the Plan shall be placed in the Committee. The Committee shall have sole discretion to construe -4- the Plan and to determine all questions relating to eligibility for and entitlement to benefits. Further, the Committee shall have the sole discretion to determine the time and form of benefit payments under the Plan. 4.2 Subject to the provisions of this Plan, the Committee from time to time may establish rules for the administration and interpretation of the Plan. The determination of the Committee as to any disputed questions shall be conclusive. All actions, decisions and interpretations of the Committee in administering the Plan shall be performed in a uniform and nondiscriminatory manner. 4.3 If an application for a benefit ("claim") is denied by the Committee, the Committee shall give written notice of such denial to the applicant, by certified or registered mail, within 60 days after the claim was filed with the Committee; provided, however, that such 60-day period may be extended to 120 days by the Committee if it determines that special circumstances exist which require an extension of the time required for processing the claim. Such denial shall set forth: (a) the specific reason or reasons for the denial; (b) the specific Plan provisions on which the denial is based; (c) any additional material or information necessary for the applicant to perfect the claim and an explanation of why such material or information is necessary; and (d) an explanation of the Plan's claim review procedure. Following receipt of such denial, the applicant or his or her duly authorized representative may: (a) request a review of the denial by filing written application for review with the Committee within 60 days after receipt by the applicant of such denial; (b) review documents pertinent to the claim at such reasonable time and location as shall be mutually agreeable to the applicant and the Committee; and (c) submit issues and comments in writing to the Committee relating to its review of the claim. The Committee shall, after consideration of the application for review, render a decision and shall give written notice -5- thereof to the applicant, by certified or registered mail, within 60 days after receipt by the Committee of the application for review; provided, however, that such 60-day period may be extended to 120 days by the Committee if it determines that special circumstances exist which require an extension of the time required for processing the application for review. Such notice shall include specific reasons for the decision and specific references to the pertinent Plan provisions on which the decision is based. 4.4 Any act that the Plan authorizes or requires the Committee to do may be done by a majority of its members. The action of such majority, expressed from time to time by a vote at a meeting or in writing without a meeting, shall constitute the action of the Committee and shall have the same effect for all purposes as if assented to by all members of the Committee at the time in office. 4.5 The members of the Committee may authorize one or more of their number to execute or deliver any instrument, make any payment or perform any other act which the Plan authorizes or requires the Committee to do. 4.6 The Committee may employ counsel and other agents, may delegate ministerial duties to such agents or to employees of the Company and may procure such clerical, accounting, actuarial, consulting and other services as it may require in carrying out the provisions of the Plan. 4.7 The Company shall indemnify and save harmless each member of the Committee against all expenses and liabilities arising out of his or her acts or omissions with respect to the Plan, provided such member would be entitled to indemnification pursuant to the By-Laws of the Company. ARTICLE V Miscellaneous 5.1 The Board may at any time, in its sole discretion, terminate this Plan or amend the Plan in whole or in part. No such termination or amendment shall have the effect of retroactively reducing any benefit, based on a Participant's Benefit Service, Credited Service, and Earnings as of the date of such termination or amendment, or restricting any right of a Participant, retired Participant, Surviving Spouse, or other person or estate entitled to benefits hereunder. 5.2 Nothing contained herein will confer upon any -6- Participant the right to be retained in the service of the Company or any other right not expressly provided for herein, nor will the existence of this Plan impair the right of the Company to discharge or otherwise deal with a Participant. 5.3 This Plan is unfunded for purposes of the Code and ERISA and is not intended to meet the requirements of Section 401(a) of the Code. This Plan constitutes a mere promise by the Company to make benefit payments in the future, and the Participant hereunder shall have no greater rights than a general, unsecured creditor of the Company. 5.4 To the maximum extent permitted by law, no benefit under this Plan shall be assignable or subject in any manner to alienation, sale, transfer, claims of creditors, pledge, attachment or encumbrances of any kind. 5.5 Each Participant shall receive a copy of this Plan and the Committee will make available for inspection by the Participant a copy of any rules and regulations adopted by the Committee in administering the Plan. 5.6 This Plan is established under and will be construed according to the laws of the State of Maine, except to the extent such laws may be preempted by ERISA. IN WITNESS WHEREOF, Central Maine Power Company has caused this document to be executed by its duly authorized officer on this twentieth day of October, 1993. CENTRAL MAINE POWER COMPANY By: Carlton D. Reed, Jr. Chairman of the Board -7- SCHEDULE A Arthur W. Adelberg Senior Vice President, Law and Governmental Relations Richard A. Crabtree Senior Vice President, Customer Services and Division Operations Matthew Hunter President and Chief Executive Officer David T. Flanagan Executive Vice President Donald F. Kelly Senior Vice President, Production, Engineering and Power Supply David E. Marsh Senior Vice President, Finance and Chief Financial Officer EX-13.1 5 MD&A, FIN STATEMENTS & NOTES Exhibit 13-1 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Overview: The Company's earnings per share declined by 11 percent in 1993 to $1.65 from $1.85 in 1992. The return on common equity for 1993 was 9.77 percent versus 11.25 percent earned in 1992. The reduced earnings level for 1993 can be attributed to higher costs, weak sales and cost disallowances associated with two proceedings before the Maine Public Utilities Commission (MPUC) during 1993. The combination of weak sales due to economic and competitive pressures, and a disappointing and inadequate rate-case decision in December 1993, offers the Company no reasonable opportunity to achieve a level of 1994 earnings near the 1993 level or the current allowed rate of 10.05 percent on common equity. The reduction in the Company's earnings capacity for the near term takes into account the significant reductions in previously planned 1994 operation, maintenance, and capital expenditures described later in this section. Service-area kilowatt-hour sales increased by 0.4 percent during 1993. The small increase can be attributed to a weak economic climate, significant competition from alternative fuel sources, energy-management impacts and other factors. On December 14, 1993, the MPUC issued its order in the Company's base-rate proceeding filed in March 1993. The MPUC's analysis of the Company's revenue deficiency indicated a need for additional revenues of $51.5 million, yet found the Company entitled to a net revenue increase of only $26.2 million. The Commission found a total cost of capital of 8.52 percent and a cost of equity of 10.05 percent, after deducting the one-half percent (.5%) return-on-equity penalty it established in the 1993 investigation of the Company's management of certain Independent Power Producer (IPP) contracts. To arrive at its revenue-requirement conclusion, the MPUC deducted $25.3 million "to adjust for management inefficiency" after finding the Company's performance in the areas of management efficiency and cost-cutting to have been "inadequate." In so doing, the Commission noted that "Much of our cost efficiency finding occurs in the context of reviewing the results of the Commission-ordered Management Audit". In issuing that decision, the MPUC disallowed recovery of approximately $2.5 million of previously deferred costs and $1.3 million of previously deferred income-tax-related expenses which, as a result, were reflected as reductions in earnings during the fourth quarter of 1993. The Company strongly disagrees with the MPUC's management- inefficiency finding and with the resulting deduction of nearly one-half the revenue increase to which the Commission itself found the Company to be otherwise entitled using traditional ratemaking principles. The Company has appealed the order to the Maine Supreme Judicial Court. The Company's credit ratings came under significant pressure during 1993 when its senior secured debt was downgraded by all three agencies that rate the Company's securities, one of which -1- dropped the rating to below investment grade. As noted later in this report, the Company's other securities came under even more pressure as the junior securities were, in most cases, assigned non-investment-grade ratings. The decline in the Company's credit ratings will impair its access to the capital markets, will make the terms and conditions of borrowing more stringent and increase the cost of capital, and has substantially reduced, if not eliminated, the Company's access to the commercial-paper markets. The credit-rating agencies cited the stagnant economy, inadequate rate relief and pricing flexibility, increased competition, and uncertainty of recovery of non-utility purchased-power costs as reasons for the credit downgrades. After review of the Company's overall financial position and outlook, including the impacts associated with the MPUC's rate-case order and the expected near-term revenue impacts of weak sales, the Company's Board of Directors voted on December 15, 1993, to reduce the quarterly dividend paid on common stock from 39 cents to 22.5 cents. In response to the business challenges facing the Company, the Company's Board of Directors, in December 1993, approved a broad-based restructuring and rate-stability plan. The rate-stabilizing strategy: 1. Cut in-house operating costs while maintaining service. 2. Cut non-utility power costs, the largest external cost. 3. Work with regulators on innovative, competitive new products and pricing. The first step in implementing the strategy was to eliminate at least 225 full-time equivalent jobs, or 10 percent of the Company's work-force, by March 1994. The Company's operating budget for 1994 was cut $22 million, or 12 percent, from previously planned levels. The 1994 capital budget for plant, equipment, and conservation programs was cut by $14 million, or 19 percent, from previously planned levels. The second component of the plan, reducing the cost of non-utility power, includes continued efforts to renegotiate existing contracts, buy-outs, or contract terminations, and support for Maine legislative action on bills that would have the effect of reducing the cost of non-utility power to our customers. The third component includes continuing Company efforts to achieve changes in regulation that would redefine the basis for overall price changes and provide flexibility in setting specific prices, and in the acquisition and use of resources. As detailed later in this report, the Company has indicated its interest in pursuing a price-cap approach to the regulation of electric rates and, consistent with the terms of the MPUC December 1993 order in the base-rate case, will be filing a plan with the MPUC sometime in the first half of 1994. Earnings in 1993 reflect the January 1993 stipulation that lowered the level of 1993 accruals under the Electric Revenue Adjustment Mechanism (ERAM), and the October 1993 MPUC order in a proceeding reviewing non-utility purchased power contract administration. In that proceeding, the MPUC found that the -2- Company had been unreasonable and imprudent in its management of two contracts and determined it would reduce the Company's allowed rate of return on equity by one-half percent (.5% or approximately $4 million, before income taxes, over a 12-month period) and directed the Company to charge against deferred fuel-cost balances approximately $4.1 million of payments from power providers that had previously been credited against purchased-power capacity costs. The Company recorded a reserve for this order totalling $4.1 million during the third quarter of 1993. The Company not only strongly disagrees with the MPUC findings, but has received an order from the Chief Justice of the Maine Supreme Judicial Court temporarily restraining the MPUC from implementing the rate-of-return penalty pending a decision on the Company's appeal of the MPUC penalty. On February 3, 1994, the MPUC indicated its intent to vacate the penalty portion of the order and to seek an alternative cost-disallowance remedy. The Company cannot predict the outcome of its appeal or the outcome of any alternative remedy imposed by the MPUC, or any appeal from such alternative remedy, or any Maine legislative action. (See Note 3 to Consolidated Financial Statements, "Regulatory Matters - Other MPUC Proceedings," for further information.) The Company's financial objectives for 1994 and beyond include seeking cost reductions and cost control, risk reduction associated with purchased-power contract review proceedings, restructuring prices, achieving pricing flexibility to enhance our ability to compete for sales, and seeking rate recovery of the costs of providing electric service. Our ability to restore earnings to competitive levels and to improve overall financial health depends significantly on meeting these challenges. Our near-term success in reducing the upward pressure on electric rates depends heavily on our ability to reduce our largest cost of service, non-utility generation. While our pricing goal is to lower our inflation-adjusted overall rates by the year 2000, we must continue to focus on improving financial ratios and on regaining lost ground in our credit standing. Achieving acceptable earnings levels for the upcoming year is the most difficult of our financial challenges. Earnings and Dividends: Net income for 1993 was $61.3 million compared to $63.6 million in 1992, and $59.1 million in 1991. Earnings applicable to common stock were $52.5 million or $1.65 per share in 1993, compared to $56.8 million or $1.85 in 1992, and $53.7 million or $1.82 in 1991. Total dividends declared in 1993 were $1.395 per common share, resulting in a cash distribution of 85 percent of current-year common earnings per share. Total dividends per share for 1992 and 1991 were $1.56. In December 1993, the quarterly dividend payment per share of common stock was reduced from $0.39 to $0.225. This reduction reflects current earnings levels and the near-term financial outlook discussed below. Future dividend levels depend on earnings quality and growth, and on other considerations such as changes in capital costs. Revenues and Sales: Electric operating revenues increased by $15.9 million or 2 percent to $893.6 million in 1993, and by $11.2 million or 1 percent to $877.7 million in 1992. The -3- components of the change in electric operating revenues are as follows: (Dollars in millions) 1993 1992 Revenues from kilowatt-hour sales: Total service-area base revenues $15.3 $ 8.7 Fuel cost recoveries 12.3 3.1 Non-territorial base revenues (0.1) 0.1 Revenues from kilowatt-hour sales 27.5 11.9 Other operating revenues: Electric Revenue Adjustment Mechanism, including revenue adjustment-tax flowback (14.6) 3.0 Other, including Maine Electric Power Company, Inc. 3.0 (3.7) Total Change in Electric Operating Revenues $15.9 $11.2
Refer to "Incentive Regulation," "Base Rates," and "Fuel Rates," below, for a discussion of ERAM, the tax-benefit flowback, new rates, and their impact on revenues. The Company's service-area sales for the years 1993, 1992 and 1991 are shown in the following table: (Kilowatt-hours in millions) 1993 1992 1992 KWH % KWH % KWH % change change change Residential 2,884 (3.5)% 2,990 0.4% 2,977 (3.6)% Commercial 2,387 0.9 2,366 1.7 2,327 0.4 Industrial 3,791 3.2 3,672 0.6 3,651 (0.2) Wholesale and lighting 155 0.3 154 2.1 151 0.1 Total Service-Area Sales 9,217 0.4 % 9,182 0.8% 9,106 (1.2)%
Service-area kilowatt-hour sales increased by 0.4 percent in 1993. The primary factors are the continued weak economy, rising electricity prices, energy management, weather conditions, and loss of sales due to conversions from electricity. Sales levels for 1992 rose a modest 0.8 percent from the prior year due to the previously discussed economic conditions, competitive pressures, electricity-price increases and energy-management activities. Residential kilowatt-hour sales decreased in 1993 by 3.5 percent, after increasing by 0.4 percent in 1992 and decreasing by 3.6 percent in 1991. The increase in the average number of residential customers was 4,771 in 1993, 5,657 in 1992, and 5,670 in 1991. Average usage per residential customer declined by 4.5 percent in 1993. The 1993 increase in commercial sales of 0.9 percent reflects a -4- 4-percent increase in the retail sector and a 3.6-percent decrease in the service sector, which combined, comprise approximately 60 percent of commercial sales. Commercial sales had increased by 1.7 percent in 1992 and by 0.4 percent in 1991. Industrial-sales levels are significantly affected by changes in power supplied to the Company's large pulp-and-paper industry customers, who account for approximately 66 percent of industrial sales and approximately 27 percent of total service-area sales. Sales to the pulp-and-paper sector increased by 3.2 percent in 1993, by 0.1 percent in 1992, and by 3.5 percent in 1991. The 1993 increase results primarily from the increased levels of production by many of the Company's customers and purchases of excess energy under newly approved tariffs at lower rates. Sales to all other industrial customers as a group increased by 3.3 percent in 1993 and 1.5 percent in 1992; they decreased 6.8 percent in 1991. Sales to major industrial customers are shown in the following table: (Kilowatt-hours in 1993 1992 1991 millions) Paper and allied products 2,519* 2,441* 2,438* Transportation equipment (shipbuilding) 208 212 202 Chemicals and allied products 182 167 157 Textile mill products 141 134 130 Electrical and electronic machinery 136 151 169 Food products 95 85 85 Lumber and wood products 88 85 86 Leather and leather products 81 77 72
*Totals include sales made under simultaneous-purchase-and-sale contracts related to purchases required under the Public Utilities Regulatory Policy Act of 1978 (PURPA). Non-territorial Sales: On August 2, 1991, the Federal Energy Regulatory Commission (FERC) issued an order requiring the Company to revise its rates to a level reflecting the filed cost of service associated with each of 14 contracts for non-territorial sales, rather than the negotiated market-based levels. Other revenues in 1991 reflect the establishment of a $4.5-million reserve to reflect refunds associated with some of the contracts. Other revenues for 1992 reflect the reversal of approximately $1.9 million of that reserve after a settlement agreement established that the Company would refund approximately $2.6 million related to this issue. The FERC rejected the Company's continuing claims of disparate treatment based on its having been ordered to make refunds while several similarly situated utilities were not. But on September 29, 1993, the FERC rescinded the Company's obligation to make -5- refunds, invoking its "equitable discretion" to declare that it would be "unfair to continue to single out Central Maine for refunds." The FERC order allows the utilities that had shared the $2.6 million in refunds to repay the Company, with interest, over a 24-month period. The utility receiving the largest refund has requested reconsideration of the FERC rescission order. The Company recorded approximately $3.0 million of income during the third quarter of 1993, reflecting the refund including interest. The Company cannot predict the outcome of the other utility's request for reconsideration, or what portion, if any, of the $3.0 million received in 1993, may have to be refunded by the Company. Corporate Restructuring: Maine and the New England region continue to experience a significant economic downturn that began in late 1989. The recession was a significant factor in the small level of growth in total kilowatt-hour sales in 1993 and 1992, and the decline in such sales in 1991. The 1991 decline, the first since 1949, was primarily due to lower usage per customer in the residential-customer class, which represents approximately 31 percent of total service-area sales. Lower sales in recent years have not produced revenues sufficient to cover the cost of service. This has required the Company to seek price increases. However, the state of the economy has made obtaining adequate rate increases difficult. In response to the slow growth in revenues and concerns over the rising price of electricity, the Company undertook cost-control activities beginning in 1991. For example, a reduction of approximately 10 percent in the Company's work force since 1991 and the reduction in functions not critical to safety or service quality were implemented to reduce operation-and-maintenance outlays during 1993, 1992 and 1991. The Company's capital-investment program has also been reduced. Slower growth in the Company's service area has eliminated the need for certain construction projects, while other projects are being deferred. Please refer to the "Overview" section above for a detailed discussion of the Company's current restructuring plans. Incentive Regulation: On May 7, 1991, the MPUC ordered a three-year trial of the Electric Revenue Adjustment Mechanism (ERAM), a fundamental change in the way the Company's revenues were treated, and set new incentives for effective utility-sponsored energy-management. On July 16, 1992, the MPUC issued an order authorizing the Company to begin collecting $7.8 million, which was only a portion of the $26.2 million of ERAM revenues accrued in its first year, and an energy-management incentive of $1.5 million, beginning in September 1992. Approximately $18.4 million of ERAM revenues accrued in the 12 months beginning March 1, 1991, were, therefore, carried over to the 1993 ERAM filing. In January 1993, the MPUC approved a stipulation that resolved several outstanding issues, including those in the Company's ERAM proceeding. The stipulation permitted recovery of accrued ERAM balances in accordance with the terms of an Emerging Issues Task Force consensus. The stipulation also approved an Accounting Order permitting the Company to accelerate the flow-back of $5.9 million of certain deferred taxes associated with prior losses on reacquired debt. -6- For 1992, the stipulation placed a limit of 11.25 percent on the Company's allowed rate of return on equity. Earnings in excess of the limit, up to approximately $10 million (the revenue requirement of the tax benefits), were applied on a monthly basis to reduce 1993 ERAM accruals. The stipulation also reduced the amount of ERAM accruals from January 1993 through November 1993 by $591,000 per month. The ERAM program continued until the effective date of new base rates, December 1, 1993. As contemplated in the January 1993 stipulation, the MPUC approved a revenue increase of $40 million, effective July 1, 1993, which includes, among other things, $21.2 million toward recovery of deferred ERAM revenues. As of December 31, 1993, the Company had collected approximately $19.2 million of the ERAM revenues; the unbilled ERAM balance at that time was approximately $50.5 million. Base Rates: On March 1, 1993, the Company filed a request with the MPUC for a $95-million increase in base rates. The major components of the request were (1) compensating for lower-than-forecasted sales, (2) increased operation-and-maintenance expenses, (3) increased operating costs of the four operating nuclear plants in which the Company owns interests, (4) property additions and transmission, distribution and other improvements, (5) energy-management program costs, and (6) the expiration of the flow-through of certain tax benefits. Ultimately, the Company reduced the amount of its base-rate request from $95 million to $83 million. The decrease was the result of lower estimates of 1994 operation-and-maintenance expenses, further reductions in the Company's cost of capital, a decrease in the level of anticipated expenditures for energy- management programs, and the change in the federal income tax rate from 34 percent to 35 percent. On December 14, 1993, the MPUC issued its order in the proceeding. The MPUC's analysis indicated a need for additional revenues of $51.5 million, yet found the Company to be entitled to a net revenue increase of only $26.2 million. The Commission found a total cost of capital of 8.52 percent and a cost of equity of 10.05 percent, after deducting a one-half percent (.5%) return-on-equity penalty it had established in a 1993 investigation of the Company's management of certain independent power producer contracts. See Note 3 to Consolidated Financial Statements, "Regulatory Matters - Other MPUC Proceedings," for further discussion of this investigation. To arrive at its revenue-requirement conclusion, the MPUC deducted $25.3 million "to adjust for management inefficiency" after finding the Company's performance in the areas of management efficiency and cost-cutting to have been "inadequate". The Company strongly disagrees with the MPUC's management-inefficiency finding and with the resulting deduction of nearly one-half the revenue increase to which the Commission itself found the Company to be otherwise entitled using traditional ratemaking principles. The Company filed an appeal of the base-rate order with the Maine Supreme Judicial Court. The Company cannot, however, predict the result of that appeal. -7- Fuel Rates: In accordance with the January 1993 ratemaking stipulation, the MPUC approved, as part of the $40 million July 1993 revenue increase, $17 million to reduce deferred fuel-clause balances. In July 1992, the MPUC issued an order authorizing an increase, effective September 1, 1992, in the Company's Fuel Cost Adjustment of $13.2 million of the $38.7 million requested by the Company, along with the ERAM and demand-side-management incentives discussed above. The orders extended the smoothing approach that began in 1988, resulting in unrecovered-fuel and purchased-power costs' being deferred for future recovery. The Company has repeatedly expressed concern about the regulators' tendency to defer the recovery of expenses. Rate Stability: In connection with the base-rate proceeding, the Company filed, on July 21, 1993, an alternative rate proposal. The proposal consisted of a combination of pricing and regulatory changes that would, among other things, limit future rate increases to annual changes based on the rate of inflation and mandated costs, and revise existing regulatory rules and policies to allow the Company to adjust prices more rapidly in response to customer needs and competitive factors. In its December 14, 1993 base-rate order, the MPUC ordered that a follow-up proceeding be held to implement, by mid-1994, a rate-stability plan along the lines discussed in the order. The MPUC encouraged the Company and the parties wishing to participate in the proceeding to work together to develop a plan containing price-cap, profit-sharing-and pricing-flexibility components. The MPUC also directed that the initial plan have a duration of five years, subject to a brief annual proceeding to implement any applicable rate changes, and a detailed review at the end of the fourth year to evaluate the performance of the plan and initiate necessary changes. Participants in the rate-stability plan proceeding have prepared price-cap proposals in response to the MPUC's order and discussions are under way. The Company cannot predict the outcome of this process or the MPUC's ultimate decision on price-cap regulation. Deferred Costs: Over the past few years, the amount of deferred charges and regulatory assets has increased under the regulatory policies adopted by the MPUC. The Securities and Exchange Commission has periodically considered issues regarding the proper accounting treatment of charges deferred by regulatory policy. As a result, the Company has regularly requested the MPUC to issue accounting and ratemaking orders to provide appropriate authority to comply with changing accounting requirements and to allow the Company to appropriately reflect the amounts as deferred charges and regulatory assets. In recent years, the Company received such orders with respect to issues in the 1991 Early Retirement Incentive Program, ERAM, purchased-power contract buy-outs, environmental-site cleanup costs, taxes on losses on reacquired debt, accounting for postretirement benefits and income taxes pursuant to the newly issued accounting standards. The Company will monitor situations that result in deferred charges and regulatory assets and will seek appropriate regulatory approvals. Competition: The Company faces competition in several aspects of its traditional business and anticipates that competition will -8- continue to place 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 outside of the Company's service territory have expanded customers' energy options. As a result, the Company has been involved in a number of negotiations with certain customers during 1993 and will continue to pursue retention of its customer base. This increasingly competitive environment has resulted in the Company's entering into contracts with two of its wholesale customers, as well as with certain industrial and commercial customers, to provide their energy needs at prices and margins lower than the current averages. On July 28, 1993, the Town of Madison Electric Works (Madison), a wholesale customer of the Company, announced that it had selected a competitive bid from Northeast Utilities (NU) and was entering negotiations for NU to become its wholesale electric supplier for a period of up to 10 years. The Company's bid was rejected by Madison for being submitted after the 10-day bidding period. NU, a Connecticut-based holding company with substantial excess generating capacity, submitted a bid to provide up to 45 megawatts of capacity at a rate that would initially be well below the Company's existing rates. Substantially all of the 45 megawatts would supply a large paper-making facility in Madison's service territory that has been served directly by the Company under a special service agreement with Madison during the last 12 years. The Company understands that Madison intends to start taking power from NU in late 1994 for that portion required to serve the paper-making facility and in late 1996 for its remaining requirements. Losing Madison as a wholesale customer would reduce the Company's non-fuel revenues by approximately $11 million annually when fully in effect, based on current rates and 1993 sales, minus any amounts paid to the Company for transmission of the NU power from the New Hampshire border. The Company has intervened in opposition to Madison's petition to the MPUC for approval of its contract with NU. The Company cannot predict what action the MPUC will take on the petition. The Company expects to file with the FERC to seek approval of a contract to provide transmission service for Madison from NU, in early 1994. The filing will request recovery of the full cost of providing transmission service as well as a stranded-investment fee to compensate the Company for lost-base revenues. In addition to special agreements with its large customers, the Company is also pursuing with the MPUC alternative pricing mechanisms that would allow the Company the flexibility to modify the price of its product in certain instances, when the competitive alternatives could result in the loss of a significant end use of electricity. In its preliminary discussions, the MPUC has indicated there may be instances in which the ability of the Company to adjust its price in response to competitive pressures is advisable. In February 1994, the MPUC approved a specific plan under which the Company may operate with respect to residential water-heating customers. The Company believes it may be granted the authority to develop additional market-responsive rates in certain circumstances in the future. Rating Agency Actions: Beginning in late August 1993, three major securities-rating agencies lowered their ratings on the -9- Company's outstanding debt and preferred stock on a number of occasions. In October 1993, Duff & Phelps Credit Rating Co. lowered the fixed income ratings as follows: General and Refunding Mortgage Bonds from "BBB+" to "BBB-"; unsecured notes from "BBB" to "BB+"; and preferred stock from "BBB" to "BB-." Standard & Poor's Corp. (S&P) announced, in late October 1993, application of more stringent financial-risk standards to the investor-owned utility industry to reflect S&P's view of mounting business risk. S&P stated that it believed the industry's "credit profile" was being "threatened chiefly by intensifying competitive pressures but also by sluggish demand expectations, slow earnings growth prospects, high common dividend payout, environmental cost pressures, and nuclear operating cost and decommissioning challenges." As a result, S&P revised rating outlooks for about one-third of the industry and placed the Company and several other utilities on "CreditWatch with negative implications." By January 1994, S&P had removed the Company's ratings from "CreditWatch" and lowered them as follows: senior secured debt to "BB+" from "BBB-"; senior unsecured debt to "BB-" from "BB+"; preferred stock to "B+" from "BB"; and commercial paper to "B" from "A-3." In addition, S&P assigned its preliminary "BB+" senior-secured-debt rating to the Company's $150-million General and Refunding Mortgage Bonds recently registered with the Securities and Exchange Commission as a "shelf" registration pursuant to Rule 415 under the Securities Act of 1933. By January 1994, Moody's Investors Service (Moody's) had lowered its rating on the Company's preferred stock to "ba2" from "baa3" and its short-term debt rating for the Company's commercial paper to "Prime-3" from "Prime-2." At the same time, Moody's confirmed its ratings on the Company's General and Refunding Mortgage Bonds at "Baa2", unsecured medium-term notes and pollution control revenue bonds at "Baa3", and the Company's Securities and Exchange Commission "shelf" registration for $150,000,000 of General and Refunding Mortgage Bonds to "(P)Baa2." The rating agencies explained that the downgrades primarily reflect the MPUC's "unsupportive" base-rate decision, which in their opinion will not allow the Company's financial parameters, adjusted for off-balance-sheet obligations, to remain at acceptable levels for a utility with a "below-average" business position. Additionally, the rating agencies expressed the belief that the Company's business position also reflects a depressed Maine economy, a large industrial-customer base, significant purchased-power obligations, relatively high production costs, increasing rate pressures, and a high dividend payout. Financing and Refinancing in 1993: During 1993, the Company continued its program to refinance its outstanding debt to take advantage of the currently low interest rates. The Company issued $75 million of Series Q 7.05% Due 2008 General and Refunding Mortgage Bonds in March, $50 million of Series R 7 7/8% Due 2023 in May, $60 million of Series S 6.03% Due 1998 in August, and $75 million of Series T 6.25% Due 1998 in November. None of these series has sinking funds, and Series S 6.03% Due -10- 1998 and Series T 6.25% Due 1998 are not callable at the option of the Company. The Series Q and Series R bonds are not callable at the option of the Company prior to March 1, 1998, and June 1, 2003, respectively, except under limited circumstances. The Company redeemed its $100-million Series I 9 1/4% Due 2016 in the second quarter of 1993, $50 million of its Series M 9.18% Due 1995 in the third quarter of 1993, and $27.5 million of its Series N 8.50% Due 2001 in the fourth quarter of 1993. Premiums paid on redemptions totalled $9.6 million. These financing and refinancing transactions reduced the annual cost of the Company's mortgage debt to 7.1 percent at December 31, 1993, from 8.5 percent at December 31, 1992. During the year, the Company also raised approximately $25.5 million of additional capital through its Dividend Reinvestment and Common Stock Purchase Plan, resulting in the issuance of 1.2 million new shares of common stock. In 1993, the Company issued $48 million of notes under its $150-million Medium-Term Note program at an average interest rate of 4.8 percent and an average life of 2.9 years. Notes in the amount of $26.5 million matured during the year, increasing the total outstanding notes at year-end 1993 to $146.0 million from $124.5 million at year-end 1992. The proceeds from the debt and equity issuances were used for general corporate purposes, which included financing construction and energy-management projects, retiring or refunding outstanding securities, repaying short-term debt, and buying out purchased-power contracts. Environmental Actions: The Company has been named by the Environmental Protection Agency (EPA) 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 EPA as containing soil contaminated by PCBs from equipment originally owned by the Company. Refer to Note 4 to Consolidated Financial Statements, "Commitments and Contingencies - Legal and Environmental Matters," for a more detailed discussion of this matter. 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 54 percent of total operating expenses in 1993, 53 percent in 1992, and 54 percent in 1991. Purchased-power energy expense includes all costs associated with purchases from non-utility generators. 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. Under current ratemaking practice, changes in fuel expense are provided rate treatment through a fuel clause, with interest being paid to or recovered from customers on over-collected or under-collected balances. Fuel expense for Maine Electric Power Company, Inc. (MEPCO), a 78-percent-owned subsidiary of the Company, is fully recoverable through billing to MEPCO participants and fluctuates with participants' energy requirements. -11- The Company's diverse energy mix held dependence on oil-fired generation to 15.5 percent of 1993 net generation. Diversification of the Company's energy mix has helped mitigate the impact of oil-price changes. However, in recent years, significant amounts of non-utility generation have been purchased and added to the Company's energy mix. The average price of non-utility generators' energy 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 plans to moderate the cost of non-utility generation by continuing to negotiate buy-outs or changes whenever possible, and by supporting legislative action on bills that would promote that objective. To control the price pressure related to purchases from non-utility generators, the Company negotiated contract buy-outs or restructuring with non-utility generators in early 1994, 1993, and 1992. In January 1994, the Company entered into a termination-and-settlement agreement and paid $5 million to terminate a purchased-power contract and dismiss a lawsuit and counterclaims related to the Company's termination of a long-term contract to purchase approximately 80 megawatts of electric power from a cogeneration project proposed for construction by Caithness King of Maine Limited Partnership (Caithness). In the suit, Caithness denied the validity of the Company's termination of the contract and sought damages estimated to be in excess of $100 million for breach of the contract, or in the alternative, reformation of the contract and other legal relief. The contract termination is expected to save approximately $57 million in fuel costs over the next five years. In February 1993, the Company successfully negotiated a buy-out of two long-term contracts with a non-utility generator that is expected to save customers approximately $50 million in fuel costs during the next five years. The Company agreed to pay $11 million to buy out each of the contracts for plants yet to be built that were expected to begin delivering power in 1994 and 1996. The agreement gives the Company the option to decide by mid-1996 whether to pay the $11-million termination fee or have the second plant built to take power delivery by late 1998. The cancelled plants each had a committed capacity of 31 megawatts. The Company has reached agreements in principle to renegotiate 11 long-term hydro contracts. Lower prices for power will enable CMP to save approximately $6 million over the first five years of the contracts. The 11 hydroelectric dams have a combined capacity of 8.7 megawatts. The Company paid approximately $19 million in 1992 to buy-out three long-term contracts, which is expected to save the Company's customers approximately $11 million over the next five years. Additionally, the 1992 contract negotiations reduced existing capacity by approximately 13.4 megawatts. Total buy-outs, restructuring, and terminations made to date are expected to save the Company's customers more than $170 million in fuel costs during the next five years. 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 four Yankee nuclear generating facilities. Effective January 1, 1991, the -12- MPUC approved an accounting and ratemaking methodology whereby the Company charges to expense the cost of Maine Yankee's refueling outages over a nineteen-month period (the estimated time between refueling outages). Purchased-power capacity expense includes $5.0 million, $7.6 million and $6.7 million of such expense in 1993, 1992, 1991, respectively, related to the Maine Yankee outages. The level of purchased-power capacity expense also fluctuates with the timing of the maintenance and refueling outages at the three other Yankee nuclear generating facilities in which the Company has equity interests. The cost of capacity increases during refueling periods. During 1992, Yankee Atomic Electric Company, in which the Company is a 9.5-percent equity owner, discontinued the generation of power and prepared a plan for decommissioning. Purchased-power capacity in 1993 and 1992 contained approximately $5.7 million and $6.9 million, respectively, of costs related to this facility. Refer to Note 6 to Consolidated Financial Statements, "Capacity Arrangements - Power Agreements," for a more detailed discussion of this matter. Operation-and-maintenance expense decreased by $3.2 million in 1993. The reduction reflects the impact of cost-containment practices and certain one-time items. As previously discussed, the MPUC's December 1993 base-rate-case decision required the Company to charge to expense approximately $2.5 million of previously deferred costs. During the fourth quarter of 1992, the Company was required, pursuant to another MPUC decision, to charge to expense approximately $3.5 million of incremental costs related to the cleanup effort after Hurricane Bob, which hit the Company's service territory in 1991. Additionally, as the result of a court decision on responsibility for certain costs incurred in connection with an environmental site, the Company was able to credit $0.8 million to expense for costs charged to expense in prior years which became recoverable from third parties. Cost-control measures instituted in 1991 continued through 1993. Notwithstanding these efforts, 1993 expense included increases reflecting continued costs for mandated energy-management programs and amortization of purchased-power contract buy-out costs and other general cost increases. For 1992, operation-and-maintenance expense increased reflecting the Hurricane Bob charge, increased costs of meeting customer requirements, and costs associated with energy-management programs. Operation-and-maintenance expense for 1993, 1992, and 1991 also reflect the implementation of an early-retirement program accepted by approximately 200 employees in 1991. The Company's overall level of interest expense during 1993 reflects the continued refinancing of General and Refunding Mortgage Bonds at lower interest rates, and the issuance of $49 million in additional notes under the Company's Medium-Term Note program since January 1, 1991. Short-term interest rates over the period 1991 through 1993 fluctuated with the change in the cost and average outstanding balances of short-term debt. The increase in aggregate dividends on preferred stock for the three-year period ended December 31, 1993, is due to the issuance of two series of preferred stock in August 1992. State and federal income taxes fluctuate with the level of -13- pre-tax earnings and the regulatory treatment of taxes by the MPUC. The increase in 1993 is primarily the result of eliminating a one-time accelerated flow-back of $5.9 million of deferred income taxes recorded in 1992 pursuant to the January 1993 stipulation, as discussed under the heading "Incentive Regulation" above and an increase in the federal income tax rate to 35 percent from 34 percent. Additionally, the December 1993 base-rate-case decision discontinued a previously approved policy whereby the Company could defer the impact of Internal Revenue Service audits for recovery in future periods. Liquidity and Capital Resources: As noted above, the MPUC approved increases in base electric rates in 1991, 1992, and 1993, and fuel rates in each of the three years. The new rates produce additional cash. Increases in rates are being used to fund costs of fuel, energy-management programs, operations, maintenance, systems improvements, investments in generation needed to ensure the Company's continued ability to provide reliable electric service, and collection of unbilled revenues recorded pursuant to the ERAM. Approximately $129.0 million of cash was provided from net income before non-cash items, primarily depreciation and deferred taxes. Approximately $62.4 million of cash was applied to fluctuations in working capital and other operating activities, including the financing of deferred energy-management programs, the buy-out of purchased-power contracts, the financing of unbilled fuel and ERAM balances, and depositing funds with the Mortgage Bond Trustee to allow for redemption of outstanding General and Refunding Mortgage Bonds. Proceeds from the Company's Dividend Reinvestment and Common Stock Purchase Plan provided approximately $25.5 million of cash, while the issuance of General and Refunding Mortgage Bonds provided $260 million of cash. The issuance and redemption of Medium-Term Notes provided $21.5 million and short-term obligations used $63 million, respectively, of cash during 1993. Retirements and redemptions of mortgage bonds required $177.5 million of cash resources. Dividends paid on common stock were $49.3 million, while preferred-stock dividends were $8.7 million. The January 1994 record-date dividend on common stock was reduced from $0.39 per share to $0.225 per share. Capital-investment activities, primarily construction expenditures, utilized $56.5 million in cash during 1993. Construction expenditures comprised approximately $6.1 million for generating projects, $3.1 million for transmission, $29.0 million for distribution, and $10.1 million for general construction expenditures. In addition, $5.3 million was used for various capitalized energy-management programs. The Company's construction program for the period 1994 through 1998 has been estimated at approximately $281 million, including an Allowance for Funds Used During Construction of approximately $3 million. Actual construction expenditures will depend upon the availability of capital and other resources, load forecasts, customer growth, and general business conditions. As a result of the recent base-rate case, the Company has reduced its planned 1994 capital-investment outlays to one half of the 1990 amount. -14- During the five-year period, the Company also anticipates incurring approximately $35 million in costs associated with energy-management programs, and $301 million for sinking funds and debt maturities. The Company estimates that for the period 1994 through 1998, internally generated funds from depreciation, deferred taxes, and retained earnings should provide a substantial portion of the construction-program requirements. Current expectations place little reliance on external funding sources to meet the reduced capital expenditure requirements for the next several years. However, the availability at any particular time of internally generated funds for such requirements will depend on working-capital needs. Effective in January 1994, the Company announced that it was electing the option under its Dividend Reinvestment and Common Stock Purchase Plan to purchase shares pursuant to this plan on the market, rather than issue new shares. As a result, current financing plans do not anticipate the issuance of any additional common stock during the next several years. 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, 1993, $146 million of Medium-Term Notes were outstanding, which, pursuant to the terms of the program, permits the issuance of an additional $4 million of such notes. The ultimate nature, timing, and amount of financing of the Company's total construction, refinancing, and energy-management capital requirements will be determined in light of market conditions, the level of earnings and internally generated funds, and other relevant factors. To support its short-term capital requirements, the Company maintains lines of credit totalling $73 million and has an unsecured $50-million revolving-credit agreement with several banks that can be used to support commercial-paper borrowing or as short-term financing. However, as previously discussed, access to commercial paper markets has been substantially reduced, if not eliminated, as a result of downgrading of the Company's credit ratings. Borrowings under lines of credit may be subject to more stringent terms and conditions in the future. The amount of outstanding short-term borrowing will fluctuate with day-to-day operational needs, the timing of long-term financing, and market conditions. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Consolidated Statement of Earnings (Dollars in Thousands, Except Per-Share Amounts) Year Ended December 31 1993 1992 1991 Electric Operating Revenues (Notes 1 and 3) $893,577 $877,695 $866,539 Operating expenses -15- Year Ended December 31 1993 1992 1991 Fuel used for company generation (Notes 1 and 6) 16,906 23,411 28,437 Purchased power - energy (Notes 1 and 6) 408,944 388,599 385,190 Purchased power - capacity (Note 6) 84,520 79,895 77,232 Other operation 148,318 144,126 138,838 Maintenance 33,311 40,749 37,402 Depreciation and amortization (Note 1) 53,138 50,431 47,946 Federal and state income taxes (Note 2) 25,716 18,258 21,685 Taxes other than income taxes 23,023 24,706 23,739 Total Operating Expenses 793,876 770,175 760,469 Equity in Earnings of Associated Companies (Note 6) 5,829 6,688 8,193 Operating Income 105,530 114,208 114,263 Other income (expense) Allowance for equity funds used during construction (Note 1) 1,523 1,633 886 Other, net (673) 1,927 344 Income taxes applicable to other income (Note 2) 3,127 (177) (46) Total Other Income 3,977 3,383 1,184 Income Before Interest Charges 109,507 117,591 115,447 Interest charges Long-term debt (Note 7) 42,266 46,299 47,878 Other interest (Note 7) 6,784 8,844 9,136 Allowance for borrowed funds used during construction (Note 1) (845) (1,135) (701) Total Interest Charges 48,205 54,008 56,313 Net income 61,302 63,583 59,134 Dividends on preferred stock 8,842 6,770 5,479 Earnings Applicable to Common Stock $ 52,460 $ 56,813 $ 53,655 -16- Year Ended December 31 1993 1992 1991 Weighted Average Number of Shares of Common Stock Outstanding 31,789,114 30,630,427 29,508,590 Earnings Per Share of Common Stock $ 1.65 $1.85 $1.82 Dividends Declared Per Share of Common Stock $1.395 $1.56 $1.56 The accompanying notes are an integral part of these financial statements.
Consolidated Statement of Cash Flows (Dollars in Thousands) Year Ended December 31 1993 1992 1991 Operating Activities Net income $ 61,302 $ 63,583 $ 59,134 Items not requiring (providing) cash: Depreciation and amortization 63,647 60,330 58,119 Deferred income taxes and investment tax credits, net 5,584 1,511 3,079 Allowance for equity funds used during construction (1,523) (1,633) (886) Changes in certain assets and liabilities: Accounts receivable (4,881) (26,017) (38,102) Inventories 2,838 1,168 4,467 Other current assets (24,436) (2,184) (2,955) Retail fuel costs (4,349) (1,617) (27,946) Accounts payable 1,338 (11,046) 23,806 Accrued taxes and interest 3,077 1,736 (196) Miscellaneous current liabilities (3,296) 1,506 1,194 Deferred energy-management costs (10,192) (11,183) (9,513) Maine Yankee outage accrual 4,962 (3,122) 6,666 Purchased-power contract buyouts (515) (19,365) - Revenue adjustment-tax flowback (9,990) 9,990 - Other, net (16,932) (6,771) 2,831 Net Cash Provided by Operating Activities 66,634 56,886 79,698 Investing Activities Construction expenditures (53,576) (72,307) (75,609) Investments in associated companies - (885) (259) -17- Year Ended December 31 1993 1992 1991 Changes in accounts payable - investing activities (2,905) (1,932) (905) Net Cash Used by Investing Activities (56,481) (75,124) (76,773) Financing Activities Issuances: Mortgage bonds 260,000 75,000 100,000 Common stock 25,513 24,179 18,397 Medium-term notes 48,000 70,000 20,000 Preferred stock - 75,000 - Redemptions: Mortgage bonds (177,500) (135,000) (121,250) Premiums on redemptions (9,634) (3,212) (2,871) Preferred stock (7,125) (2,750) (1,375) Medium-term notes (26,500) (37,500) (25,000) Short-term obligations, net (63,000) 5,000 56,950 Other long-term obligations, net (868) (874) 5,156 Dividends: Common stock (49,345) (47,566) (45,813) Preferred stock (8,664) (6,115) (5,508) Net Cash Provided (Used) by Financing Activities (9,123) 16,162 (1,314) Net Increase (Decrease) in Cash and Cash Equivalents 1,030 (2,076) 1,611 Cash and cash equivalents, beginning of year 926 3,002 1,391 Cash and Cash Equivalents, end of year $ 1,956 $ 926 $ 3,002 Supplemental Cash-Flow Information: Cash paid during the year for: Interest (net of amounts capitalized) $ 42,870 $ 49,874 $ 54,712 Income taxes 15,852 17,749 18,323 Supplemental Noncash Investing and Financing Activities: New capital lease obligations incurred $ - $ - $ 4,167
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 Balance Sheet (Dollars in Thousands) December 31, -18- Assets 1993 1992 Electric property, at original cost (Notes 6 and 7) $1,564,875 $1,516,945 Less: accumulated depreciation (Note 1) 503,280 474,036 Electric property in service 1,061,595 1,042,909 Construction work in progress (Note 4) 19,689 34,550 Nuclear fuel, less accumulated amortization of $7,242 in 1993 and $6,544 in 1992 1,822 1,899 Net electric property 1,083,106 1,079,358 Investments in associated companies, at equity (Notes 1 and 6) 47,452 46,904 Net Electric Property and Investments in Associated Companies 1,130,558 1,126,262 Current assets Cash and temporary cash investments 1,956 926 Accounts receivable, less allowances for uncollectible accounts of $2,704 in 1993 and $2,250 in 1992: Service - billed 83,330 80,831 Service - unbilled (Notes 1 and 3) 67,022 67,425 Other accounts receivable 10,651 7,866 Undercollected retail fuel costs 84,708 80,359 Prepaid income taxes 1,335 2,488 Fuel oil inventory, at average cost 6,939 8,488 Materials and supplies, at average cost 14,430 15,719 Funds on deposit with trustee 27,758 4,407 Prepayments and other current assets 8,008 6,923 Total Current Assets 306,137 275,432 Deferred charges and other assets (Note 1) Recoverable costs of Seabrook 1 and abandoned projects, net 110,443 113,127 Yankee Atomic purchased-power contract (Note 6) 32,775 38,217 Regulatory assets - deferred taxes (Note 2) 237,387 - Deferred charges and other assets 187,562 136,967 Total Deferred Charges and Other Assets 568,167 288,311 Total Assets $2,004,862 $1,690,005
(Dollars in Thousands) December 31 Stockholders' Investment and Liabilities 1993 1992 Capitalization (see separate statement) (Note 7) Common stock investment $ 553,389 $ 520,368 Preferred stock 65,571 110,571 Redeemable preferred stock 80,000 40,750 Long-term obligations 581,844 499,029 Total Capitalization 1,280,804 1,170,718 Current liabilities and interim financing Interim financing (see separate statement) (Note 7) 68,500 115,000 Sinking-fund requirements (Note 7) 3,421 4,726 Accounts payable 94,417 95,984 -19- Dividends payable 9,468 14,291 Accrued interest 12,680 10,756 Miscellaneous current liabilities 13,137 16,433 Total Other Current Liabilities 133,123 142,190 Total Current Liabilities and Interim Financing 201,623 257,190 Commitments and contingencies (Notes 4 and 6) Reserves and deferred credits Accumulated deferred income taxes (Note 2) 341,349 137,933 Unamortized investment tax credits (Note 2) 36,679 38,511 Yankee Atomic purchased - power contract (Note 6) 32,775 38,217 Regulatory liabilities - deferred taxes (Note 2) 49,734 - Other reserves and deferred credits 61,898 47,436 Total Reserves and Deferred Credits 522,435 262,097 Total Stockholders' Investment and Liabilities $2,004,862 $1,690,005 The accompanying notes are an integral part of these financial statements.
Consolidated Statement of Capitalization and Interim Financing (Dollars in Thousands) December 31 1993 1992 Amount % Amount % Capitalization (Note 7) Common-stock investment: Common stock, par value $5 per share: Authorized - 80,000,000 shares Outstanding - 32,379,937 shares in 1993 and 31,148,321 shares in 1992 $ 161,900 $ 155,742 Other paid-in capital 274,343 254,576 Retained earnings 117,146 110,050 Total Common Stock Investment 553,389 41.0% 520,368 40.5% Preferred Stock - not subject to mandatory redemption 65,571 4.9 110,571 8.6 Preferred stock - subject to mandatory redemption 80,000 42,125 Less: current sinking fund requirements - 1,375 -20- December 31 1993 1992 Amount % Amount % Redeemable Preferred Stock - subject to mandatory redemption 80,000 5.9 40,750 3.2 Long-term obligations: Mortgage bonds 407,500 325,000 Less: unamortized debt discount 2,175 892 Total Mortgage Bonds 405,325 324,108 Medium-Term Notes 146,000 124,500 Other long-term obligations: Lease obligations 42,740 45,204 Pollution-control facility and other notes 34,200 35,068 Total Other Long-Term Obligations 76,940 80,272 Less: Current Sinking Fund Requirements and Current Maturities 46,421 29,851 Total Long-Term Obligations 581,844 43.1 499,029 38.8 Total Capitalization 1,280,804 94.9 1,170,718 91.1 Interim financing, amounts to be refinanced (Note 7): Short-term obligations 25,500 88,500 Current maturities of long-term obligations 43,000 26,500 Total Interim Financing 68,500 5.1 115,000 8.9 Total Capitalization and Interim Financing $1,349,304 100.0% $1,285,718 100.0% The accompanying notes are an integral part of these financial statements.
Consolidated Statement of Changes in Common Stock Investment For the Three Years Ended December 31, 1993 (Dollars in Thousands) -21- Amount Other at Paid-In Par Capital Retained Shares Value Earnings Total Balance - December 31, 1990 28,945,143 $144,726 $223,837 $ 95,142 $463,705 Net income 59,134 59,134 Dividends declared: Common stock (46,200) (46,200) Preferred stock (5,479) (5,479) Cost for reacquired preferred stock 617 (617) - Issues of common stock 1,053,791 5,269 13,128 18,397 Capital stock expense (6) (6) Balance - December 31, 1991 29,998,934 149,995 237,576 101,980 489,551 Net income 63,583 63,583 Dividends declared: Common stock (47,988) (47,988) Preferred stock (6,908) (6,908) Cost for reacquired preferred stock 617 (617) - Issues of common stock 1,149,387 5,747 18,432 24,179 Capital stock expense (2,049) (2,049) Balance - December 31, 1992 31,148,321 155,742 254,576 110,050 520,368 Net income 61,302 61,302 Dividends declared: Common stock (44,459) (44,459) Preferred stock (8,704) (8,704) Cost for reacquired preferred stock 1,043 (1,043) - Issues of common stock 1,231,616 6,158 19,355 25,513 Capital stock expense (631) (631) Balance - December 31, 1993 32,379,937 $161,900 $274,343 $117,146 $553,389
-22- The accompanying notes are an integral part of these financial statements. Note 1 - Summary of Significant Accounting Policies Financial Statements: The consolidated financial statements include the accounts of Central Maine Power Company (the Company) and its 78-percent-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. 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. The Company's approved tariffs provide for the recovery of the cost of fuel used in Company generating facilities and purchased-power energy costs. The Company also collects interest on unbilled fuel and pays interest on fuel-related over-collections. From March 1991 through November 1993, the Company recorded unbilled revenues pursuant to the Electric Revenue Adjustment Mechanism (ERAM) under an MPUC order. See Note 3, "Regulatory Matters - Incentive Regulation," for further information. Depreciation: Depreciation of electric property is calculated using the straight-line method. The weighted average composite rates were 2.9 percent in 1993, 2.9 percent in 1992, and 3.0 percent in 1991. 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 9.8 percent in 1993, 10.2 percent in 1992, and 10.5 percent in 1991. Property Taxes: Effective January 1, 1993, the Company changed its method of accounting for property taxes such that these taxes are accrued monthly during the fiscal period of the taxing entity. Previously, the Company had accrued taxes over a statutory tax year of April to March. The effect of the change was to increase earnings for common stock by $2.7 million or $.09 per share for the year ended December 31, 1993. 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. Deferred costs related to energy-management programs of $43.3 million are being amortized and recovered through rates over periods of five to 10 years, while $9.2 million are deferred for -23- future recovery. Deferred financing costs of $30.1 million are being recovered through rates over periods ranging from three to 30 years. Other deferred amounts totalling $30.8 million are being recovered through rates over periods ranging from 5 to 38 years. In accordance with MPUC accounting orders, deferred charges and other assets include $8.0 million related to environmental-site cleanup and $9.9 million related to postretirement benefits. Refer to Note 4, "Commitments and Contingencies - Legal and Environmental Matters" and Note 5, "Pension and Other Post-Employment Benefits - Other Post-Employment Benefits," for additional discussion of these matters. During 1992, the Company paid approximately $19 million to buy out certain purchased-power contracts, the cost of which was deferred. The MPUC authorized the Company to begin amortization and recovery in rates effective July 1993, over periods of two to 15 years. 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 current ratemaking practices, the deferred taxes related to these recoverable costs are being amortized over periods of four to 10 years. As of December 31, 1993, all deferred taxes related to Seabrook I have been amortized. The recoverable investments as of December 31, 1993, and 1992 are as follows: (Dollars in Thousands) December 31, Recovery Periods Recoverable costs of: 1993 1992 Ending Seabrook 1 $141,084 $141,084 2015 Other projects 57,491 57,491 1995 to 2001 198,575 198,575 Less: accumulated amortization 84,212 73,984 Less: related income taxes 3,920 11,464 Total Net Recoverable Investment $110,443 $113,127
Note 2 - Income Taxes The components of federal and state income taxes reflected in the Consolidated Statement of Earnings are as follows: Year Ended December 31, (Dollars in Thousands) 1993 1992 1991 Federal: Current $ 13,456 $13,087 $13,471 Deferred 37,455 4,187 3,896 Investment tax credits, net (1,832) (1,690) 447 -24- Regulatory deferred (30,224) - - Total Federal Taxes 18,855 15,584 17,814 State: Current 3,549 3,837 5,181 Deferred 10,250 (986) (1,264) Regulatory deferred (10,065) - - Total State Taxes 3,734 2,851 3,917 Total Federal and State Income Taxes $22,589 $18,435 $21,731 Federal and state income taxes charged to: Operating expense $25,716 $18,258 $21,685 Other income (3,127) 177 46 $22,589 $18,435 $21,731
The Company and MEPCO record deferred income-tax expense in accordance with regulatory authority and also defer investment and energy tax credits and amortize them over the estimated lives of the assets that generated the credits. As of December 31, 1993, the Company had fully utilized all investment and energy tax credits generated. Effective January 1, 1993, the Company adopted the provisions of the Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes" (SFAS No. 109). SFAS No. 109 requires recognition of deferred tax liabilities and assets for the expected future tax consequences of events that have been included in the financial statements or tax returns. Under this method, 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. 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 have 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) was able to record 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. The adoption of SFAS No. 109 had no impact on net income. The Company filed a request for an accounting order with the MPUC in 1992 to reaffirm its regulatory policy allowing recovery of amounts for income taxes payable in the future and on August 31, 1993, the MPUC adopted and established for regulatory accounting and reporting purposes the standards required by the FASB in SFAS No. 109. Prior to the implementation of SFAS No. 109, the Company accounted for income taxes using Accounting Principles Board Opinion No. 11. -25- Accumulated deferred income taxes consisted of the following in 1993: (Dollars in Thousands) 1993 Accumulated deferred income taxes, net at January 1, 1993 $297,564 Assets: Investment tax credits, net $ 25,198 Regulatory liabilities 10,191 Alternative minimum tax 4,768 All other 12,095 52,252 Liabilities: Property-related 254,796 Abandoned plant 76,128 Regulatory assets 66,597 397,521 Accumulated deferred income taxes, net at December 31, 1993 $345,269 Accumulated deferred income taxes, recorded as: Accumulated deferred income taxes $341,349 Recoverable costs of Seabrook 1 and abandoned projects, net 3,920 $345,269
A valuation allowance has not been recorded at December 31, 1993, as the Company expects that all deferred income tax assets will be realized in the future. The tax effects of the significant timing differences for the years ended December 31, 1992, and 1991 required to be disclosed pursuant to the accounting standards for income taxes in effect prior to the adoption of SFAS No. 109 are as follows: Year Ended December 31 (Dollars in Thousands) 1992 1991 Federal State Federal State Depreciation $ 7,173 $ (64) $ 9,127 $ (106) Amortization of loss on investments in abandoned projects (6,181) (1,364) (6,147) (1,353) Alternative minimum tax 1,187 - 328 - Energy management costs 2,163 627 1,802 522 Loss on reacquired debt (3,183) (892) 480 140 Hurricane Bob (1,202) (347) 1,202 347 Maine Yankee refueling outage 1,148 331 (2,064) (595) Early retirement programs (364) (113) (1,132) (381) Revenue adjustment-tax flowback (3,063) (981) - - Purchased-power contract buyouts 5,740 1,655 - - Other, net 769 162 300 162 Total Deferred Taxes $4,187 $(986) $3,896 $ (1,264)
-26- The Omnibus Budget Revenue Reconciliation Act of 1993 increased the corporate tax rate from 34 percent to 35 percent effective January 1, 1993. The tax impact on total current and deferred tax expense for the year ended December 31, 1993 was approximately $0.7 million. The additional deferred taxes recorded as a result of the corporate tax rate change were approximately $13.0 million. 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: Year Ended December 31 (Dollars in 1993 1992 1991 Thousands) Amount % Amount % Amount % Income tax expense at statutory federal rate $28,055 35.0 % $26,917 34.0 % $26,162 34.0 % Permanent differences: Investment tax credit amortization (1,613) (2.0) (1,613) (2.0) (1,608) (2.1) Dividend received deduction (1,731) (2.2) (1,920) (2.4) (2,432) (3.2) Other, net (634) (0.8) (585) (0.8) (395) (0.5) 24,077 30.0 22,799 28.8 21,727 28.2 Effect of timing differences for which deferred taxes are not recorded (flow through): Tax basis repairs (1,175) (1.5) (899) (1.1) (1,583) (2.0) Depreciation differences flowed through in prior years 1,728 2.2 2,024 2.5 2,104 2.7 Accelerated flowback of deferred taxes on loss on abandoned generating projects (2,678) (3.3) (2,778) (3.5) (2,808) (3.6) Deduction of removal costs (392) (0.5) (649) (0.8) (1,058) (1.4) Carrying costs, net (523) (0.7) (199) (0.3) 51 0.1 -27- Year Ended December 31 (Dollars in 1993 1992 1991 Thousands) Amount % Amount % Amount % Adjustment to tax accrual for change in rate treatment 481 0.6 - - (150) (0.2) Reduction for non-regulated deferred taxes previously flowed through (1,530) (1.9) - - - - Excess property taxes paid (912) (1.1) 175 0.2 (25) - Accelerated flowback of deferred taxes on loss on reacquired debt - - (4,618) (5.8) - - Accelerated 5-year flowback of certain regulatory deferred taxes - - - - (710) (0.9) Other, net (221) (0.3) (271) (0.3) 266 0.3 Federal Income Tax Expense and Effective Rate $18,855 23.5 % $15,584 19.7 % $17,814 23.2 %
Note 3 - Regulatory Matters Incentive Regulation: On May 7, 1991, the MPUC ordered a three-year trial of the Electric Revenue Adjustment Mechanism (ERAM), a fundamental change in the way the Company's revenues were treated, and set new incentives for effective utility-sponsored energy management. On July 16, 1992, the MPUC issued an order authorizing the Company to begin collecting $7.8 million, which was only a portion of the $26.2 million of ERAM revenues accrued in its first year, and an energy-management incentive of $1.5 million, beginning in September 1992. Approximately $18.4 million of ERAM revenues accrued in the 12 months beginning March 1, 1991, were, therefore, carried over to the 1993 ERAM filing. In January 1993, the MPUC approved a stipulation that resolved several outstanding issues, including those in the Company's ERAM proceeding. The stipulation permitted recovery of accrued ERAM balances in accordance with the terms of an Emerging Issues Task Force consensus. The stipulation also authorized recovery of the costs associated with buy-outs by the Company of certain purchased-power contracts and requested the MPUC to grant an increase in the Company's fuel-cost adjustment. The stipulation also approved an Accounting Order permitting the Company to accelerate the flow-back of $5.9 million of certain deferred taxes associated with prior losses on reacquired debt. For 1992, the stipulation placed a limit of 11.25 percent on the Company's allowed rate of return on equity. Earnings in excess of the limit, up to approximately $10 million (the revenue requirement of the tax benefits), were applied on a monthly basis to reduce 1993 ERAM -28- accruals. Additionally, approximately $317,000 of income, net of income taxes, in excess of the $10 million, was used to fund a portion of 1993 operation-and-maintenance expenses. The stipulation also reduced the amount of ERAM accruals from January 1993 through November 1993 by $591,000 per month. The ERAM program continued until the effective date of new base rates, December 1, 1993. As contemplated by the terms of the January 1993 stipulation, the MPUC approved a revenue increase of $40 million, effective July 1, 1993, which included, among other things, $21.2 million toward recovery of deferred ERAM revenues. As of December 31, 1993, the Company had collected approximately $19.2 million of the ERAM revenues; the unbilled ERAM balance at that time was approximately $50.5 million. Base Rates: On March 1, 1993, the Company filed a request with the MPUC for a $95-million increase in base rates. The major components of the request were (1) compensating for lower-than-forecasted sales, (2) increased operation-and-maintenance expenses, (3) increased operating costs of the four operating nuclear plants in which the Company owns interests, (4) property additions and transmission, distribution and other improvements, (5) energy-management program costs and, (6) the expiration of certain tax benefits. Ultimately, the Company reduced the amount of its base-rate request from $95 million to $83 million. The decrease was the result of lower estimates of 1994 operation and maintenance expenses, further reductions in the Company's cost of capital, a decrease in the level of anticipated expenditures for energy-management programs and the change in the federal income-tax rate from 34 percent to 35 percent. On December 14, 1993, the MPUC issued its order in the proceeding. The MPUC's analysis indicated a need for additional revenues of $51.5 million, yet found the Company to be entitled to a net revenue increase of only $26.2 million. The Commission found a total cost of capital of 8.52 percent and a cost of equity of 10.05 percent, after deducting a one-half percent (.5%) return-on-equity penalty established by the MPUC in a 1993 investigation of the Company's management of certain independent power-producer contracts. See "Other MPUC Proceedings" below, for further discussion of this investigation. To arrive at its revenue-requirement conclusion, the MPUC deducted $25.3 million "to adjust for management inefficiency" after finding the Company's performance in the areas of management efficiency and cost-cutting to have been "inadequate". The Company strongly disagrees with the MPUC's management-inefficiency finding and with the resulting deduction of nearly one-half the revenue increase to which the Commission itself found the Company to be otherwise entitled using traditional ratemaking principles. The Company filed an appeal of the base-rate order with the Maine Supreme Judicial Court. The Company cannot, however, predict the result of that appeal. Other MPUC Proceedings: On October 28, 1993, in connection with a proceeding on independent power-producer contracts, the MPUC issued an order finding that the Company had been unreasonable -29- and imprudent in its management of two independent power-producer contracts and indicated that it would reduce the Company's allowed rate of return on equity by one-half percent (.5%) in the then-pending base-rate case (approximately $4 million, before income taxes, over a 12-month period) and directed the Company to charge against deferred fuel-cost balances approximately $4.1 million of payments from power providers that had previously been credited against purchased-power capacity costs, unless the Company could demonstrate that the crediting was proper. The Company recorded a reserve totalling $4.1 million during the third quarter of 1993, reflecting the impact of the order. Finally, the MPUC announced that it would review in the future the Company's administration and management of certain power-purchase contracts for purchases of 10 megawatts or more. On December 20, 1993, the Chief Justice of the Maine Supreme Judicial Court, acting on the Company's request, issued an order staying the effectiveness of the 0.5-percent return-on-equity penalty pending final resolution of the Company's appeal of the October 28, 1993, MPUC order to the Maine Supreme Judicial Court. In addition, the court ordered that if the Company should not prevail on its appeal, it would be required to refund any revenues collected as a result of the stay order, with interest. Finally, the court ordered an expedited hearing on the appeal, scheduling oral argument before the Maine Supreme Judicial Court for March 1994. Based on that schedule, a decision is expected by early summer 1994. On February 3, 1994, the MPUC filed a Motion to Dismiss with the Court, stating that by order dated February 3, 1994, the Commission had reopened and reconsidered its October 28, 1993 decision. As a result of such reconsideration, the MPUC decided to vacate the return-on-equity penalty conditioned on either the Company's acquiescence in the MPUC's jurisdiction or a finding by the Court that the MPUC retains jurisdiction, and to consider alternative remedies. The MPUC argued that, because of its February 3 order, the Company's appeal of the return-on-equity penalty should be dismissed as moot. The Chief Justice declined to dismiss the appeal and added the jurisdictional question to the issues to be determined by the Court. The MPUC, in its February 3, 1994 order, indicated that an alternative remedy under consideration by the MPUC "appears to present an opportunity to insulate ratepayers sufficiently from CMP's imprudence...," yet also noted, "We do not decide at this time that such a remedy...will be adopted." The MPUC order indicated an intent to seek additional information on the issue of annual differences between the contract rates and avoided costs. The Company cannot predict the outcome of the appeal on either the issue of jurisdiction or the merits of the return-on-equity penalty, nor is it able to predict the outcome of this issue if remanded to the Commission, or any appeal from such alternative remedy or any legislative action. Federal Energy Regulatory Commission: On August 2, 1991, the FERC issued an order requiring the Company to revise its rates to a level reflecting the filed cost of service associated with each of 14 contracts for non-territorial sales, rather than the negotiated market-based levels. Other revenues in 1991 reflect -30- the establishment of a $4.5-million reserve to reflect refunds associated with some of the contracts. Other revenues for 1992 reflect the reversal of approximately $1.9 million of that reserve as a result of a settlement agreement that required the Company to refund approximately $2.6 million related to this issue. After rejection by the FERC of the Company's continuing claims of disparate treatment based on its having been ordered to make refunds while several similarly situated utilities were not, on September 29, 1993, the FERC rescinded the Company's obligation to make refunds. In making its decision, the FERC invoked its "equitable discretion" and agreed that, based on its having granted a general amnesty from refunds to other utilities, circumstances had changed so dramatically since its approval of the Company's 1992 refund settlement that it would be "unfair to continue to single out Central Maine for refunds." The FERC order allows the utilities that had shared the $2.6 million in refunds to repay the Company, with interest, over a 24-month period. The utility that received the major share of the amount refunded by the Company has requested reconsideration of the FERC rescission order. The Company recorded approximately $3.0 million of income during the third quarter of 1993, reflecting the refund including interest. The Company cannot predict the outcome of the other utility's request for reconsideration, or what portion, if any, of the $3.0 million received in 1993, may have to be refunded by the Company. Note 4 - Commitments and Contingencies Construction Program: The Company's plans for improvements and expansion of generating, transmission-and-distribution facilities, and power-supply sources are under continuing review. As part of the Company's cost reduction actions, the general construction budget was reduced by $14 million, and a transmission project of $5 million was deferred for one year. 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 forecasted capital expenditures for the five-year period 1994 through 1998, including AFC of approximately $3 million, are as follows: (Dollars in Millions) 1994 1995 -1998 Total Type of Facilities: Generating projects $11 $48 $ 59 Transmission 7 28 35 Distribution 23 100 123 General 12 52 64 Energy management 7 28 35 Total Estimated Capital Expenditures $60 $256 $316
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 as a potentially responsible party and has been incurring costs to determine the best method of cleaning up an -31- 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 1990, the Company and the EPA signed a negotiated consent agreement, which was entered as an order by the United States District Court for the District of Maine in 1991. The agreement provides for studies, development of work plans, additional EPA review, and eventual cleanup of the site by the Company over a period of years, using the method and level of cleanup selected by the EPA. The Company has been investigating other courses of action that might result in lower costs and, in March 1992, acquired title to the site to pursue the possibility of developing it in a manner that would not require the same method and level of cleanup currently provided in the agreement. The Company also initiated a lawsuit against the original owners of the site and Westinghouse Electric Co. (Westinghouse), which arranged for the equipment disposal, seeking contributions toward past and future cleanup costs. On November 8, 1993, the United States District Court for the District of Maine rendered its decision in the suit, holding that Westinghouse was responsible for 41 percent of the necessary past and future cleanup costs and the former owners 12.5 percent, other than a small amount (less than 5 percent) of such costs not attributable to PCBs, for which Westinghouse was held not responsible and the former owners were held responsible for 33 percent. The Court further concluded that the Company had incurred approximately $3.3 million to that point in costs subject to sharing among the parties. At the same time, the Company has been actively pursuing recovery of its costs through its insurance carriers and has reached agreement with one for recovering a portion of those costs. It has also filed lawsuits seeking such recovery from other carriers. In August 1991, the Company requested permission from the MPUC to defer its cleanup-related costs, with accrued carrying costs, on the basis that such costs are allowable costs of service and should be recoverable in rates. In August 1992, the MPUC issued an order authorizing the Company to defer direct costs associated with the site incurred after August 9, 1991, with accrued carrying costs. Such costs incurred prior to the request were charged to a $3-million reserve established in 1985. Initial tests on the site have been completed and more complex technological studies are still in progress. Based on results to date and on the most likely cleanup method, the Company believes that the remaining costs of the cleanup will total between $7 million and $11 million, depending on the level of cleanup ultimately required and other variable factors. Such estimate is net of the agreed insurance recovery and considers any contributions from Westinghouse and the former owners, but excludes contributions from the insurance carriers the Company has sued, or any other third parties. As a result, in the fourth quarter of 1993, the Company decreased the liability recorded on its books from $14 million, the estimated liability prior to the November 1993 court ruling, to $7 million and recorded an equal reduction in a regulatory asset, established to reflect the -32- anticipated ratemaking recovery of such costs when ultimately paid. Approximately $1 million of costs incurred to date has been charged against the liability. The Company cannot predict the level and timing of the cleanup costs, the extent to which 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. Power Purchase Contract Suit: In December 1992, the Company terminated a 30-year power-purchase contract with Caithness King of Maine Limited Partnership (Caithness) for the purchase of approximately 80 megawatts of electric power from a cogeneration project proposed for construction by Caithness at Topsham, Maine. On March 17, 1993, after legal action was threatened against the Company by Caithness, the Company instituted a declaratory-judgment action against Caithness and certain affiliated entities in the United States District Court for the District of Maine seeking a judicial confirmation of its right to terminate the contract. On April 15, 1993, Caithness filed its response to the action, including counterclaims alleging a breach of the contract by the Company, among other claims, and seeking damages estimated by Caithness to be in excess of $100 million or, in the alternative, reformation of the contract and other legal relief. In January 1994, a termination-and-settlement agreement was reached between the parties, whereby Caithness would terminate the project and release all rights, claims, interests and entitlement thereunder, and the Company would pay Caithness $5 million in consideration. The Company expects to defer this amount and amortize it over the life of the original contract when ultimately allowed in rates. 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 $75.5 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-percent ownership interest in the Millstone 3 nuclear plant, the Company's retrospective premium could be as high as $6 million in any year, for a cumulative total of $45.3 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 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 -33- premiums and the Company's indirect and direct ownership in nuclear generating facilities, this adjustment could range up to approximately $6.3 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. Total pension expense related to these plans amounted to $3.7 million in 1993, $8.1 million in 1992, and $11.1 million in 1991. 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 1991, the Company offered an Early Retirement Incentive Plan (ERIP) to qualifying employees. Approximately 200 employees accepted the offer. The actuarial present value of the ERIP was $12.2 million, of which $3.1 million and $6.7 million were included in pension expense for 1992 and 1991, respectively. The remaining $2.4 million cost was recorded as a deferred charge and is being amortized to expense in 1994 and 1995 in accordance with accounting and ratemaking orders from the MPUC. A summary of the components of net periodic pension cost for the non-union and union defined-benefit plans in 1993, 1992, and 1991 follows: 1993 1992 1991 (Dollars in Non- Non- Non- Thousands) Union Union Union Union Union Union Service cost - benefits earned during the period $2,092 $1,436 $2,344 $1,271 $2,240 $1,252 Interest cost on projected benefit obligation 5,355 3,691 5,709 3,705 5,026 3,207 Return on plan assets (9,669) (6,051) (5,085) (3,198) (14,927) (9,525) Net amortization and deferral 4,419 2,457 351 (104) 10,641 6,484 Early Retirement Incentive Program - - 1,240 1,821 2,727 4,006 Net periodic pension cost $2,197 $1,533 $4,559 $ 3,495 $ 5,707 $ 5,424
Assumptions used in accounting for the non-union and union defined-benefit plans in 1993, 1992, and 1991 are as follows: -34- 1993 1992 1991 Weighted average discount rates 7.5% 8.0% 8.5% Rate of increase in future compensation levels 5.0% 5.5% 7.0% 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, 1993, and 1992: 1993 1992 (Dollars in Thousands) Non- Union Non- Union Union Union Actuarial present value of benefit obligations: Vested benefit obligation $54,837 $41,521 $50,771 $38,194 Accumulated benefit obligation $58,777 $44,674 $53,783 $40,503 Projected benefit obligation $73,674 $50,845 $68,037 $46,293 Plan assets at estimated market value (primarily stocks, bonds, and guaranteed annuity contracts) 80,787 50,007 71,713 45,248 Funded status-projected benefit obligation in excess of or (less than) plan assets (7,113) 838 (3,676) 1,045 Early Retirement Incentive Program deferral (992) (1,457) (992) (1,457) Unrecognized prior service cost (1,724) (1,089) (1,619) (1,169) Unrecognized net gain 15,516 5,529 13,776 5,771 Unrecognized (net obligation) net asset (250) 2,980 (279) 3,304 Net Pension Liability Recognized in the Balance Sheet $ 5,437 $ 6,801 $ 7,210 $ 7,494
Other Post-Employment Benefits: In addition to pension benefits, the Company provides certain health-care and life-insurance benefits for substantially all of its retired employees. In December 1990, FASB issued Statement of Financial Accounting Standards No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" (SFAS No. 106), which the Company adopted effective January 1, 1993. The new standards require the accrual of the expected cost of such benefits during the employees' years of service. The effect of the change can be reflected in annual expenses over the active service life of -35- employees or a period of 20 years, rather than in the year of adoption. The MPUC approved a rulemaking on SFAS No. 106, effective July 20, 1993, for all jurisdictional utilities. The rule adopts the accrual method of accounting and authorizes the establishment of a regulatory asset for the deferral of such costs until they are "phased-in" for ratemaking purposes. 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. Segregation in an external fund will be required for amounts collected in rates. A formal funding plan will be adopted concurrent with the initial recovery in rates. Until then, no return on assets will be reflected in postretirement benefit cost. As a result of the MPUC order, the Company continued to record the cost of these benefits by charging expense in the period paid ($6.5 million in 1993, $5.0 million in 1992, and $3.8 million in 1991), with the excess over that amount in 1993 of $ 9.9 million deferred for future recovery. During 1993, the Company contributed $0.9 million to a Voluntary Employee Benefit Association (VEBA) trust based on an actuarial computation of claims incurred but not paid, as of December 31, 1993. A summary of the components of net periodic postretirement benefit cost for the plan in 1993 follows: (Dollars in Thousands) 1993 Service cost $ 1,429 Interest on accumulated post-retirement benefit obligation 8,352 Actual return on plan assets - Amortization of transition obligation 5,306 Postretirement benefits expense 15,087 Deferred postretirement benefits expense 8,612 Postretirement benefit expense recognized in the income statement $ 6,475
The health-care cost trend rates assume trends ranging from 10.2 percent to 16.1 percent for 1993, reducing to 4.5 percent overall, over a period of eight 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 $1.1 million and the accumulated postretirement benefit obligation by $10.0 million. Additional assumptions used in accounting for the postretirement benefit plan in 1993 are as follows: 1993 Weighted average discount rate 7.5% Rate of increase in future compensation levels 5.5% 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, 1993: -36- (Dollars in Thousands) 1993 Accumulated post-retirement benefit obligation: Retirees $ 73,809 Fully eligible active plan participants 5,559 Other active plan participants 22,880 Total accumulated postretirement benefit obligation 102,248 Plan assets, at fair value 854 Accumulated postretirement benefits obligation in excess of plan assets 101,394 Unrecognized net loss (4,013) Unrecognized transition obligation (87,515) Accrued postretirement benefit cost recognized in the balance sheet $ 9,866
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. 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) and is obligated to pay its proportionate share of the generating costs, which include depreciation, operation-and-maintenance expenses, a return on invested capital, and the estimated cost of decommissioning the nuclear plants at the end of their estimated service lives. Pertinent data related to these power agreements as of December 31, 1993, are as follows: Maine Vermont Connecticut Yankee Yankee Yankee Yankee Atomic* Ownership share 38% 4% 6% 9.5% Contract expiration date 2008 2012 1998 2000 Capacity (MW) 880 519 583 - Company's share of: Capacity (MW) 330 21 35 - Estimated annual costs (1993 costs in thousands) $67,368 $6,469 $13,378 $5,722 Long-term obligations and redeemable preferred stock (thousands) $93,444 $6,413 $12,074 $1,710 *See below for discussion on 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 began collecting $9.1 million annually for decommissioning based on a FERC-approved funding level of $167 million. In January 1994, Maine Yankee filed a Notice of Tariff Change with the FERC to increase its annual collection to $14.9 million and to reduce -37- 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 is 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. Accumulated decommissioning funds were $93.8 million as of December 31, 1993. Condensed financial information of Maine Yankee Atomic Power Company is as follows: (Dollars in Thousands) 1993 1992 1991 Earnings: Operating revenues $193,102 $187,259 $166,471 Operating income 16,580 17,064 20,059 Net income 8,980 9,173 8,863 Earnings applicable to common stock 7,376 8,394 8,369 Company's Equity Share of Net Earnings $ 2,803 $ 3,190 $ 3,180 Investment: Net electric property and nuclear fuel $261,674 $273,195 $288,428 Current assets 36,018 44,149 38,342 Deferred charges and other assets 237,125 203,849 160,111 Total Assets 534,817 521,193 486,881 Less: Redeemable preferred stock 19,800 20,400 6,000 Long-term obligations 218,839 210,754 221,405 Current liabilities 27,887 40,027 46,598 Reserves and deferred credits 201,222 183,095 145,929 Net Assets $ 67,069 $ 66,917 $ 66,949 Company's Equity in Net Assets $ 25,486 $ 25,428 $ 25,441
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 percent of the Company's system capacity. Its 9.5-percent equity investment in Yankee Atomic is approximately $2.3 million. Presently, purchased-power costs billed to the Company, which include the estimated cost of the ultimate decommissioning of the unit, are collected by the Company from its customers through the Company's base-rate structure. On March 18, 1993, the FERC approved a settlement agreement regarding the 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 $32.8 million. This estimate, which is subject to ongoing review and -38- revision, has been recorded by the Company as a regulatory asset and a liability on the accompanying balance sheet. As part of the MPUC's decision in the Company's recent base-rate case, the Company's share of costs related to the deactivation of Yankee Atomic are being recovered through rates based on the most recent projections of costs. Costs incurred to date total $11.0 million. The Company has approximately a 60-percent ownership interest in the jointly owned, Company-operated, 619-megawatt oil-fired W. F. Wyman Unit No. 4. The Company also has a 2.5-percent ownership interest in the Millstone 3 nuclear plant operated by Northeast Utilities, and receives power from its 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, and related accumulated depreciation and amortization attributable to these units as of December 31, 1993, and 1992 were as follows: Wyman 4 Millstone 3 (Dollars in Thousands) 1993 1992 1993 1992 Plant in service and nuclear fuel $115,598 $115,697 $107,713 $106,229 Accumulated depreciation and amortization 53,397 49,846 28,744 24,165
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 percent. The Company is making facilities-support payments on approximately $33.2 million, its share of the construction cost for these transmission facilities incurred through December 31, 1993. These obligations are reflected on the Company's 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. The agreements generally have terms of five to 30 years and require the Company to purchase the energy at specified prices per kilowatt-hour. As of December 31, 1993, facilities having 596 megawatts of capacity covered by these contracts were in service; another 15 megawatts are expected to be added by the end of 1994. The costs of purchases under all of these contracts amounted to $360.7 million in 1993, $341.5 million in 1992, and $332.4 million in 1991. Such costs are recoverable through the Company's fuel clause, after review and approval by the MPUC. -39- In connection with the Company's 1992 Fuel Cost Adjustment proceeding, the MPUC announced it would review the prudence of administration and management of these contracts, as well as the terms and conditions of recent contracts. Refer to Note 3, "Regulatory Matters - Other MPUC Proceedings," for further discussion on this issue. To control the price pressure related to purchases from non-utility generators, the Company negotiated long term contract buy-outs or restructuring with three non-utility generators in 1992, four in 1993, 11 in early 1994, and continues to renegotiate other contracts. The Company incurred buy-out costs of approximately $11.4 million in 1993 and $19 million in 1992. The 1994 renegotiation of prices and contract terms did not require cash payments. Total buy-outs, restructuring, and terminations made to date are expected to save the Company's customers more than $170 million in fuel costs during the next five years. 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, 1993, the Company's retained earnings were $117.1 million, of which $87.5 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. Mortgage Bonds outstanding as of December 31, 1993, and 1992 were as follows: (Dollars in Thousands) Interest Series Redeemed/Maturity Rate 1993 1992 Central Maine Power Company General and Refunding Mortgage Bonds: I 1993-April 1 and June 21 9 1/4% $ - $100,000 M 1993-August 20 and September 27 9.18 - 50,000 S 1998-August 15 6.03 60,000 - T 1998-November 1 6.25 75,000 - O 1999-January 1 7 3/8 50,000 50,000 P 2000-January 15 7.66 75,000 75,000 N 2001-September 15 8.50 22,500 50,000 Q 2008-March 1 7.05 75,000 - -40- R 2023-June 1 7 7/8 50,000 - Total Mortgage Bonds $407,500 $325,000
Limitations on Unsecured Indebtedness: The Company's Articles of Incorporation limit certain unsecured indebtedness that may be outstanding to 20 percent of capitalization, as defined; 20 percent of defined capitalization amounted to $230 million as of December 31, 1993. Unsecured indebtedness, as defined, amounted to $56 million as of December 31, 1993. 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 from time to time 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, 1993, and 1992 were as follows: (Dollars in Thousands) Maturity Interest Rate 1993 1992 Series A: 1992-1995 5.75%-9.58% $ 13,000 $ 39,500 1996-2000 9.35%-9.65 15,000 15,000 Total Series A 28,000 54,500 Series B: 1992-1995 3.625-6.50* 85,000 55,000 1996-2000 4.92%-6.50 33,000 15,000 Total Series B 118,000 70,000 Total Medium-Term Notes $146,000 $124,500 *Includes $10 million of variable rate notes in 1993, with an average interest rate of 3.625%.
Pollution-Control Facility and Other Notes: Pollution-control facility and other notes outstanding as of December 31, 1993, and 1992 were as follows: (Dollars in Thousands) Interest Series Rate Maturity 1993 1992 Central Maine Power Company: Promissory Note 9% June 15, 1993 $ - $ 8 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 -41- Industrial Development Authority of the State 7 3/8% May 1, 2014 11,000 11,000 of New Hampshire Notes 7 3/8% May 1, 2014 8,500 8,500 Maine Electric Power Company, Inc.: Promissory Notes Variable * July 1, 1996 3,450 4,310 Total Pollution-Control Facility and Other Notes $34,200 $35,068
*The average rate was 4.4% in 1993 and 5.0% in 1992. 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. 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 1996 and 2021. The net book value of property under capital leases was $40.0 million and $42.6 million at December 31, 1993, and 1992, 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, 1998, together with the present value of the minimum lease payments are as follows: (Dollars in Thousands) Amount 1994 $ 7,030 1995 6,865 1996 5,719 1997 5,505 1998 5,340 Thereafter 70,815 Total minimum lease payments 101,274 Less: amounts representing interest 58,534 Present Value of Net Minimum Lease Payments $ 42,740
Consolidated sinking-fund requirements for long-term obligations, including capital lease payments and maturing debt issues, for the five years ending December 31, 1998, are as follows: Sinking Maturing (Dollars in Thousands) Fund Debt Total 1994 $ 3,421 $ 43,000 $ 46,421 1995 3,503 55,000 58,503 -42- 1996 3,450 10,000 13,450 1997 1,678 15,000 16,678 1998 1,685 143,000 144,685
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, 1993. 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, 1993 are as follows: (Dollars in Thousands) Carrying Fair Amount Value Cash and temporary investments $ 1,956 $ 1,956 Redeemable preferred stock 80,000 79,450 Mortgage bonds 407,500 407,772 Medium-term notes 146,000 148,132 Pollution-control facility and other notes 34,200 37,253
Anticipated regulatory treatment of the excess of fair value over carrying value of the Company's financial instruments, if in fact settled at amounts approximating those above, would dictate that the excess be used to reduce the Company's rates over a prescribed amortization period. Accordingly, any settlement would not result in a material impact on the Company's financial position or results of operations. Preferred Stock: Preferred-stock balances outstanding as of December 31, 1993, 1992, and 1991 were as follows: Current Shares (Dollars in Thousands, except Out- per-share amounts) standing 1993 1992 1991 Preferred Stock - Not Subject to Mandatory Redemption: $25 par value - authorized 2,000,000 shares; outstanding: None $ - $ - $ - $100 par value noncallable - Authorized 5,713 shares; outstanding: 6% voting 5,713 571 571 571 $100 par value callable - authorized 2,300,000* shares; outstanding: 3.50% series (redeemable at $101) 220,000 22,000 22,000 22,000 -43- 4.60% series (redeemable at $101) 30,000 3,000 3,000 3,000 4.75% series (redeemable at $101) 50,000 5,000 5,000 5,000 5.25% series (redeemable at $102) 50,000 5,000 5,000 5,000 7 7/8% series (optional redemption after 9/1/97, at $100) 300,000 30,000 30,000 - Flexible Money Market Preferred Stock, Series A - (redeemable at $100)** None - 45,000 - Preferred Stock - Not Subject to Mandatory Redemption $65,571 $110,571 $35,571 Redeemable Preferred Stock - Subject to Mandatory Redemption: $100 par value callable - authorized 2,300,000* shares; outstanding: 8.40% series (71,250 shares in 1992 and 98,750 shares in 1991) None $ - $ 7,125 $ 9,875 Flexible Money Market Preferred Stock, Series A - 7.999% (redeemable at $100) 450,000 45,000 - - 8 7/8% series (redeemable at $105.917) (350,000 shares in 1992 and in 1991) 350,000 35,000 35,000 35,000 Redeemable Preferred Stock - Subject to Mandatory Redemption $80,000 $ 42,125 $44,875 *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. **The average rate was 3.35% through November 16, 1993 and 3.45% in 1992.
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 beginning in 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, 1998, is $7,000,000 annually beginning in 1996. On August 27, 1992, the Company issued through a public offering 450,000 shares of Flexible Money Market Preferred Stock, Series A, $100 par value. The annualized dividend rate based on the initial 55-day dividend period rate was 3.25 percent. At the option of the Company, the term of each dividend period subsequent to the initial period was 49 days or longer, subject to certain adjustments. Subsequent dividend rates were set by auction at the end of each dividend period. On November 16, -44- 1993, the Board of Directors voted to fix the dividend at 7.999 percent. 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. Interim Financing: The Company uses funds obtained from short-term borrowing, primarily through issuance of commercial paper backed by lines of credit with commercial banks, and its revolving-credit agreement to provide initial financing for construction and other corporate purposes. As of December 31, 1993, the Company had existing lines of credit totalling $73 million and had an additional $50-million, unsecured revolving-credit agreement with a group of banks described below. Annual fees on the unused portion of the lines of credit are 3/16 of 1 percent. These lines of credit are subject to periodic review and renewal during the year by the banks. Under the terms of these agreements, the Company had outstanding at December 31, 1993, $15.5 million of commercial paper and $10 million of short-term bank notes. As of December 31, 1993, MEPCO had lines of credit totalling $2.5 million with commercial banks to provide for its working-capital needs. These lines of credit are subject to annual review and renewal. Annual fees for the lines of credit range from 3/16 to 1/4 of 1 percent. At December 31, 1993, there was no short-term borrowing outstanding under the MEPCO credit lines. Credit Agreement: In November 1986, the Company entered into an unsecured revolving-credit agreement with several banks providing for loans of up to $40 million. In early 1992, the credit agreement was amended to increase the aggregate principal amount of notes that may be outstanding to $50 million. The agreement is for a three-year period, but may be extended for successive one-year periods with bank approval. With extensions, the agreement is presently scheduled to expire on October 15, 1996. In addition, long-term floating-rate loans outstanding at the termination of the revolving credit phase may be payable two years thereafter, under certain conditions. The Company may borrow at rates, as defined within the credit agreement, based on a Certificate of Deposit loan rate, a Eurodollar loan rate, or the agent bank's reference rate. A commitment fee of 3/16 of 1 percent per annum is paid on the unused portion of the line. Note 8 - Quarterly Financial Data (Unaudited) Unaudited, consolidated quarterly financial data pertaining to the results of operations, which reflect the seasonality of electric sales and higher rates and lower contribution to earnings per kilowatt-hour during peak-consumption periods, are shown below. (Dollars in Thousands, Except Per-Share Amounts) Quarter Ended -45- March June 30 September December 31 31 30 1993 Electric operating revenues $236,021 $198,953 $227,383 $231,220 Operating income 33,298 24,227 21,623 26,382 Net income 21,573 13,702 13,561 12,466 Earnings per common share (1) .62 .37 .36 .31 1992 Electric operating revenues $246,624 $203,822 $207,170 $220,079 Operating income 34,801 28,678 27,423 23,306 Net income 21,521 15,105 15,203 11,754 Earnings per common share (1) .67 .45 .44 .30 1991 Electric operating revenues $229,213 $202,956 $203,126 $231,244 Operating income 30,506 29,569 26,929 27,259 Net income 16,187 15,535 13,583 13,829 Earnings per common share (1) .51 .48 .41 .42 (1) Earnings per share are computed using the weighted average number of common shares outstanding during the applicable quarter.
-46- REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS TO THE SHAREHOLDERS AND THE BOARD OF DIRECTORS OF CENTRAL MAINE POWER COMPANY We have audited the accompanying consolidated balance sheet and consolidated statement of capitalization and interim financing of Central Maine Power Company (a Maine corporation) and subsidiary as of December 31, 1993, and 1992, and the related consolidated statements of earnings, changes in common stock investment and cash flows for each of the three years in the period ended December 31, 1993. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Central Maine Power Company and subsidiary as of December 31, 1993, and 1992, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1993, in conformity with generally accepted accounting principles. As discussed in Notes 2 and 5 to the consolidated financial statements, effective January 1, 1993, the Company changed its methods of accounting for income taxes and other postretirement benefits. ARTHUR ANDERSEN & CO. Boston, Massachusetts February 4, 1994 -47- MANAGEMENT REPORT ON RESPONSIBILITY FOR FINANCIAL REPORTING 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 it 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. A staff of internal auditors conducts comprehensive reviews, provides ongoing assessments of the effectiveness of selective internal controls, and reports 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. Arthur Andersen & Co., 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, President and Chief Executive Officer David E. Marsh, Vice President, Corporate Services, and Chief Financial Officer -48- CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE Change in Independent Accountant On January 19, 1994, on recommendation of the Company's Audit Committee, which had requested proposals from major accounting firms consistent with its policy of periodically reviewing accounting services, the Board of Directors of the Company engaged Coopers & Lybrand as the Company's principal accountant to audit the Company's 1994 financial statements. During 1991, the Company was considering a change in the accounting treatment of deferred investment tax credits. After discussions with the predecessor auditors, Arthur Andersen & Co., who disagreed with the proposed accounting, and with the Office of the Chief Accountant of the Securities and Exchange Commission, the Company rejected the proposed change. Arthur Andersen & Co., has agreed in writing with the information in this section. The 1991 disagreement cited above was discussed with the Audit Committee of the Company by Arthur Andersen & Co. The Company has authorized Arthur Andersen & Co. to respond fully to any inquiries by Coopers & Lybrand concerning the disagreement. During the period of the disagreement neither the Company nor anyone acting on its behalf consulted Coopers & Lybrand regarding any matter. -49- -----END PRIVACY-ENHANCED MESSAGE-----