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
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
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.
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.
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
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
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.
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
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
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
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
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
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,
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
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.
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.
Item 2. PROPERTIES.
Existing Facilities
The electric properties of the Company form a single integrated system which is connected at 345 kilovolts and 115 kilovolts with the lines of Public Service Company of New Hampshire at the southerly end and at 115 kilovolts with Bangor Hydro-Electric Company at the northerly end of the Company's system. The Company's system is also connected with the system of The New Brunswick Power Corporation and with Bangor Hydro-Electric Company, in each case through the 345-kilovolt interconnection constructed by MEPCO, a 78 percent-owned subsidiary of the Company. At December 31, 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
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:
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
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.
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.
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
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:
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
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:
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
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.
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.
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
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
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.
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.
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.
PART II
Item 5.
Item 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
The Company's common stock is traded on the New York Stock Exchange. As of March 21, 1994, there were 35,146 holders of record of the Company's common stock.
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.
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.
Item 7.
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.
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.
Item 9.
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
reference.
PART III
Item 10.
Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
See the information under the heading "Election of Directors" in the registrant's definitive proxy material for its annual meeting of shareholders to be held on May 25, 1994, and Item 4.1, Executive Officers of the Registrant, above, both of which are hereby incorporated herein by reference.
Item 11.
Item 11. EXECUTIVE COMPENSATION.
See the information under the heading "Board Committees, Meetings and Compensation" and the heading "Executive Compensation" in the registrant's definitive proxy material for its annual meeting of shareholders to be held on May 25, 1994, which is hereby incorporated herein by reference.
Item 12.
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
See the information under the heading "Security Ownership" in the registrant's definitive proxy material for its annual meeting of shareholders to be held on May 25, 1994, which is hereby incorporated herein by reference.
Item 13.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
See the information under the heading, "Board Committees, Meetings and Compensation" in the registrant's definitive proxy material for its annual meeting of shareholders to be held on May 28, 1994, which is hereby incorporated herein by reference.
PART IV
Item 14.
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
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.
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.
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
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.
The following report and consent and financial schedules of Central Maine Power Company are filed herewith and included in response to Item 14(d).
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.
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
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
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