-----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, c+Mw6XKAI4QOab3ik2YpJ8KJi2fhwCNp+CbAenvIqOR9mp9zuXC3gNZHbHSfnd0h tIpHT9JWyLChC2hUPOW8Tw== 0000018675-94-000048.txt : 19941116 0000018675-94-000048.hdr.sgml : 19941116 ACCESSION NUMBER: 0000018675-94-000048 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 2 CONFORMED PERIOD OF REPORT: 19940930 FILED AS OF DATE: 19941114 SROS: NYSE 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-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-05139 FILM NUMBER: 94559366 BUSINESS ADDRESS: STREET 1: 83 EDISON DR CITY: AUGUSTA STATE: ME ZIP: 04336 BUSINESS PHONE: 2076233521 10-Q 1 UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-Q (Mark One) X QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended September 30, 1994 OR TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to Commission file number 1-5139 CENTRAL MAINE POWER COMPANY (Exact name of registrant as specified in its charter) Incorporated in 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 offices) (Zip Code) 207-623-3521 (Registrant's telephone number including area code) (Former name, former address and former fiscal year, if changed since last report.) 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 the filing requirements for at least the past 90 days. Yes X No Indicate the number of shares outstanding of each of the issuer's classes of Common Stock, as of the latest practicable date. Shares Outstanding Class as of November 10, 1994 Common Stock, $5 Par Value 32,442,752
Central Maine Power Company INDEX Page No. Part I. Financial Information Consolidated Statement of Earnings for the Three Months Ended September 30, 1994 and 1993 1 Consolidated Statement of Earnings for the Nine Months Ended September 30, 1994 and 1993 2 Consolidated Balance Sheet - September 30, 1994 and December 31, 1993: Assets 3 Stockholders' Investment and Liabilities 4 Consolidated Statement of Cash Flows for the Nine Months Ended September 30, 1994 and 1993 5 Notes to Consolidated Financial Statements 6 Management's Discussion and Analysis of Financial Condition and Results of Operations 20 Part II. Other Information 28
PART I - FINANCIAL INFORMATION Item 1. Financial Statements Central Maine Power Company CONSOLIDATED STATEMENT OF EARNINGS (Unaudited) (Dollars in Thousands Except Per Share Amounts) For the Three Months Ended September 30, 1994 1993 ELECTRIC OPERATING REVENUES $233,543 $227,383 OPERATING EXPENSES Fuel Used for Company Generation 4,614 8,338 Purchased Power Energy 110,944 104,615 Capacity 21,687 25,745 Other Operation 34,921 35,949 Maintenance 8,210 9,402 Depreciation and Amortization 13,992 13,254 Federal and State Income Taxes 8,529 2,804 Taxes Other Than Income Taxes 6,416 7,012 Total Operating Expenses 209,313 207,119 EQUITY IN EARNINGS OF ASSOCIATED COMPANIES 1,422 1,359 OPERATING INCOME 25,652 21,623 OTHER INCOME (EXPENSE) Allowance for Equity Funds Used During Construction 213 427 Other, Net 850 1,440 Income Taxes Applicable to Other Income (Expense) (290) 1,615 Total Other Income (Expense) 773 3,482 INCOME BEFORE INTEREST CHARGES 26,425 25,105 INTEREST CHARGES Long-Term Debt 11,293 10,050 Other Interest 1,176 1,724 Allowance for Borrowed Funds Used During Construction (127) (230) Total Interest Charges 12,342 11,544 NET INCOME 14,083 13,561 DIVIDENDS ON PREFERRED STOCK 2,627 2,099 EARNINGS APPLICABLE TO COMMON STOCK $ 11,456 $ 11,462 WEIGHTED AVERAGE NUMBER OF SHARES OF COMMON STOCK OUTSTANDING 32,442,752 31,916,822 EARNINGS PER SHARE OF COMMON STOCK $0.35 $0.36 DIVIDENDS DECLARED PER SHARE OF COMMON STOCK $0.225 $0.39 The accompanying notes are an integral part of these financial statements.
Central Maine Power Company CONSOLIDATED STATEMENT OF EARNINGS (Unaudited) (Dollars in Thousands Except Per Share Amounts) For the Nine Months Ended September 30, 1994 1993 ELECTRIC OPERATING REVENUES $686,905 $662,357 OPERATING EXPENSES Fuel Used for Company Generation 13,685 14,111 Purchased Power Energy 325,654 299,417 Capacity 56,632 66,491 Other Operation 106,995 108,955 Maintenance 23,035 24,141 Depreciation and Amortization 41,789 39,459 Federal and State Income Taxes 25,988 18,159 Taxes Other Than Income Taxes 19,068 16,672 Total Operating Expenses 612,846 587,405 EQUITY IN EARNINGS OF ASSOCIATED COMPANIES 4,435 4,196 OPERATING INCOME 78,494 79,148 OTHER INCOME (EXPENSE) Allowance for Equity Funds Used During Construction 637 1,311 Other, Net (2,236) 3,000 Income Taxes Applicable to Other Income (Expense) 845 1,571 Total Other Income (Expense) (754) 5,882 INCOME BEFORE INTEREST CHARGES 77,740 85,030 INTEREST CHARGES Long-Term Debt 33,799 31,853 Other Interest 3,520 5,078 Allowance for Borrowed Funds Used During Construction (385) (737) Total Interest Charges 36,934 36,194 NET INCOME 40,806 48,836 DIVIDENDS ON PREFERRED STOCK 7,883 6,459 EARNINGS APPLICABLE TO COMMON STOCK $ 32,923 $ 42,377 WEIGHTED AVERAGE NUMBER OF SHARES OF COMMON STOCK OUTSTANDING 32,442,292 31,629,986 EARNINGS PER SHARE OF COMMON STOCK $1.01 $1.34 DIVIDENDS DECLARED PER SHARE OF COMMON STOCK $0.675 $1.17 The accompanying notes are an integral part of these financial statements.
Central Maine Power Company CONSOLIDATED BALANCE SHEET (Dollars in Thousands) Sept. 30, Dec. 31, 1994 1993 (Unaudited) ASSETS ELECTRIC PROPERTY, at Original Cost $1,570,979 $1,564,875 Less: Accumulated Depreciation 512,741 503,280 Electric Property in Service 1,058,238 1,061,595 Construction Work in Progress 17,035 19,689 Net Nuclear Fuel 1,347 1,822 Net Electric Property 1,076,620 1,083,106 INVESTMENTS IN ASSOCIATED COMPANIES, at Equity 48,130 47,452 Net Electric Property and Investments in Associated Companies 1,124,750 1,130,558 CURRENT ASSETS Cash and Temporary Cash Investments 51,027 1,956 Accounts Receivable, Less Allowances for Uncollectible Accounts of $2,434 in 1994 and $2,704 in 1993 Service - Billed 69,135 83,330 - Unbilled 45,560 67,022 Other Accounts Receivable 6,596 10,651 Prepaid Income Taxes 6,881 1,335 Undercollected Retail Fuel Costs 74,209 84,708 Inventories, at Average Cost Fuel Oil 4,691 6,939 Materials and Supplies 14,024 14,430 Funds on Deposit With Trustee 27,787 27,758 Prepayments and Other Current Assets 12,953 8,008 Total Current Assets 312,863 306,137 DEFERRED CHARGES AND OTHER ASSETS Recoverable Costs of Seabrook 1 and Abandoned Projects, Net 104,092 110,443 Regulatory Assets-Deferred Taxes 240,062 237,387 Yankee Atomic Purchased-Power Contract 28,943 32,775 Deferred Charges and Other Assets 286,815 187,562 Total Deferred Charges and Other Assets 659,912 568,167 TOTAL ASSETS $2,097,525 $2,004,862 The accompanying notes are an integral part of these financial statements.
Central Maine Power Company CONSOLIDATED BALANCE SHEET (Dollars in Thousands) Sept. 30, Dec. 31, 1994 1993 (Unaudited) STOCKHOLDERS' INVESTMENT AND LIABILITIES CAPITALIZATION Common Stock Investment $ 565,319 $ 553,389 Preferred Stock 65,571 65,571 Redeemable Preferred Stock 80,000 80,000 Long-Term Obligations 578,867 581,844 Total Capitalization 1,289,757 1,280,804 CURRENT LIABILITIES AND INTERIM FINANCING Interim Financing 45,000 68,500 Sinking-Fund Requirements 3,339 3,421 Accounts Payable 73,079 94,417 Dividends Payable 9,932 9,468 Accrued Interest 8,622 12,680 Miscellaneous Current Liabilities 13,288 13,137 Total Current Liabilities and Interim Financing 153,260 201,623 COMMITMENTS AND CONTINGENCIES RESERVES AND DEFERRED CREDITS Accumulated Deferred Income Taxes 370,230 341,349 Unamortized Investment Tax Credits 35,470 36,679 Regulatory Liabilities-Deferred Taxes 52,566 49,734 Yankee Atomic Purchased-Power Contract 28,943 32,775 Other Reserves and Deferred Credits 167,299 61,898 Total Reserves and Deferred Credits 654,508 522,435 TOTAL STOCKHOLDERS' INVESTMENT AND LIABILITIES $2,097,525 $2,004,862 The accompanying notes are an integral part of these financial statements.
Central Maine Power Company CONSOLIDATED STATEMENT OF CASH FLOWS (Unaudited) (Dollars in Thousands) (Note 1) For the Nine Months Ended Sept. 30, 1994 1993 CASH FROM OPERATIONS Net Income $ 40,806 $ 48,836 Items Not Requiring (Providing) Cash: Depreciation and Amortization 53,825 46,772 Deferred Income Taxes and Investment Tax Credits, Net 26,511 4,707 Allowance for Equity Funds Used During Construction (637) (1,311) Changes in Certain Assets and Liabilities: Accounts Receivable 39,712 13,349 Other Current Assets (4,974) (28,280) Inventories 2,654 2,048 Retail Fuel Costs 10,499 3,092 Accounts Payable (19,895) 1,737 Accrued Income Taxes and Interest (9,604) (7,658) Miscellaneous Current Liabilities 151 (1,113) Deferred Energy Management Costs (4,017) (4,482) Maine Yankee Outage Accrual (6,247) (6,380) Other, Net 5,255 (8,563) Net Cash Provided By Operating Activities 134,039 62,754 INVESTING ACTIVITIES Construction Expenditures (29,743) (37,798) Changes in Accounts Payable - Investing Activities (1,443) (3,631) Net Cash Used by Investing Activities (31,186) (41,429) FINANCING ACTIVITIES Issuances: Common Stock 927 19,276 Mortgage Bonds 25,000 185,000 Redemptions: Short-Term Obligations, Net (25,500) (7,000) Premium on Redemptions - (8,671) Preferred Stock - (7,125) Mortgage Bonds - (150,000) Other Long-Term Obligations, Net (24,860) (9,368) Dividends: Common Stock (21,916) (36,841) Preferred Stock (7,433) (6,723) Net Cash Used by Financing Activities (53,782) (21,452) Net Increase In Cash and Cash Equivalents 49,071 (127) CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD 1,956 926 CASH AND CASH EQUIVALENTS, END OF PERIOD $51,027 $ 799 The accompanying notes are an integral part of these financial statements.
Central Maine Power Company NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. Summary of Significant Accounting Policies Certain information in footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles has been condensed or omitted in this Form 10-Q pursuant to the rules and regulations of the Securities and Exchange Commission. However, the disclosures herein, when read with the Annual Report on Form 10-K for the year ended December 31, 1993 (Form 10-K), are adequate to make the information presented herein not misleading. 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. The Company's significant accounting policies are contained in Note 1 of Notes to Consolidated Financial Statements in the Company's Form 10-K. For interim accounting periods the policies are the same. The interim financial statements reflect all adjustments that are, in the opinion of management, necessary to a fair statement of results for the interim periods presented. All such adjustments are of a normal recurring nature. For purposes of the statement of cash flows, the Company considers all highly liquid instruments purchased having maturities of three months or less to be cash equivalents. Supplemental Cash Flow Disclosure - Cash paid for interest, net of amounts capitalized, for the nine months ended September 30, 1994 and 1993 amounted to $36.7 million and $38.6 million, respectively. Income taxes paid amounted to $4.2 million and $14.7 million for the nine months ended September 30, 1994 and 1993, respectively. The Company incurred no new capital lease obligations in either period. 2. Commitments and Contingencies Legal and Environmental Matters - The Company is a party in legal and administrative proceedings that arise in the normal course of business. As discussed in Note 4 of Notes to Consolidated Financial Statements in the Company's Form 10-K, in connection with one such proceeding, the Company has been named a potentially responsible party and has been incurring costs to determine the best method of cleaning up an Augusta, Maine, site formerly owned by a salvage company and identified by the Environmental Protection Agency (EPA) as containing soil contaminated by polychlorinated biphenyls (PCBs) from equipment originally owned by the Company. Initial tests on the site have been completed and more complex technological studies are still in progress. Prior to the April 1994 change in the cleanup standard discussed below, the Company believed that its share of the remaining costs of the cleanup would total between $7 million and $11 million, depending on the level of cleanup ultimately required and other variable factors. Such estimate was net of an agreed partial insurance recovery and considered the court-ordered contributions of 41-percent from Westinghouse Electric Co. and 12.5 percent from the former owners, but excluded contributions from the other insurance carriers the Company has sued, or any other third parties. As a result, the Company has recorded an estimated liability of $6 million and an equal regulatory asset, reflecting the anticipated ratemaking recovery of such costs when ultimately paid. On April 8, 1994, the EPA announced changes to the remedy it had previously selected, the principal change being to adjust the soil cleanup standard to ten parts per million from the one part per million established in the EPA's 1989 Record of Decision, on the part of the site where PCBs were found in their highest concentration. The EPA stated that the purpose of adjusting the standard of cleanup was to accommodate the selected technology's current inability to eliminate PCBs and other chemical components on the site to the original standard. On July 11, 1994, the EPA formally approved the previously announced changes. In September 1994, in connection with the 12.5 percent court- ordered contribution from the former owners, the Company agreed to a settlement of all claims against the former owners and received $15,000 as their 12.5 percent share of the cleanup costs. The excess of their share above the $15,000 will be subject to the cost-sharing agreement between the Company and the insurance company. Approximately $2.5 million of costs incurred from August 9, 1991, to date have been deferred. Company believes it is now more probable that its share of the remaining cleanup costs will total near the lower end of its previously estimated range of $6 million to $11 million, based on the selected cleanup method and the new standard, and considering the new level of third-party contributions as described above. The Company cannot predict with certainty the level and timing of the cleanup costs, the extent they will be covered by insurance, or the ratemaking treatment of such costs, but believes it should recover substantially all of such costs through insurance and rates. The Company also believes that the ultimate resolution of the legal and environmental proceedings in which it is currently involved will not have a material adverse effect on its financial condition. 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. On April 4, 1994, the Maine Public Utilities Commission (MPUC) approved a stipulation in which the Company agreed not to seek recovery in rates of the costs incurred pursuant to the termination and buy-out of its purchased-power contract with Caithness. As a result, $4.5 million of costs not previously charged to expense were reflected as a reduction in other income (expense) during the first quarter of 1994. See Note 3, "Regulatory Matters - Maine Public Utilities Commission," for further discussion of the stipulation. 3. Regulatory Matters Maine Public Utilities Commission - Refer to Note 3 of Notes to Consolidated Financial Statements in the Company's Form 10-K for background on the Company's 1993 base-rate proceeding. a. On April 4, 1994, the MPUC approved a stipulation supported by the Company and other parties to an earlier proceeding on independent-power-producer contracts and the Company's 1993 base-rate case. In the stipulation, the Company agreed to write-off $5 million in purchased- power costs, to be implemented through a one-time reduction in its deferred fuel cost balance, and further agreed not to seek recovery in rates of the approximately $5.5 million (of which $4.5 million was deferred) in costs incurred in pursuing the termination and buy-out in January 1994 of its purchased-power contract with Caithness. The Company also agreed to withdraw its appeal to the Maine Supreme Judicial Court (Law Court) of the MPUC's October 1993 order in its power-contract investigation, which will have the effect of increasing the Company's annual base revenues by approximately $4 million, the amount of the stayed one-half percent return-on-equity penalty previously imposed by the MPUC, and to withdraw its appeal to the Law Court of the MPUC's December 1993 decision in the Company's base-rate case. In return, the stipulation provided that the Company would be subject to no further prudence investigation, penalties or disallowances resulting from any actions prior to March 1, 1994, in any respect in connection with the two contracts that were the subject of the MPUC's October 28, 1993 imprudence finding and the Caithness contract. In the stipulation the parties also agreed that any further prudence investigation by the MPUC of the Company's administration of purchased-power contracts before April 4, 1994, would conclude with the issuance of a final MPUC order no later than October 1, 1994. Please refer to section b. below for a discussion of a July 5, 1995 MPUC stipulation approval which resolved the remaining issues related to this matter. Finally, in addition to agreement on procedural matters, the stipulation contained an agreement that the Company would be subject to no further investigation, disallowance or other financially adverse consequence with respect to its administration of its "Capacity Deficiency Fund" and would not be required to flow through to ratepayers any amounts previously recorded to that fund. That provision allowed the Company to reverse, during the first quarter of 1994, the $4.1 million reserve previously credited, in 1993, against its deferred fuel-cost balance. b. On July 5, 1994, the MPUC approved a further stipulation that provides that the Company will not be subject to any further investigations, disallowances, or other financially adverse consequences with respect to its administration prior to March 22, 1994, of the Company's larger Non-Utility Generator's (NUG) contracts (over ten megawatts) totalling approximately 398 megawatts in the aggregate, that were then being investigated by the MPUC. In the approved stipulation the Company also agreed to provide regular reports to the PUC on the status of renegotiation of its high-cost NUG contracts and to postpone current recovery of $0.5 million associated with earned 1991 demand-side-management incentives. The Company further agreed that it would not seek recovery of such deferred incentives if its earned rate of return on common equity exceeds 6.8% in 1994. The Company believes that the PUC's approval of this stipulation resolves another of the complex issues that have been posing risks to the Company since the MPUC's initiation of a general investigation of the Company's administration of NUG contracts by its order of October 28, 1993. c. MPUC Alternative Rate Plan - In its December 14, 1993, base-rate order, the MPUC ordered that a follow-up proceeding to the Company's base-rate proceeding be held to implement by mid-1994 a rate-stability plan (sometimes hereinafter referred to as an "alternative rate plan" or "ARP") along the lines discussed in the order. The MPUC encouraged the Company and the parties electing to participate in the proceeding to work together to develop a five-year plan containing price-cap, profit-sharing, and pricing-flexibility components. The MPUC concluded that such a plan would be likely to provide a number of benefits that would outweigh the potential costs. The Company engaged in discussions with the MPUC staff and other interested parties over several months in an effort to reach a consensus on such a plan. On June 15, 1994, having been unsuccessful in reaching agreement on some of the substantive issues, the Company filed a proposed rate stability plan with the MPUC in a new proceeding, on a schedule calling for a decision on such a plan in late November of 1994. The plan filed by the Company contained an index-based price-setting mechanism, a sharing of excess profits and losses, a pricing flexibility provision, and an annual review procedure, among other provisions, and contemplated an initial term of five years. After hearings and discussions among the parties, on October 14, 1994, the Company filed with the MPUC for its approval a stipulation signed by most of the parties participating in the ARP proceeding, including, among others, the MPUC Staff and the Public Advocate. The stipulation recites that its principal purpose is to offer the MPUC "a single comprehensive Alternative Rate Plan consistent with the objectives and guidance set forth by the [MPUC in its December 14, 1993, base-rate order]." The stipulation also recites that the parties are supporting the five-year ARP for reasons that include ". . . potential benefits such as a higher degree of price stability and predictability, reduced regulatory costs, stronger incentives for cost minimization, the shift of risks away from ratepayers, continuation of comprehensive rate regulation and a form of regulation that will allow CMP needed flexibility to compete in a changing electric utility business environment." The proposed ARP, which is stated in the stipulation to be effective December 1, 1994, contains a price cap mechanism that provides for the Company's retail rates to increase annually on July 1, commencing July 1, 1995, by a percentage combining (1) a price index, (2) a productivity offset, (3) a sharing mechanism, and (4) flow-through items and mandated costs. The price cap would apply to all of the Company's retail rates, including the Company fuel-and-purchased power, which previously had been treated separately. Under the ARP no separate fuel clause price adjustments would occur. A specified standard inflation index would be used for measuring inflation and establishing the basis for each annual price change. The inflation index would be reduced by the sum of two productivity factors, a general productivity offset of 1.0% and a second formula-based offset starting in 1996 intended to reflect the limited effect of inflation on the Company's purchased-power costs during the proposed five-year initial term of the ARP. The sharing mechanism would adjust the subsequent year's July price change in the event the Company's earnings were outside a range of 350 basis points above or below the Company's allowed return on equity, starting at the current 10.55% allowed return and indexed annually for changes in capital costs. Outside that range, profits and losses would be shared equally by the Company and ratepayers. This feature would commence with the price change of July 1, 1996, and reflect 1995 results. The proposed ARP also provides for partial flow-through to ratepayers of cost savings from non-utility generator contract buy-outs and restructuring, recovery of demand- side management costs, penalties for failure to attain customer-service and energy-efficiency targets, and specific recovery of half the costs of the transition to Statement of Financial Accounting Standards No. 106 accounting treatment of post-retirement benefits other than pensions, the remaining 50% to be recovered through the annual price index increase. The proposed plan also generally defines mandated costs that would be recoverable by the Company notwithstanding the index- based price cap. To receive such treatment a mandated cost's revenue requirement must exceed $3 million and must be one that has a disproportionate effect on the Company or the electric power industry. According to the stipulation, such costs might include those arising from special tax, regulatory, and accounting changes, and natural disasters. As part of the stipulation and in order to mitigate price pressures, reduce ratepayer risks and better position itself to achieve timely restoration of competitive financial results the Company agreed that, upon approval of the stipulation, it would take the following before-tax charges against 1994 earnings, at that time: (1) the unrecovered balance of its deferred fuel and purchased-power costs as of December 31, 1994, which the Company estimates will be approximately $57 million; (2) the unrecovered balance of deferred demand-side management costs for 1993 and 1994, which the Company estimates will be approximately $17 million; (3) the unrecovered balance of deferred Electric Revenue Adjustment Mechanism (ERAM) revenues as of December 31, 1994, which the Company estimates will be approximately $24 million; and (4) the unrecovered balance of deferred costs related to the possible extension of the operating life of one of the Company's generating stations, as of December 31, 1994, which the Company estimates will be approximately $2.5 million. On an after-tax basis, these would total approximately $60 million. The proposed ARP would provide the Company the benefits of needed pricing flexibility through the ability to set prices between defined floor and ceiling levels in three service categories: (1) existing customer classes, (2) new customer classes for optional targeted services, and (3) special-rate contracts. The Company believes that the added flexibility will position it more favorably to meet the competition from other energy sources that has eroded segments of its customer base. Some price adjustments could be implemented upon 30 days' notice by the Company, while certain others would be subject to expedited review by the MPUC. The stipulation also contains provisions to protect the Company and ratepayers against unforeseen adverse results from the operation of the ARP. These include review by the MPUC if the Company's actual return on equity falls outside the designated return-on-equity range two years in a row, a mid-period review of the ARP by the MPUC in 1997 (including possible modification or termination), and a "final" review by the MPUC in 1999 to determine whether or with what changes the ARP should continue in effect after 1999. Finally, the stipulation states that the parties consider it to represent an integrated solution to the issues in the ARP proceeding resulting from a balancing of competing interests and objectives and that it will be null and void and not binding on the parties if the MPUC does not accept it without modification. In a statement issued contemporaneously with the filing the Company said the "negotiated ARP required compromises from all parties but preserved a vital balance..." and that it "offered [the Company] the opportunity to act more quickly and competitively in those sectors of our business that are opening to competition, while continuing MPUC oversight of the conduct of our traditional responsibilities." The Company cannot predict whether the MPUC will approve the stipulation or whether, or in what form, an alternative rate plan for the Company will result from the MPUC proceeding. A decision is expected in mid-December 1994. The Company believes that operation under the ARP and the stipulation would continue to meet the criteria of Statement of Accounting Standards No. 71 "Accounting for the Effects of Certain Types of Regulation" (SFAS No. 71). As a result, the Company will continue to apply the provisions of SFAS No. 71 to its accounting transactions and in its future financial statements. d. On July 18, 1994, the MPUC approved a stipulation entered into by the Company and other parties providing for an annual increase of $23.3 million. The increase is primarily for the fuel cost recoveries except for $0.8 million for recovery of non-utility generator contract buyout or restructuring costs and $0.6 million in unrecovered 1991 demand-side management incentives pursuant to the July 5, 1994 purchased-power contract prudence stipulation discussed above. In addition, the approved fuel-related stipulation provided for an expedited approval process for the Company to implement new special-rate contracts with individual customers. The expedited treatment is limited to contracts totaling in the aggregate not more than 45 megawatts of demand and is subject to other eligibility criteria, but the Company believes the new approval process will provide significant flexibility and more rapid price adjustments in meeting the increased competition affecting its customer base. The July 18 stipulation approval also resolved other ratemaking and accounting matters that had been pending before the MPUC. e. In its Orders dated August 5, 1994 and August 18, 1994, the Commission approved a stipulation related to the buyout of the power purchase contract by the Company and acquisition of a 32 MW wood-generating facility located in Fort Fairfield, Maine by the Company's subsequently established subsidiary, Aroostook Valley Electric Company. The stipulation entered into by the Company and other parties provides for a rate decrease of $4 million effective December 1, 1994. The Industrial Energy Consumer Group (IECG) appealed the Commission's Orders and, on September 28, 1994, the parties including the IECG entered into a stipulation which will decrease rates an additional $1.6 million which, combined with the $4 million rate decrease, will decrease rates by $5.6 million effective December 1, 1994. The Company financed the buyout and acquisition through the Finance Authority of Maine (FAME). See "Non-utility Generators" below for a further discussion of the FAME financing. Federal Energy Regulatory Commission - Refer to Note 3 of Notes to Consolidated Financial Statements in the Company's Form 10-K for background information on the Federal Energy Regulatory Commission (FERC) 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. The utility that had received the major share of the amount refunded by the Company pursuant to the original FERC refund order requested reconsideration of the later FERC rescission order. In April, 1994, the FERC approved a settlement agreement filed by the Company and the utility that received the major share of the original amount refunded by the Company, that required the Company to make cash payments of $0.4 million and sales of system power at a discount to that utility. A similar proposal was negotiated with another party and approved by the FERC in July 1994. As a result of these negotiations the Company reflected approximately $0.6 million as a reduction in Electric Operating Revenues during the first quarter of 1994. Non-utility Generators - On April 15, 1994, the Governor of Maine signed into law a bill allowing FAME to borrow up to $100 million to lend to electric utilities for financing buy- outs or other changes in NUG contracts that would save money for customers. The State agency's bonds, which do not pledge the full faith and credit of the state, would nevertheless, with similar terms, be likely to bear lower interest rates than the bonds of the Company with its down-graded credit rating. All agreements under the new law must be approved by the MPUC and must be completed by May 1, 1995. The new law became effective July 14, 1994. On June 9, 1994, the Company announced that it had agreed to buy out a NUG contract for a 33-megawatt wood-fired generating plant in Fort Fairfield, Maine. The Company agreed to pay $76 million to buy out the contract and $2 million to acquire the generating plant, and anticipated savings of approximately $44.5 million based on the future payments that would have been required over the remaining eight-year life of the contract. The buyout is part of the Company's plan to stabilize its rates and improve its competitive position by reducing its own expenses, cutting NUG costs, and achieving pricing reforms from the MPUC. On June 14, 1994, the Company filed an application with the MPUC, under the new law, for a certificate of approval for the Fort Fairfield buyout. Several parties, including the Town of Fort Fairfield, intervened in the MPUC proceeding in opposition to the Company's application, based largely on the adverse local impacts of the contemplated closing of the plant. On August 5, 1994, the MPUC issued an order approving a stipulation entered into by the Company with the Town of Fort Fairfield and other intervenors. In approving the stipulation the MPUC granted its certificate of approval with the statutory findings required for the FAME financing, and provided for recovery in rates of the Company's contractual cost of the buyout. In its negotiated settlement with the Town of Fort Fairfield incorporated in the stipulation, the Company agreed to continue operation of the plant for a minimum of three years, provided that certain plant- efficiency criteria can be met, and the Town agreed to support the Company's efforts to obtain the necessary regulatory and financing approvals, among other considerations. The Company has been engaged in discussions with fuel suppliers and potential purchasers of the output of the plant in an effort to develop the most cost-effective plan for continuing operation of the plant. The MPUC's approval of the stipulation provided for recognition in the Company's future rates of costs expected to be incurred by the Company in the operation of the plant, as well as estimated purchased-power cost savings. During the third quarter of 1994 the Company recorded a $76 million obligation reflecting its agreement to buy out the NUG contract. The cost of this buy-out was reflected as a regulatory asset in accordance with the MPUC's decision to provide future recovery of the amortization of the cost of the buy-out over the original life of the contract. In September 1994, FAME approved the Company's application for funds to finance the buy-out, pursuant to the new Maine law. On October 26, 1994 FAME issued $79.3 million of Taxable Electric Rate Stabilization Revenue Notes Series 1994A (FAME Notes). FAME and the Company entered into a Loan Agreement under which the Company issued FAME a Note for approximately $66.4 million, (Company Note) evidencing a loan in that amount. The proceeds of the loan, along with $13 million of the Company's own funds, were used to buy out the Fort Fairfield contract. Interest on the Company Note is paid semi-annually each January 1 and July 1 at an annual interest rate of 8.16%. The Company Note calls for only interest payments for the first two years of the note followed by annual sinking-fund payments from January 1, 1987 through maturity in 2005. The Notes are not subject to redemption prior to maturity. The remaining $12.9 million of FAME Notes' proceeds were placed in a Capital Reserve Account. The amount in the Capital Reserve Account is equal to the highest amount of principal and interest on the FAME Notes to accrue and come due in any year the FAME Notes are outstanding. The amounts invested in the Capital Reserve Account were initially invested in money-market accounts. Under the terms of the Loan Agreement, the Company is also responsible for or receives the benefit from the interest rate differential and investment gains and losses on the Capital Reserve Account. In connection with the buy-out and related purchase of the generating facility in Fort Fairfield, in October 1994 the Company formed a wholly-owned subsidiary, Aroostook Valley Electric Company (AVEC), to own and operate the Fort Fairfield generating facility in accordance with the terms of the stipulation discussed above. The Company purchased all of the common stock of AVEC for $2 million. On October 26, 1994, AVEC paid the former owners of the Fort Fairfield facility $2 million and took title to the facility. In connection with the FAME financing, AVEC granted FAME a mortgage on the facility. During the third quarter of 1994, the Company reached agreement with three additional NUGs which give the Company options to restructure their contracts through periodic payments, of which approximately $30 million was reflected as an obligation during the third quarter of 1994. These buy- outs represent 79 megawatts of capacity and should result in savings of approximately $39 million over the next five years. Wholesale Customer - As previously reported, 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. 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 the large paper-making facility of Madison Paper Industries (MPI) 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. Madison proposed to start taking power from NU in late 1994 for that portion required to serve MPI and in late 1996 for its remaining requirements. On May 16, 1994, the Company, Madison and NU entered into a settlement agreement that resolved, subject to regulatory approvals, all issues in dispute among the parties relating to Madison and MPI. Under the agreement, which was filed with the MPUC as part of a stipulation among the parties to the agreement and other intervenors in the MPUC proceeding, the related MPUC and FERC regulatory proceedings were deemed to be settled among the parties, and the Company withdrew its request for compensation for stranded investment. In return, NU agreed to pay the Company $8.4 million over a seven-year period, MPI agreed to pay the Company $1.4 million over a three-year period, a transmission rate was agreed upon for the Company's transmission service to Madison commencing September 1, 1994, and the parties agreed that Madison would be supplied by NU through 2003, with Madison having an option for an additional five years. In addition, NU and the Company agreed to a five-year capacity exchange arrangement designed to achieve significant replacement power cost savings for the Company when the Company's largest source of generation, the Maine Yankee Atomic Power Company plant, is off-line. On May 26, 1994, the MPUC approved the stipulation. The agreement must also be approved by the FERC. The agreement provides more economic benefit to the Company than if it had under-bid NU for Madison's business, but less than if Madison stayed on the Company's system at the former rates. The Company will record the amounts received under this contract as the amounts are received. As discussed above, the MPUC, in its July 1994 Order in the Company's Fuel Cost Recovery proceeding, required the Company to allocate the cash payments, the capacity exchange savings and the transmission revenues 60% to base non-fuel revenues and 40% to fuel revenues. Madison is the largest of the Company's three wholesale customers. The Company has reached agreement with its other two wholesale customers to continue to supply them at negotiated prices and margins that are lower than the previous averages. Residents of several small areas in the Company's service territory have publicly expressed interest in investigating the feasibility of organizing local electric utility districts for the purpose of providing their own electric service with power purchased from a selected supplier. Four Maine communities voted on November 8, 1994 on questions regarding the creation of municipal electric districts. In three of the towns, Westbrook, Norway and Old Orchard Beach, the proposals were defeated. The fourth, Jay, voted to create a district, and must, if the town's further investigation indicates that pursuing a district is feasible, obtain the approval of the MPUC before furnishing utility service. The Company believes that such actions are not in the best interests of either its customers or its investors and will strongly oppose them. The Company further believes that formidable obstacles will be encountered by Jay or any other group in attempting to implement the formation of such districts, including obtaining the required findings by the MPUC and economically acquiring or constructing the necessary facilities for a local utility system. The Company cannot, however, predict the ultimate results of such initiatives. 4. Capitalization and Interim Financing On September 28, 1994, the Board of Directors of the Company adopted a shareholder rights plan and declared a dividend of one common share purchase right (a Right) for each outstanding share of the common stock, par value $5.00 per share, of the Company (the Common Shares). The dividend was distributed to the shareholders of record as of the close of business on October 17, 1994. Each Right entitles the registered holder to purchase from the Company, one Common Share at an initial purchase price of $40 per Common Share, subject to adjustment. The Rights become exercisable or transferrable apart from the Common Shares, ten business days following a public announcement that a person or group has acquired beneficial ownership of, or commences a tender or exchange offer for, 20% or more of the outstanding Common Shares (acquiring person). The holder of each right not owned by the acquiring person would be entitled to purchase Common Shares having a market value equal to two times the exercise price of the Right (i.e., at a 50% discount). The purchase price payable and the number of Common Shares issuable upon exercise of the Rights are subject to adjustment from time to time and under certain circumstances. The Rights will expire on the earlier of (i) the close of business on October 31, 2004, (ii) the time at which the Rights are redeemed by the Company or (iii) the time at which the Rights are exchanged for Common Shares at an exchange ratio of one Common Share per Right, as adjusted by the Company. At any time prior to a person or group acquiring 20% or more of the outstanding common stock, the Board of Directors of the Company may redeem the then outstanding Rights in whole, but not in part, at a price of $.01 per Right, subject to adjustment. The redemption of the rights may be made effective at such time, on such basis and with such conditions as the Board of Directors in its sole discretion may establish. Immediately upon any redemption of the Rights, the right to exercise the Rights will terminate and the only right of the holders of Rights will be to receive the redemption price. The terms of the Rights may be amended by the Board of Directors of the Company without the consent of the holders of the Rights, including, an amendment to lower the threshold for an Acquiring Person from 20% to not less than the greater of (i) any percentage greater than the largest percentage of the outstanding Common Shares then known by the Company to be beneficially owned by any Person and (ii) 10%. 5. Income Taxes The effective federal income tax rate for the year ended December 31, 1993 was 23.5%. For the three and the nine months ended September 30, 1994 the effective federal tax rates were 33.4% and 33.8%, respectively. Federal and state income taxes fluctuate with the level of pre-tax earnings and the regulatory treatment of taxes by the MPUC. Certain tax benefits which were reflected as a reduction in tax expense in the earlier year expired and, therefore, were not available to reduce tax expenses in the current periods. Item 2: Management's Discussion and Analysis of Financial Condition and Results of Operations Operating Results Operating revenues increased by $24.5 million or 3.7 percent to $687 million in the first nine months of 1994 from $662 million in the first nine months of 1993. Operating revenues for the third quarter of 1994 of $234 million were 2.7 percent more than the third quarter of 1993. Revenues reflect rate increases as a result of the 1993 base rate case, fuel and Electric Revenue Adjustment Mechanism (ERAM) decisions and a stipulation approved by the Maine Public Utilities Commission (MPUC) in April 1994. Net Income for the third quarter of 1994 was $14.1 million compared to $13.6 million for the third quarter of 1993. Year- to-date Net Income in 1994 was $40.8 million compared to $48.8 million for the corresponding period in 1993. Earnings applicable to Common Stock were $11.5 million or $0.35 per share for the three months ended September 30, 1994 and $11.5 million or $0.36 per share for the comparable period in 1993. Year-to- date earnings applicable to Common Stock in 1994 were $32.9 million or $1.01 per share and $42.4 million or $1.34 per share in 1993. Weak sales due to economic and competitive pressures, the impact of a disappointing rate case decision in December 1993, higher taxes and the April 1994 stipulation discussed below, are the primary factors affecting the decline in year-to- date earnings. Average shares outstanding increased due to the issuance of 0.4 million shares since September 1993 through the Company's Dividend Reinvestment and Common Stock Purchase Plan. Effective January 1994, the Company elected to purchase shares pursuant to the plan on the market, rather than issue new shares. The combination of low sales growth on a year-to-date basis, due to economic and competitive pressures, and an inadequate rate case decision in December 1993, offer the Company no reasonable opportunity to achieve a level of 1994 earnings near the 1993 level or its currently allowed rate of 10.55 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. The Company continues its objectives of seeking cost reductions and cost control, restructuring prices, achieving price flexibility to enhance its ability to compete for sales and seeking rate recovery of the costs of providing electric service. In another move towards this goal, the Company and other parties have filed a stipulation with the MPUC proposing an Alternate Rate Plan that would limit annual price increases with an inflation-based index and provide the Company with pricing flexibility. The Alternate Rate Plan, which is discussed in Note 3 to Consolidated Financial Statements, if approved, would result in the recognition, at the time of approval, of certain charges that would result in a net loss for the current year. As discussed further in Note 3 to Consolidated Financial Statements "Regulatory Matters - Maine Public Utilities Commission," on April 4, 1994, the MPUC unanimously approved a negotiated settlement of a two-year-old dispute over the Company's administration of contracts with non-utility generators (NUGs). The stipulation required a one-time $5 million write-off of unrecovered fuel costs, precluded recovery of $4.5 million of the costs of terminating the Caithness King NUG contract and permitted retention of $4.1 million of payments associated with the capacity deficiency fund. As a result, earnings for the nine months ended September 30, 1994 reflect a net reduction of $3.5 million before taxes, or approximately $2.0 million or $0.06 per share after taxes. During the first twelve months, the stipulation will result in a net reduction in earnings of $1.5 million before taxes, or approximately $900,000 or $0.03 per share after taxes. The Company believes that the approval of the stipulation by the MPUC resolved or limited a number of complex issues that were posing significant risks to the Company. Service-area sales of electricity totaled approximately 7.0 billion kilowatt-hours for the nine-month period ended September 30, 1994, an increase of 0.8% over the first nine months of 1993. Service-area sales for the third quarter of 1994 totaled approximately 2.3 billion kilowatt-hours, which were 0.4 % more than the third quarter of 1993. Service Area Kilowatt-hour Sales (Millions of KWHs) Period Ended September 30, Three Months Nine Months % 1994 1993 % Change 1994 1993 Change Residential 653.5 645.7 1.2% 2,196.2 2,191.7 0.2% Commercial 651.1 624.7 4.2 1,871.8 1,801.4 3.9 Industrial 966.1 990.9 (2.5) 2,827.8 2,849.2 (0.8) Other 37.1 38.1 (2.7) 116.2 115.6 0.4 Total 2,307.8 2,299.4 0.4% 7,012.0 6,957.9 0.8%
The changes in service area kilowatt-hour sales reflect the following: Kilowatt-hour sales to residential customers increased by 1.2% in the third quarter and 0.2% for the nine months ended September 30, 1994 compared to 1993; while the number of customers increased approximately 1%, usage per customer was down 0.8%, with a decline in the space and water heating subclass usage continuing during the first nine months of 1994. Commercial sales increased by 4.2% in the third quarter and 3.9% for the nine months ended September 30, 1994 from 1993 due primarily to increases in the service, retail and wholesale sectors' usage while sales in the other sectors increased also. Sales to the service sector comprise approximately 31% of the Company's commercial sales. Industrial kilowatt-hour sales decreased by 2.5% in the third quarter and 0.8% for the nine months ended September 30, 1994 over 1993. Sales to the pulp and paper industry decreased by 2.8% for the third quarter and by 1.2% year- to-date 1994. The decline in sales on a quarterly and year-to-date basis to this industry was due primarily to higher than normal purchases in January 1993, and the addition of 10 megawatts of generation by one customer in March 1993 and, as discussed in Note 3 to Consolidated Financial Statements "Regulatory Matters - Wholesale Customer", Madison Paper Industries going off the Company's system beginning in September 1994. The pulp and paper industry accounts for approximately 60% of the industrial sales category. A sales increase of 0.2% over the first nine months of 1993 occurred to all other industrial customers as a group. The components of the change in electric operating revenues for the nine months ended September 30, 1994, as compared to the same period in 1993, are as follows: Three Nine Months Months (Dollars in Millions) Revenues from Kilowatt-hour Sales: Total Service-Area Base Revenue $ 8.0 $ 22.9 Fuel Cost Recoveries 3.1 20.8 Non-Territorial Base Revenue 0.7 1.9 Revenues from Kilowatt-hour Sales 11.8 45.6 Other Operating Revenues: Electric Revenue Adjustment Mechanism Including Revenue Adjustment-Tax Flowback (3.3) (17.8) Other, including Maine Electric Power Company, Inc. (2.3) (3.3) Total Change in Electric Operating Revenues $ 6.2 $ 24.5
Total service-area base revenues increased for the third quarter and first nine months of 1994 reflecting slightly higher kilowatt-hour sales, the July 1993 increase in rates to continue collection of accrued ERAM revenue and the increase of $26.2 million pursuant to the MPUC's base rate case decision effective December 1, 1993. Fuel Revenue increases reflect a fuel cost adjustment increase effective August 1, 1994 of $21.9, annually, and the changes discussed below relating to Fuel Used for Company Generation and Purchased-Power Energy expense. Other revenues reflect the elimination of ERAM accruals, effective December 1, 1993. The Company's Fuel Used for Company Generation and Purchased Power-Energy expenses are recoverable through approved fuel tariffs while Purchased Power-Energy incurred by Maine Electric Power Company, Inc. (MEPCO) is billed to MEPCO's Participants. The Company's Fuel Used for Company Generation, which consists primarily of Company-owned oil-fired generation, decreased by $3.7 million in the third quarter of 1994 over the third quarter of 1993 and by $0.4 million for the nine-month period ended September 30, 1994. Compared to 1993, total oil-fired megawatt- hour generation decreased by 45.3% in the third quarter of 1994 but increased by 5.2% year-to-date 1994. The cost of this generation on a per megawatt-hour basis was 3.2% lower for the third quarter and 9.0% lower for the nine months ended September 30, 1994, as a result of decreases in the price of oil purchased. The Company's Purchased Power-Energy expense increased by $6.3 million in the third quarter and by $26.2 million for the nine months ended September 30, 1994 due primarily to purchases from non-utility generators. Total megawatt-hour purchases increased by 32 megawatt-hours and 160 megawatt-hours over the prior year quarter and prior year-to-date. The cost of this energy on a per megawatt-hour basis increased by 3.2% for the third quarter and by 5.4% for the first nine months of 1994, respectively, primarily due to pre-set price increases. Purchased-Power Capacity expense decreased $4.1 million and $9.9 million when compared to the third quarter and the nine months ended September 30, 1993. The decrease is primarily related to the $4.1 million reserve recorded during the third quarter of 1993 to reflect the expectation, at that time, that the Company would be required to refund that amount of "Capacity Deficiency Fund". The reserve was reversed during the first quarter of 1994. See the further discussion of this matter in Note 3 to Consolidated Financial Statements "Regulatory Matters - Maine Public Utilities Commission". Other Operation and Maintenance expenses decreased by $2.2 million and $3.1 million compared to the third quarter and first nine months of 1993. Despite reflecting severance costs associated with restructuring plans in early 1994 which eliminated 225 full-time equivalent positions, increases in expenses of the Electric Lifeline Program (the MPUC-mandated low- income energy assistance program) and other planned cost increases, ongoing cost control activities directed toward limiting growth in this area are continuing. Federal and state income taxes fluctuate with the level of pre- tax earnings and the regulatory treatment of taxes by the MPUC and increased by $7.6 million and $8.6 million for the third quarter and year-to-date 1994, respectively. Certain tax benefits which were reflected as a reduction in tax expense in the earlier year expired and therefore were not available to reduce tax expenses in the current periods. Interest on long-term debt increased $1.2 million for the third quarter of 1994 and $1.9 million for the nine months ended June 30, 1994 while other interest expense decreased by $0.5 million and $1.6 million for the third quarter and year-to-date period ended September 30, 1994, respectively. These changes are the result of converting short-term borrowing into long-term debt and an increase in total debt outstanding and slightly higher overall interest rates. Liquidity and Capital Resources Approximately $120.5 million of cash was provided during the first nine months of 1994 from net income before non-cash items, primarily depreciation and amortization. During such period, approximately $13.5 million of cash was provided by fluctuations in certain assets and liabilities and from other operating activities. In April 1994, the Company issued $25 million of Series U 7.45% (Adjustable Rate) General and Refunding Mortgage Bonds, due 1998, through a private placement. The Series U Bonds do not have a sinking fund requirement and are redeemable at the option of the Company under certain circumstances. Also during the first nine months of 1994 the Company reduced the level of short-term borrowing outstanding by $25.5 million and reduced the level of other long-term obligations by $24.9 million. Dividends paid on common stock were $21.9 million, while preferred-stock dividends utilized $7.4 million of cash. Refer to Note 3 to Consolidated Financial Statements, "Regulatory Matters - Non-Utility Generators", for a discussion of the financing entered into with the Finance Authority of Maine related to the buy-out of one of the Company's non-utility generator contracts. Investing activities, primarily construction expenditures, utilized $31.2 million in cash during the first nine months of 1994 for generating projects, transmission, distribution, and general construction expenditures. In order to accommodate existing and future loads on its electric system the Company is engaged in a continuing construction program. The Company's plans for improvements and expansions, its load forecast and its power resources are under a process of continuing review. Actual construction expenditures will depend upon the availability of capital and other resources, load forecasts, customer growth and general business conditions. In June 1994, the Company entered into an agreement with a large institutional investor under which the investor agreed to purchase from the Company up to $25 million of additional General and Refunding Mortgage Bonds on or before April 15, 1995, subject to certain terms and conditions. Bonds issued pursuant to the agreement must be due on or before April 15, 1998. The ultimate nature, timing and amount of financing for the Company's total construction programs, refinancing and energy-management capital requirements will be determined in light of market conditions, earnings and other relevant factors. To support its short-term capital requirements, the Company maintains 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, access to commercial paper markets has been substantially reduced, if not eliminated, as a result of the downgrading of the Company's credit ratings during 1993. The amount of outstanding short-term borrowing will fluctuate with day-to-day operational needs, the timing of long-term financing, and market conditions. On November 9, 1994, the Company entered into a Competitive Advance and Revolving Credit Facility (Revolving Credit Facility), with several banks and Chemical Bank, as agent for the lenders, to provide up to $80 million of revolving credit loans. The Revolving Credit Facility supplements the existing $50 million revolving-credit agreement and replaces the Company's $73 million of individual lines of credit. The revolving credit loans under the Revolving Credit Facility may consist of "Eurodollar Loans" or "ABR Loans", or a combination thereof. Borrowings of Eurodollar Loans would bear an interest rate based on average rates offered in the interbank eurodollar market. Borrowings of ABR Loans would bear interest at the higher of the Prime Rate, a certificate of deposit rate plus 1%, or the Federal Funds Rate plus 1/2 of 1%. The revolving Credit Facility has a term of 364 days. However, it can be terminated 90 days after the Company's Standard & Poor's Rating Group (S&P) rating falls below "BB+" or the Company's Moody's Investors Service, Inc. (Moody's) rating falls below "Baa3" or the Company's Duff & Phelps Credit Rating Company (D&P) rating falls below "BBB-", and the condition still exists on the 90th day. The annual fees on the Revolving Credit Facility range from .375% to .5% of the unused portion of the commitment, depending on the S&P, Moody's and D&P ratings. The last credit-rating action relating to the Company's securities was announced on April 6, 1994, when S&P revised its outlook on the Company's securities from "negative" to "stable" and affirmed its ratings on the Company's senior secured debt at "BB+", its senior unsecured debt at "BB-", its preferred stock at "B+" and its commercial paper at "B". S&P cited the MPUC's April 4, 1994 approval of the stipulation resolving uncertainty relating to purchased-power contract investigations as a reason for the revision. The Company has been engaging in discussions with its 32 largest customers with the objective of entering into multi-year rate agreements that would ensure retention of those customers. These large customers have competitive options that the Company believes must be addressed by lowering the tariff (i.e., price) to a competitive level. The Company expects that such agreements will lower the revenue contribution of these customers. The Company cannot predict the results of those discussions, but implementation of such agreements is dependent on effectiveness of the ARP. With the advent of the municipalization initiatives in the Company's service territory and the continued focus of the electric utility industry on the potential costs and benefits of retail wheeling, the Company has become increasingly concerned with the possibility that certain costs incurred for the benefit of its customers would not be recoverable when customers leave its system for power-supply competitors or otherwise (stranded investment). Both the FERC and the MPUC have initiated proceedings on the stranded investment issue, with the MPUC rulemaking proceeding scheduled to conclude in the Spring of 1995. The Company cannot predict the outcome of the jurisdictional questions between the FERC and the state regulatory commissions involved in stranded-investment issues, nor can it predict the results of those proceedings. PART II - OTHER INFORMATION Item 1. Legal Proceedings Environmental Matters. For a discussion of administrative and judicial proceedings concerning cleanup of a site containing soil contaminated by PCB's from equipment originally owned by the Company, see Note 2, "Commitments and Contingencies," "Legal and Environmental Matters," which is incorporated herein by reference. Alternative Rate Plan. Reference is specifically made to Note 3, "Regulatory Matters," Section, "Alternative Rate Plan," for a discussion of a stipulation before the Maine Public Utilities Commission that, if adopted, would revise the existing system of retail rate regulation for the Company and cause the Company to take material charges against earnings in the period the stipulation is adopted. Regulatory Matters. For a discussion of certain other regulatory matters affecting the Company, see Note 3, "Regulatory Matters," which is incorporated herein by reference. Items 2. through 5. Not applicable Item 6. Exhibits and Reports on Form 8-K (a) Exhibits. None. (b) Reports on Form 8-K. The Company filed the following reports on Form 8-K during the third quarter of 1994 and thereafter to date: Date of Report Items Reported July 5, 1994 Item 5 (a) Approval of Stipulation in Power Contracts Prudence Investigation. On July 5, 1994 the PUC approved a stipulation that provided that the Company would not be subject to any further investigations, disallowances, or other financially adverse consequences with respect to administration prior to March 22, 1994, of its administration of its large non-utility generator contracts that were being investigated. (b) Approval of Fuel Cost Adjustment Stipulation. On July 18, 1994, the MPUC approved a stipulation entered into by the Company and other parties providing for an annual fuel revenue increase of $23.3 million. In addition, the approved fuel-related stipulation provides for an expedited approval process for the Company to implement new special-rate contracts with individual customers. Date of Report Items Reported October 14, 1994 Item 5 On October 14, 1994, the Company filed with the Maine Public Utilities Commission (the "PUC")for its approval a stipulation approved by most of the parties to an ongoing proceeding on an Alternative Rate Plan ("ARP"). Date of Report Items Reported October 17, 1994 Item 5 On September 28, 1994, the Board of Directors of The Company adopted a shareholder rights plan and declared a dividend of one common share purchase right (a "Right") for each outstanding share of common stock, payable to shareholders of record as of the close of business on October 17, 1994. Signatures Pursuant to the requirements 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. CENTRAL MAINE POWER COMPANY (Registrant) Date: November 10, 1994 /S/R. S. Howe R. S. Howe, Comptroller (Chief Accounting Officer) /S/D. E. Marsh David E. Marsh, Vice President, Corporate Services, and Chief Financial Officer (Principal Financial Officer and duly authorized officer) EX-27 2
UT This schedule contains summary financial information extracted from Central Maine Power Company's Form 10-Q for the period ended September 30, 1994 and is qualified in its entirety by reference to such financial statements. QTR-3 DEC-31-1993 SEP-30-1994 PER-BOOK 1,076,620 48,130 312,863 659,912 0 2,097,525 162,214 275,457 127,648 565,319 80,000 65,571 537,445 0 0 0 45,000 0 41,422 3,339 759,429 2,097,525 686,905 25,988 586,868 612,846 78,494 (754) 77,740 36,934 40,806 7,883 32,923 21,916 30,761 134,039 1.01 1.01 Other Assets are included in "Deferred Charges and Other Assets" on the Balance Sheet.
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