-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, VENIrT2bdsg3V2DWMbLd/Yvop/rgC8Npc4oGQ9ccQ+UPXzl5Dk6KW051WCOTOeh9 nIxpqlB+EPXiqyS2HuD7cQ== 0000018675-95-000023.txt : 19951119 0000018675-95-000023.hdr.sgml : 19951119 ACCESSION NUMBER: 0000018675-95-000023 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 2 CONFORMED PERIOD OF REPORT: 19950930 FILED AS OF DATE: 19951113 SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: CENTRAL MAINE POWER CO CENTRAL INDEX KEY: 0000018675 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [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: 95590104 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, 1995 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 as Class of November 10, 1995 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, 1995 and 1994 1 Consolidated Statement of Earnings for the Nine Months Ended September 30, 1995 and 1994 2 Consolidated Balance Sheet - September 30, 1995 and December 31, 1994: Assets 3 Stockholders' Investment and Liabilities 4 Consolidated Statement of Cash Flows for the Nine Months Ended September 30, 1995 and 1994 5 Notes to Consolidated Financial Statements 6 Management's Discussion and Analysis of Financial Condition and Results of Operations 12 Part II. Other Information 18
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, 1995 1994 ELECTRIC OPERATING REVENUES $217,872 $233,543 OPERATING EXPENSES Fuel Used for Company Generation 5,887 4,614 Purchased Power Energy 99,221 110,944 Capacity (Note 2) 18,631 21,687 Other Operation 41,750 34,921 Maintenance 7,021 8,210 Depreciation and Amortization 13,315 13,992 Federal and State Income Taxes 4,260 8,529 Taxes Other Than Income Taxes 7,390 6,416 Total Operating Expenses 197,475 209,313 EQUITY IN EARNINGS OF ASSOCIATED COMPANIES 1,772 1,422 OPERATING INCOME 22,169 25,652 OTHER INCOME (EXPENSE) Allowance for Equity Funds Used During Construction 173 213 Other, Net 1,802 850 Income Taxes Applicable to Other Income (Expense) (476) (290) Total Other Income (Expense) 1,499 773 INCOME BEFORE INTEREST CHARGES 23,668 26,425 INTEREST CHARGES Long-Term Debt 12,371 11,293 Other Interest 1,040 1,176 Allowance for Borrowed Funds Used During Construction (143) (127) Total Interest Charges 13,268 12,342 NET INCOME 10,400 14,083 DIVIDENDS ON PREFERRED STOCK 2,518 2,627 EARNINGS APPLICABLE TO COMMON STOCK $ 7,882 $ 11,456 WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING 32,442,752 32,442,752 EARNINGS PER SHARE OF COMMON STOCK $ 0.24 $0.35 DIVIDENDS DECLARED PER SHARE OF COMMON STOCK $0.225 $0.225 The accompanying notes are an integral part of these financial statements./TABLE Central Maine Power Company CONSOLIDATED STATEMENT OF EARNINGS (Unaudited) (Dollars in Thousands Except Per Share Amounts)
For the Nine Months Ended September 30, 1995 1994 ELECTRIC OPERATING REVENUES $683,768 $686,905 OPERATING EXPENSES Fuel Used for Company Generation 15,441 13,685 Purchased Power Energy 305,925 325,654 Capacity (Note 2) 73,799 56,632 Other Operation 131,227 106,995 Maintenance 21,960 23,035 Depreciation and Amortization 41,629 41,789 Federal and State Income Taxes 12,695 25,988 Taxes Other Than Income Taxes 20,759 19,068 Total Operating Expenses 623,435 612,846 EQUITY IN EARNINGS OF ASSOCIATED COMPANIES 5,249 4,435 OPERATING INCOME 65,582 78,494 OTHER INCOME (EXPENSE) Allowance for Equity Funds Used During Construction 483 637 Other, Net 4,748 (2,236) Income Taxes Applicable to Other Income (Expense) (1,719) 845 Total Other Income (Expense) 3,512 (754) INCOME BEFORE INTEREST CHARGES 69,094 77,740 INTEREST CHARGES Long-Term Debt 37,988 33,799 Other Interest 3,348 3,520 Allowance for Borrowed Funds Used During Construction (399) (385) Total Interest Charges 40,937 36,934 NET INCOME 28,157 40,806 DIVIDENDS ON PREFERRED STOCK 7,659 7,883 EARNINGS APPLICABLE TO COMMON STOCK $ 20,498 $ 32,923 WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING 32,442,752 32,442,292 EARNINGS PER SHARE OF COMMON STOCK $0.63 $1.01 DIVIDENDS DECLARED PER SHARE OF COMMON STOCK $0.675 $0.675 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, 1995 1994 (Unaudited) ASSETS ELECTRIC PROPERTY, at Original Cost $1,600,637 $1,579,632 Less: Accumulated Depreciation 550,178 521,645 Electric Property in Service 1,050,459 1,057,987 Construction Work in Progress 16,942 13,647 Net Nuclear Fuel 1,563 2,181 Net Electric Property and Nuclear Fuel 1,068,964 1,073,815 INVESTMENTS IN ASSOCIATED COMPANIES, at Equity 53,682 49,602 Net Electric Property, Nuclear Fuel and Investments in Associated Companies 1,122,646 1,123,417 CURRENT ASSETS Cash and Temporary Cash Investments 61,695 58,112 Accounts Receivable, Less Allowance for Uncollectible Accounts of $3,310 in 1995 and $3,301 in 1994 Service - Billed 71,753 81,289 - Unbilled 33,068 38,153 Other Accounts Receivable 8,351 12,088 Prepaid Income Taxes 1,863 28,068 Inventories, at Average Cost Fuel Oil 3,181 4,113 Materials and Supplies 13,887 13,026 Funds on Deposit With Trustee 27,910 27,820 Prepayments and Other Current Assets 9,383 9,337 Total Current Assets 231,091 272,006 DEFERRED CHARGES AND OTHER ASSETS Recoverable Costs of Seabrook 1 and Abandoned Projects, Net 96,977 101,976 Regulatory Assets-Deferred Taxes 234,013 233,234 Yankee Atomic Purchase Power Contract 34,130 38,777 Other Deferred Charges and Other Assets 267,647 276,597 Deferred Charges and Other Assets, Net 632,767 650,584 TOTAL ASSETS $1,986,504 $2,046,007 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, 1995 1994 (Unaudited) STOCKHOLDERS' INVESTMENT AND LIABILITIES CAPITALIZATION Common Stock Investment $ 490,003 $ 491,323 Preferred Stock 65,571 65,571 Redeemable Preferred Stock 74,528 80,000 Long-Term Obligations 627,833 638,841 Total Capitalization 1,257,935 1,275,735 CURRENT LIABILITIES AND INTERIM FINANCING Interim Financing 39,000 63,000 Sinking Fund Requirements 2,584 2,580 Accounts Payable 71,032 97,800 Dividends Payable 9,823 9,932 Accrued Interest 9,921 14,102 Maine Yankee Sleeving Accrual 7,893 - Miscellaneous Current Liabilities 18,922 10,535 Total Current Liabilities and Interim Financing 159,175 197,949 COMMITMENTS AND CONTINGENCIES RESERVES AND DEFERRED CREDITS Accumulated Deferred Income Taxes 354,707 348,287 Unamortized Investment Tax Credits 32,958 34,167 Regulatory Liabilities-Deferred Taxes 55,001 53,937 Yankee Atomic Purchase Power Contract 34,130 38,777 Other Reserves and Deferred Credits 92,598 97,155 Total Reserves and Deferred Credits 569,394 572,323 TOTAL STOCKHOLDERS' INVESTMENT AND LIABILITIES $1,986,504 $2,046,007 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 September 30, 1995 1994 CASH FROM OPERATIONS Net Income $ 28,157 $ 40,806 Items Not Requiring (Providing) Cash: Depreciation and Amortization 61,101 53,825 Deferred Income Taxes and Investment Tax Credits, Net 4,177 26,511 Maine Yankee Sleeving Accrual 7,893 - Allowance for Equity Funds Used During Construction (483) (637) Changes in Certain Assets and Liabilities: Accounts Receivable 18,358 39,712 Other Current Assets (136) (4,974) Inventories 71 2,654 Retail Fuel Costs - 10,499 Accounts Payable (24,685) (19,895) Accrued Interest (4,181) (4,058) Prepaid Income Taxes 26,205 (5,546) Miscellaneous Current Liabilities 8,387 151 Deferred Energy Management Costs (2,524) (4,017) Maine Yankee Outage Accrual (6,780) (6,247) Purchase Power Contracts (10,675) (4,996) Other, Net 2,210 10,251 Net Cash Provided by Operating Activities 107,095 134,039 INVESTING ACTIVITIES Construction Expenditures (32,673) (29,743) Changes in Accounts Payable-Investing Activities (2,083) (1,443) Investment in Associated Companies (600) - Net Cash Used by Investing Activities (35,356) (31,186) FINANCING ACTIVITIES Issuances: Common Stock - 927 Mortgage Bonds - 25,000 Medium-Term Notes 30,000 - Redemptions: Short-Term Obligations - (25,500) Other Long-Term Obligations - (860) Preferred Stock (5,472) - Medium-Term Notes (55,000) (24,000) Short-Term - Medium-Term Notes (8,000) - Dividends: Common Stock (21,916) (21,916) Preferred Stock (7,768) (7,433) Net Cash (Used) Provided by Financing Activities (68,156) (53,782) Net Increase (Decrease) in Cash 3,583 49,071 CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD 58,112 1,956 CASH AND CASH EQUIVALENTS, END OF PERIOD $ 61,695 $ 51,027
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 should be read with the Annual Report on Form 10-K for the year ended December 31, 1994 (Form 10-K), and 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. The adoption of the Alternative Rate Plan (ARP), effective January 1, 1995, eliminated the reconcilable fuel clause used under traditional rate-of-return regulation to account for and collect fuel and purchased-power energy costs. Fuel revenues are now recorded as they are billed rather than deferred and reflected in revenues over time periods established by the Maine Public Utilities Commission (MPUC). These effects complicate quarter-to-quarter comparisons, but seasonality issues will not affect calendar year comparisons. 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 the nine months ended September 30, 1995 and 1994 for interest, net of amounts capitalized, amounted to $41.9 million and $37.6 million, respectively. Income taxes refunded, net of amounts paid, amounted to $15.9 million for the nine months ended September 30, 1995, versus a net amount paid of $4.2 million for the corresponding period in 1994. Income taxes totaling $24.3 million were refunded in the third quarter of 1995, and $28.8 million year-to-date. The Company incurred no new capital lease obligations in either period. 2. Commitments and Contingencies (a) Maine Yankee Atomic Power Company Steam Generator Tubes - The Company, through its equity investment totaling approximately $26.8 million at September 30, 1995, owns a 38-percent stock interest in Maine Yankee Atomic Power Company (Maine Yankee), which owns and operates an 860- megawatt nuclear generating plant in Wiscasset, Maine (the Maine Yankee Plant or the Plant), and is entitled under a cost-based power contract to an approximately equal percentage of the Plant's output. The Maine Yankee Plant, like other pressurized water reactors, experienced degradation of its steam generator tubes, principally in the form of circumferential cracking, which, until early 1995, was believed to be limited to a relatively small number of tubes. During the refueling-and-maintenance shutdown that commenced in early February 1995, Maine Yankee detected through new inspection methods increased degradation of the Plant's steam generator tubes to the extent that approximately 60 percent of the Plant's 17,000 steam generator tubes appeared to have defects to some degree. Several courses of action were evaluated to address the matter, and mitigation of the problem by plugging additional tubes was not a viable option. The substantial increase in the number of degraded tubes resulted in substantial additional costs to Maine Yankee, with the Company being responsible for its pro-rata share. In addition, the Company is incurring substantial replacement power costs, the amount depending on the duration of the outage and the prices paid for the replacement power. With the termination of the reconcilable fuel-and-purchased- power adjustment under the ARP, costs of replacement power during a Maine Yankee outage are in general being treated like other Company expenses, i.e., limited by the ARP's price-index mechanism, and are not being deferred and collected through a specific fuel-rate adjustment, as under pre-1995 ratemaking. Under the ARP no additional price increase other than the 2.43 percent increase effective July 1, 1995, associated with the price index, will take effect in 1995 as a result of the Maine Yankee outage. Although the ARP contains provisions that could result in rate adjustments based on low earnings or the incurring of extraordinary costs by the Company, neither provision will affect prices in 1995. Following a detailed analysis of the safety, technical and financial considerations associated with the defective steam generator tubes, Maine Yankee has been repairing the tubes by inserting and welding short reinforcing sleeves of an improved material in all of the Plant's steam generator tubes. Similar repairs have been completed at other nuclear plants in the United States and abroad, but not on the scale of the Maine Yankee project. On May 22, 1995, the federal Nuclear Regulatory Commission (NRC) issued a license approving the sleeving process of Westinghouse Electric Corporation (Westinghouse) for the Plant. On the same day, the Board of Directors of Maine Yankee authorized management to undertake the sleeving project, and on May 24, 1995, Maine Yankee selected Westinghouse as the contractor for the project. The sleeving project started in early June and is nearing completion, with the Plant expected to return to service by the end of 1995. On October 25, 1995, Maine Yankee began re-loading fuel into the Plant's reactor. Maine Yankee is recording the sleeving costs as maintenance expense. The Company estimated its share of such costs to be $15.0 million and recorded a one-time charge for that amount to purchased power-capacity expense in the second quarter of 1995. Maine Yankee has billed the Company $7.1 million as of September 30, 1995, for costs incurred. In addition, the Company is incurring additional fuel costs over and above what it would have incurred if the Maine Yankee Plant had continued to operate, in the range of approximately $3.5 million to $4.5 million per month while the outage persists, and both the Company and Maine Yankee have implemented cost-reduction measures to partially offset the additional costs. The Company's incremental replacement-power costs were approximately $11 million in the third quarter, and approximately $22 million for the nine months ended September 30, 1995. Although the repairs are on schedule to be completed by the end of 1995, the Company cannot predict with certainty how long the Plant will be out of service. The impact of the Company's replacement-power costs and its share of the Maine Yankee sleeving costs will have a material adverse effect on the Company's financial results for 1995. (b) 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 was 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. In July 1994, the EPA approved changes to the remedy it had previously selected, the principal change being to adjust the soil cleanup standard to 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 inability to reduce PCBs and other chemical components on the site to the original standard. In June 1995, after discussions between the Company and the EPA, design work on the selected remedy was suspended. On July 7, 1995, the Company formally requested that the EPA abandon that remedy for an already-designated alternative remedy that the Company believes could result in substantially lower costs. On October 10, 1995, the EPA approved the new remedy after determining that the old remedy was no longer feasible or cost-effective at the site. The new remedy involves transporting the contaminated soil to a secure off-site landfill. The Company believes that its share of the remaining costs of the cleanup under the new method could total approximately $4 million to $5 million. Such estimate is net of an agreed partial insurance recovery and the 1993 court-ordered contribution of 41 percent from Westinghouse Electric Corp., but does not reflect any possible contributions from other insurance carriers the Company has sued, or any other parties. The Company has recorded an estimated liability of $11 million, the pre-October 10, 1995 estimated cost of clean-up, and an equal regulatory asset, reflecting an accounting order to defer such costs and the anticipated ratemaking recovery of such costs when ultimately paid. As a result of the change in remedy, the Company is reviewing its estimate of its minimum liability. 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. 3. Regulatory Matters Alternative Rate Plan - In December 1994, the MPUC approved a stipulation signed by most of the parties to the Company's ARP proceeding. See Note 3 to Consolidated Financial Statements included in the Company's Form 10-K for a detailed description of the ARP. This follow-up proceeding to the Company's 1993 base- rate case was ordered by the MPUC in an effort to develop a five- year plan containing price-cap, profit-sharing, and pricing- flexibility components. Although the ARP is a major reform, the MPUC will continue to regulate the Company's operations and prices and provide for continued recovery of deferred costs. The Company believes, as stated in the MPUC's order approving the ARP, that operation under the ARP continues to meet the criteria of SFAS No. 71. In its order, the MPUC reaffirmed the applicability of previous accounting orders allowing the Company to reflect amounts as deferred charges and regulatory assets. As a result, the Company will continue to apply the provisions of SFAS No. 71 to its accounting transactions and in its future financial statements. The ARP contains a mechanism that provides price-caps on the Company's retail rates to increase annually on July 1, commencing July 1, 1995, by a percentage combining (1) a price index, (2) a productivity offset, (3) a sharing mechanism, and (4) flow- through items and mandated costs. The price cap applies to all of the Company's retail rates, including the Company's fuel-and- purchased-power cost, which previously had been treated separately. Under the ARP, fuel expense is no longer subject to reconciliation or specific rate recovery, but is subject to the annual indexed price-cap changes. The ARP also provides for partial flow-through to ratepayers of cost savings from non-utility generator contract buy-outs and restructuring, recovery of energy-management costs, penalties for failure to attain customer-service and energy-efficiency targets, and specific recovery of half the costs of the transition to the accounting method required by Statement of Financial Accounting Standards No. 106, "Accounting for Postretirement Benefits Other Than Pensions" (SFAS No. 106), the remaining 50 percent to be recovered through the annual price-cap change. The ARP also generally defines mandated costs that would be recoverable by the Company notwithstanding the index-based price cap. To receive such treatment, a mandated cost's revenue requirement must exceed $3 million and have a disproportionate effect on the Company or the electric power industry. The ARP also contains provisions to protect the Company and ratepayers against unforeseen adverse results from its operation. These include review by the MPUC if the Company's actual return on equity falls outside the designated 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. On July 1, 1995, the Company's first annual increase in rates and rate-element caps under the ARP of 2.43 percent became effective. The components of the increase included the inflation index of 2.92 percent, reduced by a productivity offset of 0.5 percent and increased by 0.01 percent for flowthrough items and mandated costs. Under prior long-term agreements, price discounts for competitively targeted customer classes are not affected by the increase. 4. Capitalization and Interim Financing On May 24, 1995, the shareholders of the Company, by a vote of 50.36 percent to 49.64 percent, approved a shareholder proposal at the Company's annual meeting of shareholders recommending redemption of the rights and termination of the Shareholder Rights Plan adopted by the Company on September 28, 1994, (see Note 7 of Notes to Consolidated Financial Statements in the Company's Form 10-K). The Shareholder Rights Plan was meant to provide protection against abusive or discriminatory takeover tactics. On July 19, 1995, the Board of Directors of the Company terminated, effective immediately, the right to exercise the Rights issued to its shareholders pursuant to the Shareholder Rights Plan and ordered the redemption of the Rights. The Board directed payment of the redemption price of $.01 per Right on August 28, 1995, to holders of record at the close of business on August 14, 1995. This one-time payment amounted to $324,428. 5. Pensions and Other Postemployment Benefits In May 1995, the Company announced a Special Retirement Offer (SRO) to all employees aged 50 or more who had at least five years of continuous service. The goal of the SRO was to help the Company achieve financial savings and make the organizational changes it needs to be an effective competitor in the energy marketplace. Approximately 200 employees accepted the SRO. As a result, the Company recorded a one-time charge of $4.8 million associated with the SRO in the second quarter of 1995. The SRO also included certain permanent retirement-benefit enhancements for all employees, the cost of which will be amortized to pension expense over the remaining service life of active employees. 6. Income Taxes The effective federal income tax rate for the year ended December 31, 1994 was 31.2%. For the three and the nine months ended September 30, 1995 the effective federal tax rates were 27.1% and 30.7%, 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 The third quarter of 1995 generated net income of $10.4 million compared to $14.1 million for the corresponding period in 1994. Year-to-date net income was $28.2 million versus $40.8 million for the 1994 period. Year-to-date net income was affected by the second quarter 1995, one-time, pre-tax charges of $15.0 million for the Company's entire estimated cost of tube sleeving at Maine Yankee (see Note 2 "Commitments and Contingencies - Maine Yankee Atomic Power Company Steam Generator Tubes"), and $4.8 million of costs associated with the SRO that reduced the work force by 200 for employees accepting the offer as of June 30, 1995 (see Note 5 "Pensions and Other Postemployment Benefits"). Earnings applicable to Common Stock were $7.9 million or $0.24 per share for the third quarter compared to earnings of $11.5 million or $0.35 per share for the comparable period in 1994. Year-to-date earnings applicable to Common Stock were $20.5 million or $0.63 per share and $32.9 million or $1.01 per share in 1994. The one-time charges, net of tax, included in the year- to-date numbers were $8.9 million or $0.27 per Common Share for Maine Yankee tube-sleeving and $2.8 million or $0.09 per share for the SRO. Operating revenues decreased by $3.1 million or 0.5 percent to $684 million in the first nine months of 1995. Operating revenues for the third quarter of 1995 of $218 million were 6.7 percent less than the third quarter of 1994. Revenues were affected by flat or lower kilowatt-hour sales, a 1994 price increase for most customers, price discounts for competitively targeted customer classes and the elimination under the ARP that took effect January 1, 1995, of reconciliation treatment for fuel and purchased-power expenses. The adoption of the ARP effective January 1, 1995 had a significant impact on the results of operations for the first nine months of 1995 when compared to 1994. The ARP price-cap method of ratemaking eliminates the reconcilable fuel clause used under traditional rate-of-return regulation to account for and collect fuel and purchased-power energy costs. One impact of this change is that seasonality in prices and certain accounting treatments for fuel revenues can produce more volatility in quarterly results than occurred under the prior ratemaking treatment. These effects complicate quarter-to-quarter comparisons, but seasonality issues will not affect calendar year comparisons. Under that discontinued mechanism, fluctuations in fuel costs required the Company to record unbilled fuel revenue for any fuel costs incurred in excess of the amounts actually collected in each respective period. If fuel collections exceeded fuel costs a charge to revenue was made during that period. The effect of the fuel cost adjustment mechanism was to ensure that all fuel costs incurred were ultimately collected from customers at some time in the future. This fuel mechanism also resulted in the allocation of a greater portion of the customers' rates to fuel revenues in the winter months and traditionally resulted in a charge to revenues in the winter months as fuel revenues collected normally exceed fuel costs. With the elimination of the reconcilable fuel mechanism under the ARP, fuel revenues are now recorded as they are billed. Therefore, the traditional charge to revenues for fuel overcollections in the winter months no longer occurs, affecting revenues for the first nine months of 1995. Service-area sales for the third quarter of 1995 totaled approximately 2.3 billion kilowatt-hours and were 0.7 percent greater than the third quarter of 1994. Service-area sales of electricity totaled approximately 6.8 billion kilowatt-hours for the nine-month period ended September 30, 1995, a decrease of 3.1 percent compared to the first nine months of 1994. Service Area Kilowatt-hour Sales (Millions of KWHs) Period Ended September 30, Three Months Nine Months % % 1995 1994 Change 1995 1994 Change Residential 665.8 653.5 1.9% 2,117.1 2,196.2 (3.6)% Commercial 664.9 651.1 2.1 1,873.9 1,871.8 0.1 Industrial 957.8 966.1 (0.9) 2,702.2 2,827.8 (4.4) Other 34.5 37.1 (6.8) 102.3 116.2 (11.9) 2,323.0 2,307.8 0.7% 6,795.5 7,012.0 (3.1)%
The changes in service area kilowatt-hour sales reflect the following: Kilowatt-hour sales to residential customers increased by 1.9 percent in the third quarter and decreased by 3.6 percent for the nine months ended September 30, 1995 compared to 1994; usage per customer increased 0.8 percent in the third quarter and decreased 4.7 percent for the nine months ended September 30, 1995. Warmer than normal winter temperatures and declines in the space and water heating subclass usage contributed to the annual decrease. Commercial sales increased by 2.1 percent and 0.1 percent for the three-month and nine-month periods from 1994, reflecting increases or flat sales in most sectors for the quarter and moderate growth in the retail and transporta- tion, communication and utility sectors year-to-date. Industrial kilowatt-hour sales decreased by 0.9 percent in the third quarter and by 4.4 percent for the nine months ended September 30, 1995 compared to 1994 due primarily to decreased sales to the pulp and paper industry of 4.4 percent in the third quarter and 9.1 percent for the nine- month period ended September 30, 1995. This sector accounts for approximately 63 percent of the industrial sales category. The primary factor in the decline in sales to this industry was the loss of 127 million kilowatt-hours of sales formerly made to a customer who began taking service from another utility in late 1994. See Note 4 to Consolidated Financial Statements in the Company's Form 10-K for a detailed discussion of this matter. A sales increase of 6.1 percent for the third quarter and 4.6 percent for the nine months ended September 30, 1995 occurred in all other industrial customers as a group. The components of the change in electric operating revenues for the nine months ended September 30, 1995, as compared to the same period in 1994, are as follows: Three Nine Months Months (Dollars in Thousands) Revenues from Kilowatt-hour Sales $(17,790) $(10,574) Other Operating Revenues, including Maine Electric Power Company, Inc. 2,119 7,437 Total Change in Electric Operating Revenues $(15,671) $(3,137)
Total service-area base revenues decreased for the third quarter and the nine months ended September 30, 1995 reflecting flat or lower kilowatt-hour sales, a December 1994 annual price decrease totaling $5.6 million, and the discounted rates given competitively positioned customers effective with the ARP. Seasonal fluctuations in fuel revenues will continue throughout the remainder of 1995. For a complete discussion of discounted rates, see Note 4 to Consolidated Financial Statements in the Company's Form 10-K. MEPCO's electric sales and transmission revenues from New England utilities other than the Company (included in other operating revenues in the preceding table) amounted to $4.2 million and $1.5 million in the third quarters of 1995 and 1994, respectively. These same totals for the nine-months ended September 30, 1995 and 1994 were $8.7 million and $4.3 million, respectively. Under a Participation Agreement that terminates on July 1, 1996, subject to certain rights to continued participation, all of MEPCO's costs, including a return on invested capital, are paid by the participating utilities (Participants), which include the Company and most of the larger New England electric companies. The level of MEPCO's revenues and expenses changes depending upon the level of energy purchases by Participants. Purchased power-capacity expense decreased by $3.1 million in the third quarter of 1995 and increased by $17.2 million in the nine months ended September 30, 1995. The nine-month period includes the one-time pre-tax charge of $15.0 million for the Company's entire estimated cost of the tube sleeving at Maine Yankee. The Maine Yankee charge, which represents CMP's share of the previously reported estimated total repair cost of $40.0 million, was accrued in the second quarter of 1995; actual billings for repair work will continue through year-end 1995. Other charges in the nine-month period included higher nuclear capacity expense at two other nuclear plants in which the Company has an equity interest. The year-to-date expense comparison also includes the 1994 credit for the reversal of a $4.1 million "capacity deficiency fund". A January 1994 MPUC-approved stipulation favorably resolved all issues related to that fund. Other operation and maintenance expenses increased by $5.6 million compared to the third quarter of 1994 and $23.2 million compared to the first nine months of 1994. These increases primarily reflect significantly higher monthly charges for amortization of purchased-power contract buy-outs and the one- time pre-tax charge of $4.8 million for costs associated with the Company's SRO. Energy-management expenses increased slightly in both periods. Federal and state income taxes decreased by $4.1 million in the third quarter and by $10.7 million for the nine months ended September 30, 1995. Federal and state income taxes fluctuate with the level of pre-tax earnings and the regulatory treatment of taxes by the MPUC. Lower pre-tax earnings were attributable to lower sales levels and the one-time charges for Maine Yankee tube sleeving and the SRO. The tax effects, applicable to the nine months ended September 30, 1995, of these one-time charges were decreases of $6.1 million for Maine Yankee tube sleeving and $2.0 million for the SRO. Interest on long-term debt during the third quarter of 1995 increased by approximately $1.1 million and $4.2 million for the first nine months of 1995 while other interest expense decreased slightly compared to 1994. The increase reflects higher levels of outstanding long-term debt when compared to 1994. The increased debt results from the issuance of additional mortgage bonds during 1994 and the note to the Finance Authority of Maine issued to finance the buyout of a large non-utility generator (NUG) contract in 1994. Liquidity and Capital Resources Approximately $100.8 million of cash was provided during the first nine months of 1995 from net income before non-cash items, primarily depreciation and amortization and the accrual of the estimated cost of the Maine Yankee tube sleeving. During such period, approximately $6.3 million of cash was provided by fluctuations in certain assets and liabilities and from other operating activities. During the first nine months of 1995, the Company reduced the level of preferred stock outstanding by $5.5 million through normal sinking fund requirements. Dividends paid on common stock were $21.9 million, while preferred-stock dividends utilized $7.8 million of cash. Medium-Term Notes were reduced by $33.0 million. Investing activities, primarily construction expenditures, utilized $35.4 million in cash during the first nine months of 1995 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-supply sources 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. 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 replaced the Company's $73 million of individual lines of credit. Several credit-rating actions relating to the Company's securities took place in early 1995, when the Company's actions taken during 1994 with respect to cost control, NUG cost reductions, the regulatory reform under the ARP, and the competitive pricing agreements with large customers, were recognized by Moody's Investors Service (Moody's) which upgraded the Company's ratings on preferred stock and commercial paper, and Duff & Phelps Credit Rating Co. (Duff & Phelps), which upgraded its preferred stock rating. After announcement of the Maine Yankee steam generator tube issues Duff & Phelps placed the Company on "credit watch" for possible downgrade, but on May 25, 1995, removed the Company's fixed-income securities from "Rating Watch--Down" and reaffirmed the Company's ratings. Moody's reaffirmed its ratings of the Company's securities on June 19, 1995, including its negative rating outlook. Standard and Poor's Corp. continues to monitor the Maine Yankee situation and its impact on its ratings of the Company's securities. Stranded Costs The enactment by Congress of the Energy Policy Act of 1992 accelerated planning by electric utilities, including the Company, for the anticipated transition to a more competitive industry. The functional areas in which competition will take place, the regulatory changes that will be implemented, and the resulting structure of both the industry and the Company are all uncertain, but the likelihood of a transition to direct competition to serve retail customers is widely anticipated. A departure from traditional regulation, however, could have substantial impacts on the value of utility assets and on the ability of electric utilities to recover their costs through rates. In the absence of full recovery, utilities would find their above-market costs to be "stranded", or unrecoverable, in the new competitive setting. The Company has substantial exposure to cost stranding relative to its size, principally in the form of its long-term contract obligations to buy non-utility power at average prices above prices that could currently be achieved in the open market. In addition, the Company's deferred charges, which are being recovered in rates, could be impaired. Based on current costs and obligations the present value of excess costs over market rates for electricity could be as much as approximately three to four times the amount of the Company's common equity. However, the amount of the Company's embedded costs in excess of what could be recovered if electricity prices were set at market levels that could be potentially at risk of recovery is dependent on such factors as the length of the transition period to open competition, the market rate for electricity, the terms and conditions, including stranded cost recovery provisions, of open competition and the overall level of the Company's costs. On March 29, 1995, as part of a broader Notice of Proposed Rulemaking (NOPR) related to open transmission access and stranded costs, and designed to facilitate the development of a competitive market, the Federal Energy Regulatory Commission (FERC) expressed support for the principle that utilities are entitled to full recovery of their "legitimate and verifiable" stranded costs at both the state and federal levels. Earlier, the MPUC had initiated a rulemaking proceeding on stranded costs at the retail level with a preliminary proposal that recommended less than full recovery of such costs, but terminated its proceeding after FERC issued its NOPR to avoid "parallel and duplicative proceedings". A diverse committee appointed by the Maine Legislature is in the process of developing recommendations for the MPUC on the future structure of the electric utility industry in Maine. Substantial opposition has emerged in the FERC proceeding to allowing full recovery of stranded costs, largely from customer groups and NUGs. The stranding of a major portion of its costs would have a material adverse effect on the Company's results of operations, depending on the amounts involved. The Company believes that it is entitled to recover substantially all of its potentially strandable costs under existing regulatory principles, but cannot predict how much of such costs it will ultimately be allowed to recover at the state or federal level. 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. Regulatory Matters. For a discussion of certain other Regulatory matters affecting the Company, see Note 3, "Regulatory Matters," which is incorporated herein by reference. Item 2. through Item 4. Not applicable Item 5. Other Events Maine Yankee Steam Generator Tubes. For a discussion of issues arising from the discovery of a large number of degraded steam generator tubes at the Maine Yankee plant see Note 2, "Commitments and Contingencies," "Maine Yankee Atomic Power Company Steam Generator Tubes," which is incorporated herein by reference. Stranded Costs. The enactment by Congress of the Energy Policy Act of 1992 accelerated planning by electric utilities, including the Company, for the anticipated transition to a more competitive industry. The functional areas in which competition will take place, the regulatory changes that will be implemented, and the resulting structure of both the industry and the Company are all uncertain, but the likelihood of a transition to direct competition to serve retail customers is widely anticipated. A departure from traditional regulation, however, could have substantial impacts on the value of utility assets and on the ability of electric utilities to recover their costs through rates. In the absence of full recovery, utilities would find their above-market costs to be "stranded", or unrecoverable, in the new competitive setting. The Company has substantial exposure to cost stranding relative to its size, principally in the form of its long-term contract obligations to buy non-utility power at average prices above prices that could currently be achieved in the open market. In addition, the Company's deferred charges, which are being recovered in rates, could be impaired. Based on current costs and obligations the present value of excess costs over market rates for electricity could be as much as approximately three to four times the amount of the Company's common equity. However, the amount of the Company's embedded costs in excess of what could be recovered if electricity prices were set at market levels that could be potentially at risk of recovery is dependent on such factors as the length of the transition period to open competition, the market rate for electricity, the terms and conditions, including stranded cost recovery provisions, of open competition and the overall level of the Company's costs. On March 29, 1995, as part of a broader Notice of Proposed Rulemaking ("NOPR") related to open transmission access and stranded costs, and designed to facilitate the development of a competitive market, the Federal Energy Regulatory Commission ("FERC") expressed support for the principle that utilities are entitled to full recovery of their "legitimate and verifiable" stranded costs at both the state and federal levels. Earlier, the MPUC had initiated a rulemaking proceeding on stranded costs at the retail level with a preliminary proposal that recommended less than full recovery of such costs, but terminated its proceeding after FERC issued its NOPR to avoid "parallel and duplicative proceedings". A diverse committee appointed by the Maine Legislature is in the process of developing recommendations for the MPUC on the future structure of the electric utility industry in Maine. Substantial opposition has emerged in the FERC proceeding to allowing full recovery of stranded costs, largely from customer groups and NUGs. The stranding of a major portion of its costs would have a material adverse effect on the Company's results of operations, depending on the amounts involved. The Company believes that it is entitled to recover substantially all of its potentially strandable costs under existing regulatory principles, but cannot predict how much of such costs it will ultimately be allowed to recover at the state or federal level. 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 1995 and thereafter to date: Date of Report Items Reported July 19, 1995 Item 5 (a) The Company announced its second-quarter financial results, pointing out specifically that one-time accounting charges for the costs of the steam-generator tube sleeving project at the Maine Yankee plant and the costs of an early retirement program at the Company had resulted in an $11.2 million second-quarter loss for the Company. (b) The Company also reported that on July 19, 1995, its Board of Directors had terminated the right to exercise the rights issued under its Shareholder Rights Plan, effective immediately, and that it would pay the redemption price of one cent per right on August 28, 1995, to holders of record on August 14, 1995. (c) The Company also reported that Robert E. Tuoriniemi had been elected Comptroller of the Company, effective August 1, 1995, to fill the vacancy caused by a retirement. 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 13, 1995 /S/Robert E. Tuoriniemi Robert E. Tuoriniemi, Comptroller (Chief Accounting Officer) /S/David E. Marsh David E. Marsh, Vice President, Corporate Services, Treasurer and Chief Financial Officer (Principal Financial Officer and duly authorized officer) EX-27 2
UT 1,000 9-MOS DEC-31-1994 SEP-30-1995 PER-BOOK 1,068,964 53,682 231,091 632,767 0 1,986,504 162,214 276,234 51,555 490,003 74,528 65,571 591,686 0 0 0 39,860 0 36,147 1,724 686,985 1,986,504 683,768 12,695 610,740 623,435 65,582 3,512 69,094 40,937 28,157 7,659 20,498 21,916 23,070 107,095 0.63 0.63 Included in Total Deferred Charges.
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