-----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, SPiS5yNVFlbzKrBVGIjW3wJaMCv6LrLKrQFj8mtOQj09DF1RPaxhrk6W4iyvPe6O QlK/Pk6+I3yulHUt8lbwdQ== 0000031224-97-000043.txt : 19971117 0000031224-97-000043.hdr.sgml : 19971117 ACCESSION NUMBER: 0000031224-97-000043 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 2 CONFORMED PERIOD OF REPORT: 19970930 FILED AS OF DATE: 19971114 SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: EASTERN UTILITIES ASSOCIATES CENTRAL INDEX KEY: 0000031224 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 041271872 STATE OF INCORPORATION: MA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: SEC FILE NUMBER: 001-05366 FILM NUMBER: 97718151 BUSINESS ADDRESS: STREET 1: ONE LIBERTY SQ STREET 2: P O BOX 2333 CITY: BOSTON STATE: MA ZIP: 02109 BUSINESS PHONE: 6173579590 10-Q 1 EUA 3RD QUARTER 1997 10Q 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, 1997 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period _________________ to ___________________ Commission File Number 1-5366 EASTERN UTILITIES ASSOCIATES (Exact name of registrant as specified in its charter) Massachusetts 04-1271872 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) One Liberty Square, Boston, Massachusetts (Address of principal executive offices) 02109 (Zip Code) (617)357-9590 (Registrant's telephone number including area code) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes...X.......No.......... Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practical date. Class Outstanding at October 31, 1997 Common Shares, $5 par value 20,435,997 shares PART I - FINANCIAL INFORMATION Item 1. Financial Statements EASTERN UTILITIES ASSOCIATES CONSOLIDATED CONDENSED BALANCE SHEETS (In Thousands)
September 30, December 31, ASSETS 1997 1996 Utility Plant and Other Investments: Utility Plant in Service $ 1,067,160 $ 1,067,056 Less: Accumulated Provision for Depreciation and Amortization 372,164 350,816 Net Utility Plant in Service 694,996 716,240 Construction Work in Progress 15,742 3,839 Net Utility Plant 710,738 720,079 Investments in Jointly Owned Companies 71,922 71,626 Non-Utility Plant - Net 60,839 72,653 Total Plant and Other Investments 843,499 864,358 Current Assets: Cash and Temporary Cash Investments 15,200 12,455 Accounts Receivable, Net 85,866 90,153 Notes Receivable 26,072 24,691 Fuel, Materials and Supplies 11,432 14,131 Other Current Assets 8,112 7,668 Total Current Assets 146,682 149,098 Deferred Debits and Other Non-Current Assets 280,610 243,573 Total Assets $ 1,270,791 $ 1,257,029 LIABILITIES AND CAPITALIZATION Capitalization: Common Shares, $5 Par Value $ 102,180 $ 102,180 Other Paid-In Capital 221,407 221,160 Common Share Expense (3,931) (3,931) Retained Earnings 53,906 52,404 Total Common Equity 373,562 371,813 Non-Redeemable Preferred Stock - Net 6,900 6,900 Redeemable Preferred Stock - Net 27,468 27,035 Long-Term Debt - Net 334,842 406,337 Total Capitalization 742,772 812,085 Current Liabilities: Long-Term Debt Due Within One Year 72,517 27,512 Notes Payable 57,439 51,848 Accounts Payable 31,711 33,811 Taxes Accrued 3,479 3,004 Interest Accrued 7,363 9,612 Other Current Liabilities 34,222 26,772 Total Current Liabilities 206,731 152,559 Deferred Credits and Other Non-Current Liabilities 156,684 123,209 Accumulated Deferred Taxes 164,604 169,176 Total Liabilities and Capitalization $ 1,270,791 $ 1,257,029 See accompanying notes to consolidated condensed financial statements.
EASTERN UTILITIES ASSOCIATES CONSOLIDATED CONDENSED STATEMENTS OF INCOME (In Thousands Except Number of Shares and Per Share Amounts)
Three Months Ended Nine Months Ended September 30, September 30, 1997 1996 1997 1996 Operating Revenues $ 142,026 $ 131,076 $ 422,635 $ 388,661 Operating Expenses: Fuel 29,278 25,904 82,412 66,563 Purchased Power 28,128 27,391 90,844 86,007 Other Operation and Maintenance 48,076 44,090 141,774 134,031 Early Retirement Offer 0 0 1,416 Depreciation and Amortization 11,484 11,240 34,608 34,038 Taxes - Other Than Income 5,920 5,807 18,259 18,216 Income Taxes - Current 3,030 2,113 14,547 8,915 - Deferred (Credit) 214 1,203 (4,654) (742) Total 126,130 117,748 379,206 347,028 Operating Income 15,896 13,328 43,429 41,633 Other Income - Net 5,886 5,800 15,287 12,200 Income Before Interest Charges 21,782 19,128 58,716 53,833 Interest Charges: Interest on Long-Term Debt 8,041 8,438 24,460 25,707 Other Interest Expense 2,327 1,773 5,759 4,969 Allowance for Borrowed Funds Used During Construction (Credit (128) (472) (610) (1,457) Net Interest Charges 10,240 9,739 29,609 29,219 Net Income 11,542 9,389 29,107 24,614 Preferred Dividends of Subsidiaries 576 578 1,729 1,735 Consolidated Net Earnings $ 10,966 $ 8,811 $ 27,378 $ 22,879 Weighted Average Number of Common Shares Outstanding 20,435,997 20,435,997 20,435,997 20,436,290 Consolidated Earnings Per Average Common Share $ 0.54 $ 0.43 $ 1.34 $ 1.12 Dividends Paid $ 0.415 $ 0.415 $ 1.245 $ 1.23 See accompanying notes to consolidated condensed financial statements.
EASTERN UTILITIES ASSOCIATES CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS (In Thousands)
Nine Months Ended September 30, 1997 1996 CASH FLOW FROM OPERATING ACTIVITIES: Net Income $ 29,107 $ 24,614 Adjustments to Reconcile Net Income to Net Cash Provided from Operating Activities: Depreciation and Amortization 38,909 38,821 Deferred Taxes (5,621) (333) Non-cash Expenses on Sales of Investments in Energy Savings Projects 11,538 3,184 Investment Tax Credit, Net (901) (905) Allowance for Funds Used During Construction (170) (254) Collections and sales of project notes and leases receiv. 12,282 5,891 Other - Net (292) 6,793 Change in Operating Assets and Liabilities 6,095 7,610 Net Cash Provided From Operating Activities 90,947 85,421 CASH FLOW FROM INVESTING ACTIVITIES: Construction Expenditures (47,530) (49,662 Collections on Notes and Lease Receivables of EUA Cogenex 7,685 3,198 Increase in Other Investments (221) (4,036) Net Cash (Used in) Investment Activities (40,066) (50,500 CASH FLOW FROM FINANCING ACTIVITIES: Redemptions: Long-Term Debt (26,555) (18,560 Premium on Reacquisition and Financing Expenses 0 (14) EUA Common Share Dividends Paid (25,443) (25,137 Subsidiary Preferred Dividends Paid (1,729) (1,735) Net Increase in Short-Term Debt 5,591 13,031 Net Cash (Used in) Financing Activities (48,136) (32,415 Net Increase in Cash and Temporary Cash Investments 2,745 2,506 Cash and Temporary Cash Investments at Beginning of Period 12,455 4,060 Cash and Temporary Cash Investments at End of Period $ 15,200 $ 6,566 Supplemental disclosures of cash flow information: Cash paid during the period for: Interest (Net of Capitalized Interest) $ 46,150 $ 31,717 Income Taxes $ 21,482 $ 11,490 Supplemental schedule of non-cash investing activities: Conversion of Investments in Energy Savings Projects to Notes and Leases Receivable $ 4,652 $ 4,813 See accompanying notes to consolidated condensed financial statements.
EASTERN UTILITIES ASSOCIATES NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS The accompanying Notes should be read in conjunction with the Notes to Consolidated Financial Statements incorporated in the Eastern Utilities Associates (EUA or the Company) 1996 Annual Report on Form 10-K and the Company's Quarterly Report on Form 10-Q for the periods ended March 31, and June 30, 1997. Note A - In the opinion of the Company, the accompanying unaudited consolidated condensed financial statements contain all adjustments (consisting of only normal recurring accruals) necessary to present fairly its financial position as of Sept ember 30, 1997 and December 31, 1996, and the results of operations for the three and nine months ended September 30, 1997 and 1996 and cash flows for the nine months ended September 30, 1997 and 1996. In June 1997 the Financial Accounting Standards Board (FASB) issued Statement No. 128, "Earnings per share", which establishes standards for computing and presenting earnings per share (EPS) and applies to entities with publicly held common stock or potential common stock. This Statement simplifies the standards for computing earnings per share previously found in APB Opinion No. 15, "Earnings per share", and makes them comparable to international EPS standards. It also requires dual presentation of basic and diluted EPS on the statement of income for all entities with complex capital structures and requires a reconciliation of the basic EPS computation and the diluted EPS computation. This Statement is effective for financial statements issued for periods ending after December 31, 1997, including interim periods. As of September 30, 1997, the application of this Statement currently does not impact the Company's EPS calculations. In June 1997 the FASB issued Statement No. 130, "Reporting Comprehensive Income", which establishes standards for reporting comprehensive income and its components (revenues, expenses, gains, and losses) in a set of general-purpose financial statements. This Statement requires that all items that are required to be recognized under accounting standards as components of comprehensive income be reported in a financial statement that is displayed with the same prominence as other financial statements. This Statement is effective for fiscal years beginning after December 15, 1997, and EUA will adopt Statement 130 in the first quarter of 1998. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets a nd liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Note B - Results shown above for the respective interim periods are not necessarily indicative of results to be expected for the fiscal years due to seasonal factors which are inherent in electric utilities in New England. A greater proportionate amount of revenues is earned in the first and fourth quarters (winter season) of most years because more electricity is sold due to weather conditions, fewer day-light hours, etc. Note C - Commitments and Contingencies: Recent Nuclear Regulatory Commission (NRC) Actions Millstone III: Montaup has a 4.01% ownership interest in Millstone III, an 1154-mw nuclear unit that is jointly owned by a number of New England utilities, including subsidiaries of Northeast Utilities (Northeast). Northeast is the lead participant in Millstone III. On March 30, 1996, it was necessary to shut down the unit following an engineering evaluation which determined that four safety-related valves would not be able to perform their design function during certain postulated events. The NRC has raised numerous issues with respect to Millstone III and certain of the other nuclear units in which Northeast and its subsidiaries, either individually or collectively, have the largest ownership shares, including Connecticut Yankee (see "Connecticut Yankee" below). In October 1996, the NRC informed Northeast that it was establishing a Special Projects Office to oversee inspection and licensing activities at Millstone. The Special Projects Office is responsible for (1) licensing and inspection activities at Northeast's Connecticut plants, (2) oversight of an Independent Corrective Action Verification Program (ICAVP), (3) oversight of Northeast's corrective actions related to safety issues involving employee concerns, and (4) inspections necessary to implement NRC oversight of the plants' restart activities. Also, the NRC directed Northeast to submit a plan for disposition of safety issues raised by employees and retain an independent third-party to oversee implementation of this plan. In March of 1997, Northeast announced that Millstone III had been designated as the lead unit in the recovery process of the three Millstone nuclear units that are currently out of service. Millstone III is the largest of the three units currently out of service, and its return to service will most benefit the energy needs of the New England region. In September 1997, Northeast announced that it will delay its request to the NRC to restart Millstone III until January 1998, at the earliest. As a result of recent NRC questions as to the status of Millstone III's restart activities, it was noted that various technical issues had not yet been resolved. On October 23, 1997, Northeast presented a revised 1997 budget for Millstone III which included significant increases in operation and maintenance (O&M) expenses. Montaup's share of the revised O&M budget is approximately $11.6 million, approximately $5.6 million more than originally expected and $3.8 million more than O&M expenditures in 1996. While Millstone III is out of service, Montaup will incur incremental replacement power costs estimated at $0.4 million to $0.8 million per month. Montaup bills its replacement power costs through its fuel adjustment clause, a wholesale tariff jurisdictional to the Federal Energy Regulatory Commission (FERC). However, there is no comparable clause in Montaup's FERC-approved rates which at this time would permit Montaup to recover its share of the incremental operation and maintenance costs incurred by Northeast. Montaup pays its share of Millstone III's O&M expenses on a reservation of right basis. The fact that Montaup makes payment for these expenses is not an admission of financial responsibility for expenses incurred or to be incurred due to the outage. In August of 1997, nine non-operating owners, including Montaup, who together own approximately 19.5% of Millstone III, filed a demand for arbitration against Connecticut Light and Power (CL&P) and Western Massachusetts Electric Company ( WMECO) as well as lawsuits against Northeast and its Trustees. CL&P and WMECO, owners of approximately 65% of Millstone III, are Northeast subsidiaries which agreed to be responsible for the proper operation of the unit. The non-operating owners of Millstone III claim that Northeast and its subsidiaries failed to comply with NRC regulations, failed to operate the facility in accordance with good utility operating practice and attempted to conceal their activities from the non- operating owners and the NRC. The arbitration and lawsuits seek to recover costs associated with replacement power and O&M costs resulting from the shutdown of Millstone III. The non-operating owners conservatively estimate that their losses will exceed $200 million. EUA cannot predict the ultimate outcome of the NRC inquiries or legal proceedings brought against CL&P, WMECO and Northeast or the impact which they may have on Montaup and the EUA system. Connecticut Yankee: Connecticut Yankee, a 582-mw nuclear unit, was taken off-line in July 1996 because of issues related to certain containment air recirculation and service water systems. Montaup has a 4.5% equity ownership in Connecticut Yankee with a book value of $ 5.3 million at September 30, 1997. In October 1996, Montaup, as one of the joint owners, participated in an economic evaluation of Connecticut Yankee which recommended permanently closing the unit and replacing its output with less expensive energy sources. In December 1996, the Connecticut Yankee Board of Directors voted to retire the generating station. Connecticut Yankee certified to the NRC that it had permanently closed power generation operations and removed fuel from the reactor. Connecticut Yankee has two years to submit its decommissioning plan to the NRC. The preliminary estimate of the sum of future payments for the permanent shutdown, decommissioning, and recovery of the remaining investment in Connecticut Yankee, is approximately $758 million. The recovery of this estimated amount, elements of which have been disputed by certain intervening parties, is subject to approval of FERC. Montaup's share of the total estimated costs is $34.1 million and is included with Other Liabilities on the Consolidated Balance Sheet for the periods ending September 30, 1997 and December 31, 1996. Also, due to anticipated recoverability, a regulatory asset has been recorded for the same amount and is included with Other Assets. Montaup cannot predict the ultimate outcome of FERC's review. Maine Yankee: On August 6, 1997, as the result of an economic evaluation, the Board of Directors voted to permanently close the Maine Yankee nuclear plant. Montaup has a 4.0% equity ownership in Maine Yankee with a book value of approximately $3.1 million at September 30, 1997. The present estimate of the sum of future payments for the permanent shutdown, decommissioning, and recovery of the remaining investment in Maine Yankee, is approximately $930 million. The recovery of this estimated amount is subject to approval of FERC. Montaup's share of the total estimated costs is $37.2 million and is included with Other Liabilities on the Consolidated Balance Sheet for the period ending September 30, 1997. Also, due to anticipated recoverability, a regulatory asset has been recorded for the same amount and is included with Other Assets. Montaup cannot predict the ultimate outcome of FERC's review. In November 1997, Maine Yankee and Entergy Nuclear, Inc. (Entergy) signed an agreement to renew the contract for Entergy to provide management services to Maine Yankee. Entergy will provide management services for the initial decommissioning of Maine Yankee activities through September 30, 1998. Also, as a result of the August 1997 shutdown, Montaup and the other equity owners have been notified by the Secondary Purchasers that they will no longer make payments for purchased power to Maine Yankee. The Secondary Purchase Contracts a re between the equity owners as a group and 30 municipalities throughout New England. Presently, the equity owners are making the payments to Maine Yankee to cover these unrecovered costs from the municipals. Montaup and the other equity owners will seek payment from the municipals, but cannot predict the outcome of this contract issue at this time. Yankee Atomic Electric Company (Yankee Atomic): Montaup holds a 4.5% equity ownership in Yankee Atomic. In October 1997, Yankee Atomic announced that it had accepted a Duke Engineering and Services (DE&S) Letter of Intent to acquire Yankee Atomic's Nuclear Services Division. Yankee Atomic indicated it was seeking a purchaser with a long-term commitment to excellence in nuclear operations and support services that would continue to provide that level of service to its affiliated New England nuclear plants. Yankee Atomic's plan is to continue as a smaller organization responsible for the completion of the safe and effective decommissioning of the Yankee Nuclear Power Plant in Rowe, Massachusetts. Details of the acquisition have not yet been released. General: Recent actions by the NRC, some of which are cited above, indicate that the NRC has become more critical and active in its oversight of nuclear power plants. EUA is unable to predict at this time, what, if any, ramifications these NRC actions w ill have on any of the other nuclear power plants in which Montaup has an ownership interest or power contract. Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations The following is Management's discussion and analysis of certain significant factors affecting the Company's earnings and financial condition for the interim periods presented in this Form 10-Q. Termination of Power Marketing Joint Venture In the third quarter of 1997, EUA announced the termination of a power marketing joint venture with an affiliate of Duke Energy Corporation and also established provisions for increased legal costs, costs associated with restructuring due to electric industry deregulation and costs (or contingencies) related to certain of its energy related business activities. Collectively, these actions resulted in a net positive after-tax impact of $1.5 million to third quarter 1997 earnings. Overview Consolidated Net Earnings for the third quarter of 1997 were $11.0 million compared to $8.8 million in the third quarter of 1996. The third quarter 1997 earnings include the impact of the termination of EUA's joint venture, discussed above. Net Earnings contributions by Business Unit for the third quarter of 1997 and 1996 were as follows (000's): Increase 1997 1996 (Decrease) Core Electric Business $8,576 $9,915 $(1,339) Energy Related Business 7 (899) 906 Corporate 2,383 (205) 2,588 Consolidated $10,966 $8,811 $2,155 Consolidated Net Earnings for the nine months ended September 30, 1997 were $27.4 million compared to $22.9 million for the same period of 1996. The year-to-date 1997 earnings include the impact of the joint venture termination as well as an after-tax charge of approximately $900,000 related to an early retirement offer recorded in June of 1997. The year-to-date 1996 earnings include a one-time, after-tax charge to earnings of $3.7 million recorded by EUA Cogenex in June 1996. Net Earnings contributions by Business Unit for the first nine months of 1997 and 1996 were as follows (000's): Increase 1997 1996 (Decrease) Core Electric Business $25,696 $28,528 $(2,832) Energy Related Business (767) (4,990) 4,223 Corporate 2,449 (659) 3,108 Consolidated $27,378 $22,879 $ 4,499 The earnings contribution of the Core Electric Business Unit decreased in both the third quarter and year-to-date periods of 1997. These decreases are primarily the result of increased jointly owned unit expenses, including incremental costs related to the extended outage of Millstone III of $1.6 million and $3.5 million in the third quarter and year-to-date periods, respectively. Offsetting these impacts somewhat was increased primary kilowatthour (kWh) sales of approximately 3% in the third quarter and approximately 1% for the year-to-date period ended September 30, 1997. The year-to-date results also include expenses of approximately $1.4 million related to the early retirement offer in June 1997. Net Losses of the Energy Related Business Unit decreased by approximately $900,000 and $4.2 million in the third quarter and year-to-date periods of 1997, respectively, as compared to the same periods of a year ago. EUA Cogenex was profitable for this year's third quarter, an improvement of approximately $1.0 million from its $860,000 loss in the third quarter of 1996. The year-to-date 1996 results include a $3.7 million after-tax charge by EUA Cogenex. In addition to the 1996 charge, EUA Cogenex earnings increased $1.4 million. EUA Energy Investment losses increased by approximately $400,000, largely due to increased marketing expenses of the BIOTEN partnership, partially offset by decreased losses at EUA TransCapacity. The increases in earnings of the Corporate business unit in both the third quarter and year-to-date periods of 1997 are primarily a result of the net impacts of the previously discussed termination of the power marketing joint venture and increased intercompany interest income. Operating Revenues Operating Revenues for the third quarter of 1997 increased by approximately $11.0 million when compared to the same period of 1996. Revenues by Business Unit operations were as follows (000's): Three Months Ended September 30, Increase 1997 1996 (Decrease) Core Electric Business $127,653 $118,211 $ 9,442 Energy Related Business 14,373 12,865 1,508 Corporate 0 0 0 Consolidated $142,026 $131,076 $10,950 Core Electric Business revenues include the impact of recoveries of increased fuel, purchased power and conservation and load management (C&LM) expenses aggregating $5.0 million (see Operating Expense Below) and a 3.1% increase in primarily kWh sales. Base rate increases, effective January 1, 1997 for Blackstone Valley Electric Company (Blackstone) and Newport Electric Company (Newport) pursuant to the Rhode Island Utility Restructuring Act of 1996 (URA) also contributed to the revenue increase. EUA Cogenex revenues, which account for the majority of the Energy Related Business Unit revenues, increased by approximately $1.3 million due primarily to an increase in EUA Citizens revenues. Also impacting Energy Related Business revenues was increased revenues at EUA TransCapacity of approximately $200,000. Operating Revenues for the first nine months of 1997 increased by $34.0 million or 8.7% when compared to the same period of 1996. Operating Revenues by Business Unit for the first nine months of 1997 and 1996 were as follows (000's): Nine Months Ended September 30, Increase 1997 1996 (Decrease) Core Electric Business $376,230 $347,746 $28,484 Energy Related Business 46,405 40,915 5,490 Corporate 0 0 0 Consolidated $422,635 $388,661 $33,974 Core Electric Business revenues increased by $28.5 million due primarily to recoveries of increase fuel, purchased power and C&LM expenses of $21.3 million and increased base rate recoveries related to kWh sales improvement and base rate increases, as discussed above. Energy Related Business revenues increased approximately $5.5 million for the year-to-date period of 1997 as compared to the same period of 1996. EUA Cogenex revenues increased by approximately $5.1 million due primarily to increased Cogenex Division project sales and increased revenues of Cogenex- Canada and EUA Citizens. In addition, EUA TransCapacity revenues increased approximately $400,000 for the year-to-date period. Kilowatthour Sales Primary kWh sales of electricity by EUA's Core Electric Business Unit increased by 3.1% in the third quarter of 1997 compared to the same period last year. This increase was led by increases of 4.7% and 4.6% in the residential and commercial customer classes, which are typically more weather sensitive. Year-to-date September 30, 1997 sales of electricity increased approximately 1% compared to the same period of 1996. Increased kWh sales in the second and third quarter offset t he decreased kilowatthour sales in the first quarter of 1997. Operations Expense Fuel expense of the Core Electric Business increased by approximately $3.4 million or 13.0% and $15.9 million or 23.8% for the third quarter and year-to-date periods of 1997, respectively, as compared to the same periods of 1996. Outages of nuclear units in this year's third quarter and year-to-date period contributed to a greater dependance on higher cost fossil fuels for energy requirements, resulting in increases in average fuel costs of 9.0% and 20.9% for the respective periods. Al so impacting fuel expense were increases in total energy generated and purchased of 3.1% for the third quarter of 1997 and 5.4% for the year-to-date period as compared to the same periods of 1996. Purchased Power demand expense for the third quarter of 1997 increased approximately $700,000 or 2.7% and $4.8 million or 5.6% for the nine months ended September 30, 1997. The third quarter and year-to-date changes are primarily due to the impact of a prior period refund to retail customers from the Pilgrim Nuclear Unit of approximately $2.0 million recorded in the third quarter of 1996, and increased billings from the Maine Yankee unit offset by decreased billings from Connecticut Yankee and the Ocean State Power Project. Other Operation and Maintenance expenses increased by approximately $4.0 million or 9.0% and $7.7 million or 5.8% for the third quarter and the nine months ended September 30, 1997, respectively, as compared to the same periods in 1996. Direct expenses of the Core and Corporate Business units were relatively unchanged in the third quarter and year-to-date periods of 1997. Indirect expenses, items over which there is limited short-term control or items which are fully recovered in rates, increased by $4.1 million and $8.1 million in the third quarter and year-to-date periods of 1997 as compared to the same periods of 1996. The third quarter change was primarily due to incremental expenses related to the Millstone III outage of approximately of $1.5 million, increased C&LM expenses of approximately $1.4 million, and increased FAS106 expenses of $1.5 million, partially offset by lower transmission charges of approximately $400,000. The year-to-date change was primarily due to increased jointly owned units expense of approximately $5.9 million, approximately $3.5 million of which is related to the Mill stone III outage. Also impacting the year-to-date change was increased C&LM expenses of approximately $1.2 million and increased FAS106 expenses of approximately $1.0 million. Expenses of the Energy Related Business unit was relatively unchanged in the third quarter of 1997 and decreased by approximately $400,000 in the and year-to-date period of 1997, respectively. These changes are primarily due to ongoing cost control efforts of EUA Cogenex. Other Income (Deductions) - Net Other Income and (Deductions) - Net was relatively unchanged in this year's third quarter and increased by $3.0 million in the year-to-date period as compared to the same periods of 1996. The year to date increase is due primarily to interest income related to the favorable resolution of a Massachusetts corporate income tax dispute in the first quarter of 1997, the impact of changes to EUA Cogenex pension and post-retirement welfare benefit plans offset by gains recorded in 1996 from the sale of Seabrook II equipment jointly owned by Montaup. Other Interest Expense Other Interest expense increased approximately $600,000 in the third quarter of 1997 and increased approximately $800,000 in the year-to-date period of 1997 as compared to the same periods of 1996. These increases are primarily the result of a reserve of $500,000 recorded in the third quarter of 1997 for interest on Internal Revenue Service audit assessments in addition to interest on increased short term borrowings. Liquidity and Sources of Capital The EUA system's need for permanent capital is primarily related to investments in facilities required to meet the needs of its existing and future customers. Traditionally, cash construction requirements not met with internally generated funds are financed through short-term borrowings which are ultimately funded with permanent capital. In July 1997, several EUA System companies entered into a three-year revolving credit agreement with various financial institutions allowing for borrowings in aggregate of up to $75 million. Outstanding short-term debt at September 30, 1997 and December 31, 1996 by Business Unit was as follows (000's): September 30, 1997 December 31, 1996 Core Electric Business $ 8,250 $ 3,670 Energy Related Business 40,189 24,341 Corporate 9,000 23,837 Consolidated $57,439 $51,848 For the nine months ended September 30, 1997 internally generated funds available after the payment of dividends amounted to approximately $58.8 million while the EUA System's cash construction requirements amounted to approximately $47.5 mil lion for the same period. Various laws, regulations and contract provisions limit the use of EUA's internally generated funds such that the funds generated by one subsidiary are not generally available to fund the operations of another subsidiary. Electric Utility Industry Restructuring On August 7, 1996 the Governor of Rhode Island signed into law the Utility Restructuring Act of 1996 (URA). The URA provides for customer choice of electricity supplier to be phased-in commencing July 1, 1997 for large manufacturing customer s, certain new commercial and industrial customers, and State of Rhode Island accounts. In addition to State of Rhode Island accounts, 11 customers of Blackstone and one customer of Newport were eligible for choice commencing July 1, 1997. As of November 1, 1997, in addition to certain State of Rhode Island accounts, eleven customers exercised their right to choose an alternate supplier of electricity. By July 1, 1998, or sooner, all customers will have retail access. Under the URA the local distribution company will retain the responsibility of providing distribution services to the ultimate electricity consumer within its franchised service territory. For customers who do not choose an alternative supplier, the local distribution company will arrange for supply at a non-discriminatory, "standard offer" price. Distribution companies will also be providers of last resort, required to arrange for supply at prevailing market prices for customers who are unable to obtain their own supply. The URA provides for full recovery of prudently incurred embedded generation costs that might not be recovered in a competitive electric generation market, commonly referred to as "stranded costs," through a non- bypassable transition charge initially set at 2.8 cents per kWh through December 31, 2000. The transition charge recovers, among other things, costs of depreciated generation, net of its market value, regulatory assets, nuclear decommissioning costs and above- market payments t o power suppliers. The costs of net, above-market generation assets and regulatory assets will be recovered, with a return, through a fixed component of the transition charge from July 1, 1997, through December 31, 2009. A variable component of the transition charge will recover, on a reconciling basis, among other things, nuclear decommissioning and above market purchased power commitments from July 1, 1997, through the life of the respective unit or contract. The URA also provides for commitments to demand side management initiatives and renewables, low-income customer protections, divestiture of at least 15% of owned non- nuclear generating units as a valuation basis for mitigation of stranded cost recovery, and performance based rate -making standards for electric distribution companies. These performance based standards provide for a 6% minimum and an approximate 12% maximum allowed return on equity for Blackstone and Newport, EUA's Rhode Island Distribution Companies (R.I. Distribution Companies). In addition, the URA provides for adjustments to electric distribution companies' base rates using the prior year's Consumer Price Index and other performance factors. Under this provision of the law, base rates were increased 1.88% for customers of Blackstone, and 2.18% for our Newport customers effective January 1, 1997. In June 1997, Legislation was enacted in Rhode Island, which would allow securitization of utilities' stranded assets, a method of providing savings to customers. The implementation of the URA requires approvals from applicable regulatory agencies, including the Federal Energy Regulatory Commission (FERC), the Rhode Island Public Utilities Commission (RIPUC), and the Securities and Exchange Commission (SEC). In February 1997, Blackstone, Newport and Montaup reached a settlement in principle with the Rhode Island Division of Public Utilities and Carriers (RIDIV) and the state's Attorney General and filed a Memorandum of Understanding (MOU) with the RIPUC in March 1997 outlining the terms of the settlement. In addition to complying with the URA, the settlement provides for an immediate 10% rate reduction and the filing of a plan to divest all of Montaup's generating assets, and is similar in many respects to the settlement negotiated in Massachusetts, described below. On December 23, 1996, Eastern Edison and Montaup reached an agreement in principle with the Attorney General of Massachusetts and the Massachusetts Department of Energy Resources (MADOER) and filed a MOU with the Massachusetts Department of Public Utilities (MDPU) outlining the terms of a plan, similar in many aspects to the URA, which would allow retail customers to choose their supplier of electricity in 1998 and provide Eastern Edison and Montaup full recovery of "stranded costs." On May 16, 1997 an Offer of Settlement was filed with the MDPU. Hearings on the Offer of Settlement concluded in July 1997 and a MDPU decision is expected by year-end 1997. The Offer of Settlement envisions that all of Eastern Edison's customers will have the ability to choose an alternative supplier of electricity beginning as soon as January 1, 1998. Until a customer chooses an alternative supplier, that customer would receive "standard offer" service which would be priced to guarantee at least a 10% savings from today's electricity rates. Eastern Edison would be required to arrange for "standard offer" service and would purchase power for "standard offer" service from suppliers through a competitive bidding process. The agreement is also designed to achieve full divestiture of Montaup's generating assets via implementation of a plan, that would require (1) separation by Montaup of its generating and transmission businesses, and (2) full market valuation and sale of all generating assets through an auction or equivalent process. Upon the commencement of retail choice in Massachusetts, Montaup's FERC approved, all-requirements wholesale contract with Eastern Edison would be terminated. In its place, Montaup will bill Eastern Edison a Contract Termination Charge (CTC) designed to recover the cost of Montaup's above market, embedded generation commitments to serve Eastern Edison's customers, with a return. Eastern Edison will recover the CTC through a non-bypassable transition access charge to all of its distribution customers. The transition access charge would be reduced by the fair market value of Montaup's generating assets as determined by selling, spinning off, or otherwise disposing of such generating facilities. Embedded costs associated with generating plants and regulatory assets would be recovered, with a return, over a period of 12 years. Purchased power contracts and nuclear decommissioning costs would be recovered as incurred over the life of those obligations, a period expected to extend beyond 12 years. The initial transition access charge would be set at 3.04 cents per kWh through December 31, 2000, and is expected to decline thereafter. The agreement also establishes performance-based regulation for Eastern Edison, incorporating a floor and cap on allowed return on equity. Under the agreement, Eastern Edison's distribution rates would be frozen until December 31, 2000. Sub sequent to the commencement of retail choice, Eastern Edison's annual return on equity would be subject to a floor of 6% and a ceiling of 11.75%. In addition to MDPU approval of the Offer of Settlement, implementation is also subject to the approval of FERC. Elements of the Offer of Settlement which fall under the jurisdiction of FERC were filed with FERC on May 30, 1997 and await review. Any disposition of generation assets resulting from the agreements or the URA would also require the approval of the SEC under the Public Utility Holding Company Act of 1935. On May 1, 1997, Montaup and the R.I. Distribution Companies jointly filed amendments to the FERC-approved all-requirements power contracts between Montaup and the R.I. Distribution Companies, respectively, with FERC. The filing included a calculation for a CTC to recover stranded costs and a provision for standard offer service for resale to retail customers who do not choose an alternate generation supplier. These provisions are intended to ultimately replace the current services offered by the all-requirements contracts upon full retail access pursuant to the URA. The filing also includes "hold harmless" provisions for Montaup's other wholesale customers and for retail customers of the R.I. Distribution Companies, which allow f or recovery of any of Montaup's lost revenues during the initial phases of retail access in Rhode Island. This filing allows the R.I. Distribution Companies to implement on July 1, 1997 the phase-in provisions of the URA and to avoid any cross-subsidies by their retail customers who are excluded from the groups of customers given retail choice prior to the final phase and by Montaup's other customers. The May 1st and May 30th filings were consolidated by FERC and on October 29, 1997, settlement agreements among Montaup, its affiliated and non- affiliated customers, the Massachusetts Attorney General, the MADOER, the RIDIV and RIPUC were submitted for FERC approval. These settlements represent a comprehensive resolution of federal/wholesale issues of electric utility industry restructuring based on the settlement agreements in Massachusetts and Rhode Island. Negotiations in Rhode Island on final settlement terms regarding retail issues of electric utility industry restructuring, are nearing completion, subsequent to which a formal filing will be made to the RIPUC for approval. EUA is currently reviewing legislation that has been introduced in Massachusetts concerning electric industry restructuring. Certain provisions of the legislation as drafted are problematic to the consensus achieved through our negotiated settlement with Massachusetts stakeholders. Historically, electric rates have been designed to recover a utility's full costs of providing electric service including recovery of investment in plant assets. Also, in a regulated environment, electric utilities are subject to certain accounting rules that are not applicable to other industries. These accounting rules allow regulated companies, in appropriate circumstances, to establish regulatory assets and liabilities, which defer the current financial impact of certain costs that are expected to be recovered in future rates. The SEC has raised issues concerning the continued applicability of these standards with certain other electric utilities in other states facing restructuring. The Company believes that its Core Electric operations will continue to meet the criteria established in these accounting standards. In July 1997, the Emerging Issues Task Force (EITF) reached a consensus regarding certain issues raised related to the application of Statement of Financial Accounting Standards No. 71, (FAS71) "Accounting for the Effects of Certain Types of Regulation". The EITF determined that when sufficient detail is available for the enterprise to reasonably determine how the transition plan will affect the separable portion of its business being deregulated, the enterprise should discontinue the application of FAS71 to that deregulated portion of its business. In Massachusetts and Rhode Island, sufficient detail is deemed to be available, upon approval by FERC, of those restructuring plans submitted by EUA in its respective jurisdictions. The EITF further determined that regulatory assets and liabilities originating in the separable portion of the business and no longer subject to rate regulation should be evaluated on the basis of where regulated cash flows to recover those regulatory assets and liabilities will be derived. Based on the current settlement agreements submitted by EUA in Massachusetts and Rhode Island, management does not believe the EITF decisions will have a material effect on EUA. In addition, if legislative or regulatory changes and/or competition result in electric rates which do not fully recover the company's costs, a write-down of plant assets could be required pursuant to Financial Accounting Standard No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of". Other EUA occasionally makes projections of expected future performance or statements of its plans, objectives and new business opportunities which are forward-looking statements under federal securities law. Actual results could differ materially from those discussed and there can be no assurance that such estimates of future results will be achieved. PART II - OTHER INFORMATION Item 1. Legal Proceedings See "Note C - Commitments and Contingencies: Recent Nuclear Regulatory Commission (NRC) Actions - Millstone III" for a discussion of pending legal action involving Montaup, Northeast Utilities, Connecticut Light & Power and Western Massachusetts Electric Company. Item 5. Other Information On April 24, 1996, the FERC issued orders No. 888 and No. 889 to encourage competition in the bulk power market by requiring all public utilities that own, operate or control interstate transmission to file tariffs that offer others the same transmission services they provide themselves, under comparable terms and conditions, establishing the right and a mechanism for recovery of prudently incurred stranded costs and requiring public utilities to implement standards of conduct and an Open Access Same-time Information System (OASIS). FERC also issued a Notice of Proposed Rulemaking (NOPR) requesting comment on replacing the single tariff contained in the final open access rule with a capacity reservation tariff that would reveal how much transmission is available at any given time. Open-access transmission tariffs for point-to-point and local network service were filed with FERC by Montaup in February 1996 and became effective April 21, 1996, subject to refund, for a period of at least one year. The rates in the tariff s were the subject of a settlement agreement which was filed on July 9, 1996 to modify its terms and conditions in conformance with FERC's order. On December 31, 1996, Montaup filed revisions to its Open Access Transmission tariff necessary to comply with FERC's order on September 11, 1996, which dealt with use rights of High Voltage Direct Current (HVDC) interconnection transmission facilities with the Hydro Quebec system and on January 21, 1997, filed additional revisions to coincide with the New England Power Pool (NEPOOL) Open Access Transmission filing (see below). On January 3, 1997, as required by FERC in Order No. 889, Montaup filed its Standards of Conduct Implementation Procedures detailing Montaup's compliance with the requirements of FERC's standards. Coincident with this filing, Montaup complied with OASIS's requirements as part of a region wide OASIS in NEPOOL. On March 4, 1997, FERC issued Orders 888A and 889A which reaffirms the legal and policy bases in which Orders 888 and 889 are grounded and addresses interventions that were filed in response to Orders 888 and 889. As a result, on July 14, 19 97, Montaup filed revisions to its open access transmission service for compliance with FERC Order 888A. The filing incorporates all of the tariff amendments to date. On June 4, 1997, as supplemented on July 14, 1997, Montaup filed with FERC in Docket No. ER97-3200-000 amendments to its open access transmission tariff to provide for unbundled retail transmission service. Montaup proposed to allow retail customers to obtain retail transmission service directly from Montaup or through Montaup's retail affiliates acting as the retail customers' agent. Montaup requested FERC to allow the tariff amendments to become effective for service to retail customers in Blackstone's and Newport's service areas on July 1, 1997. FERC accepted the amendment to become effective subject to refund on that date in an order issued September 12, 1997. FERC accepted the amendment subject to any modification that may be required as a result of other pending proceedings concerning Montaup's transmission tariff and ordered Montaup to make a compliance filing changing the amendments in certain limited respects. The compliance filing was made by Montaup on October 1 0, 1997. NEPOOL is a voluntary organization open to any person engaged in the electric business such as investor-owned utilities, municipals, cooperative utilities, power marketers, brokers and load aggregators. On December 31, 1996, NEPOOL, on behalf of its participants, filed a restructuring proposal with FERC. The NEPOOL restructuring proposal is the product of over two years of intense discussions, deliberations and negotiations among the over 130 NEPOOL member participants and many non-participants, including New England state regulators. The key elements of the restructuring proposal are the implementation of a regional NEPOOL Open Access Transmission Tariff (NEPOOL Tariff), the creation of an Independent System Operator (ISO), and the restatement of the NEPOOL Agreement to establish a broader governance structure for NEPOOL and to develop a more open competitive market structure. The NEPOOL Tariff, which became effective on March 1, 1997, ensures non-discriminatory open access to the regional transmission network by providing a single rate for all transactions that utilize the NEPOOL's bulk power transmission facilities. The NEPOOL Tariff promotes competition in the New England power market through its non-pancaked rate structure. All regional service within NEPOOL, except for wheeling through or out, is to be provided as a network service. On June 25, 1997, FERC issued an order conditionally authorizing the establishment of an ISO by NEPOOL effective July 1, 1997, affirming that the transfer of control of transmission facilities owned by the public utility members of NEPOOL to the ISO is consistent with the public interest under section 203 of the Federal Power Act. NEPOOL is in the process of transferring operational control of the New England bulk power system to the ISO, a newly created non-profit Delaware corporation. The ISO's primary responsibility is to ensure system reliability, administer the NE POOL Tariff, and oversee the efficient and competitive functioning of the regional power market. The selection of the ISO's Board of Directors was announced in April 1997. To give market participants more choice and to foster competition, the restructured NEPOOL proposes the unbundling of electric service in the NEPOOL control area. The restructured NEPOOL calls for the development of competitive wholesale markets for installed capability, operable capability, energy, and reserves. These wholesale products will be market priced based on bid clearing pricing rather than the current cost-based pricing. Market participants will be able to transfer their responsibility for these products by buying or selling these various services through bilateral transactions or through the regional power exchange that will be administered through the ISO. Implementation of the installed capability market is planned for November 1997, the operable capability and energy markets are planned for April 1998, and the reserve markets will follow later in 1998. In general, the EUA System companies support the changes to NEPOOL because much of the cross-subsidies for sharing costs will be eliminated. These changes will have an impact on the Company's operating revenues and costs as NEPOOL transitions from a cost based to a bid based system. Item 6. Exhibits and Reports on Form 8-K (a) Exhibits - None (b) Reports on Form 8-K - On October 2, 1997, the Registrant filed a Current Report on Form 8-K will respect to Item 5 (Other Events). 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. Eastern Utilities Associates (Registrant) Date: November 14, 1997 /s/ Clifford J. Hebert, Jr. Clifford J. Hebert, Jr., Treasurer (on behalf of the Registrant and as Principal Financial Officer) EX-27 2 FDS
OPUR1 1000 9-MOS DEC-31-1997 SEP-30-1997 PER-BOOK 710738 132761 146862 204626 75984 1270791 102180 217476 53906 373562 27468 6900 334842 0 57439 0 72517 0 0 0 398063 1270791 422635 9893 369313 379206 43429 15287 58716 29609 29107 1729 27378 25443 24460 90947 1.245 1.245
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