-----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, GQc/q1rBVmKbmw73aqA0m+L719dYo41xjWTBRh911Hds6qW2GlJuLEbSi8SBbdfL 35VRptXhnwithWxrFjprRQ== 0000031224-99-000044.txt : 19991117 0000031224-99-000044.hdr.sgml : 19991117 ACCESSION NUMBER: 0000031224-99-000044 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 2 CONFORMED PERIOD OF REPORT: 19990930 FILED AS OF DATE: 19991115 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: 99754632 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 1999 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, 1999 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, 1999 Common Shares, $5 par value 20,435,997 shares PART I - FINANCIAL INFORMATION EASTERN UTILITIES ASSOCIATES CONSOLIDATED CONDENSED BALANCE SHEETS (In Thousands) Item 1. Financial Statements
September 30, December 31, ASSETS 1999 1998 Utility Plant and Other Investments: Utility Plant in Service $ 927,473 $ 1,000,243 Less: Accumulated Provision for Depreciation and Amortization 331,658 353,780 Net Utility Plant in Service 595,815 646,463 Construction Work in Progress 12,206 5,151 Net Utility Plant 608,021 651,614 Investments in Jointly Owned Companies 66,201 69,485 Non-Utility Plant - Net 47,410 55,274 Total Plant and Other Investments 721,632 776,373 Current Assets: Cash and Temporary Cash Investments 2,521 32,090 Accounts Receivable, Net 96,802 95,267 Notes Receivable 22,651 27,078 Fuel, Materials and Supplies 5,120 13,434 Other Current Assets 5,393 8,448 Total Current Assets 132,487 176,317 Deferred Debits and Other Non-Current Assets 626,910 349,948 Total Assets $ 1,481,029 $ 1,302,638 LIABILITIES AND CAPITALIZATION Capitalization: Common Shares, $5 Par Value $ 102,180 $ 102,180 Other Paid-In Capital 220,279 218,959 Common Share Expense (3,931) (3,931) Retained Earnings 39,479 56,466 Total Common Equity 358,007 373,674 Non-Redeemable Preferred Stock - Net 6,900 6,900 Redeemable Preferred Stock - Net 28,268 27,995 Long-Term Debt - Net 127,318 310,346 Total Capitalization 520,493 718,915 Current Liabilities: Long-Term Debt Due Within One Year 62,530 21,911 Notes Payable 117,468 63,574 Accounts Payable 29,318 29,018 Taxes Accrued 14,807 14,208 Interest Accrued 2,934 6,997 Other Current Liabilities 144,942 34,908 Total Current Liabilities 371,999 170,616 Deferred Credits and Other Non-Current Liabilities 462,986 271,078 Accumulated Deferred Taxes 125,551 142,029 Total Liabilities and Capitalization $ 1,481,029 $ 1,302,638 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, 1999 1998 1999 1998 Operating Revenues $ 141,723 $ 136,033 $ 414,043 $ 405,385 Operating Expenses: Fuel and Purchased Power 61,878 52,554 186,770 158,266 Other Operation and Maintenance 41,855 44,513 121,431 129,660 Depreciation and Amortization 10,384 13,032 33,845 39,015 Taxes - Other Than Income 5,229 6,058 16,459 17,873 Income Taxes - Current 5,294 5,336 20,645 7,496 - Deferred (Credit) (380) (922) (6,888) 6,590 Total 124,260 120,571 372,262 358,900 Operating Income 17,463 15,462 41,781 46,485 Other Income and (Deductions): Energy Related Asset Adjustments (24,669) Income Tax Impact of Energy Related Asset Adjustments 8,973 Other Income - Net 2,626 3,431 8,744 9,172 Income Before Interest Charges 20,089 18,893 34,829 55,657 Interest Charges: Interest on Long-Term Debt 4,865 6,592 17,783 21,726 Other Interest Expense 3,023 2,700 6,953 6,416 Allowance for Borrowed Funds Used During Construction (Credit) (102) (187) (366) (415) Net Interest Charges 7,786 9,105 24,370 27,727 Net Income 12,303 9,788 10,459 27,930 Preferred Dividends of Subsidiaries 576 576 1,729 1,729 Consolidated Net Earnings $ 11,727 $ 9,212 $ 8,730 $ 26,201 Weighted Average Number of Common Shares Outstanding 20,435,997 20,435,997 20,435,997 20,435,997 Consolidated Basic and Diluted Earnings Per Average Common Share $ 0.57 $ 0.45 $ 0.43 $ 1.28 Dividends Paid $ 0.415 $ 0.415 $ 1.245 $ 1.245 See accompanying notes to consolidated condensed financial statements.
EASTERN UTILITIES ASSOCIATES CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS (In Thousands)
Nine Months Ended September 30, 1999 1998 CASH FLOW FROM OPERATING ACTIVITIES: Net Income $ 10,459 $ 27,930 Adjustments to Reconcile Net Income to Net Cash Provided from Operating Activities: Depreciation and Amortization 34,983 42,797 Deferred Taxes (13,737) 6,860 Non-cash Expenses on Sales of Investments in Energy Savings Projects 7,719 7,201 Energy Related Asset Adjustments 23,813 Investment Tax Credit, Net (2,205) (1,173) Allowance for Funds Used During Construction (275) (94) Collections and Sales of Project Notes & Leases Receivable 5,229 10,133 Other - Net (1,367) (4,158) Regulatory Asset - Purchased Power Contract Buyout (105,623 Change in Operating Assets and Liabilities (6,688) (20,813) Regulatory Liability - Purchased Power Contract Buyout 105,623 Net Cash Provided From Operating Activities 57,931 68,683 CASH FLOW FROM INVESTING ACTIVITIES: Construction Expenditures (39,121) (36,100) Proceeds from Divestiture of Generating Assets 57,445 Collections on Notes and Lease Receivables of EUA Cogenex 13,355 12,013 Increase in Other Investments (2,149) Net Cash Provided From (Used in) Investment Activities 31,679 (26,236) CASH FLOW FROM FINANCING ACTIVITIES: Redemptions of Long-Term Debt (142,859 (71,061) Premiums Paid on Long-Term Debt Redemptions (3,042) EUA Common Share Dividends Paid (25,443) (25,443) Subsidiary Preferred Dividends Paid (1,729) (1,729) Net Increase in Short-Term Debt 53,894 55,179 Net Cash (Used in) Financing Activities (119,179 (43,054) Net (Decrease) in Cash and Temporary Cash Investments (29,569) (607) Cash and Temporary Cash Investments at Beginning of Period 32,090 7,252 Cash and Temporary Cash Investments at End of Period $ 2,521 $ 6,645 Supplemental disclosures of cash flow information: Cash paid during the period for: Interest (Net of Capitalized Interest) $ 24,078 $ 24,343 Income Taxes $ 15,298 $ 17,274 Supplemental schedule of non-cash investing activities: Conversion of Investments in Energy Savings Projects to Notes and Leases Receivable $ 267 $ 2,159 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) 1998 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, 1999. 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 September 30, 1999 and December 31, 1998, and the results of operations for the three and nine months ended September 30, 1999 and 1998 and cash flows for the nine months ended September 30, 1999 and 1998. The year-end consolidated condensed balance sheet data was derived from audited financial statements but does not include all disclosures required under generally accepted accounting principles. In June 1998, the Financial Accounting Standards Board (FASB) issued SFAS 133, Accounting for Derivative Instruments and Hedging Activities, which is effective for fiscal years beginning after June 15, 1999. In June 1999, the FASB issued SFAS 137, Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date, which amends SFAS 133 to be effective for all fiscal quarters of all fiscal years beginning after June 15, 2000 (that is, January 1, 2001 for companies with calendar-year fiscal years). SFAS 133 requires the recognition of all derivative instruments as either assets or liabilities in the statement of financial position and the measurement of those instruments at fair value. The Company does not expect SFAS 133 to have a material impact on its financial position or results of operations. 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 and 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. In July 1999, EUA filed an application under the Public Utility Holding Company Act with the Securities and Exchange Commission (SEC) requesting authorization for Eastern Edison to transfer all of Eastern Edison's investment in Montaup's securities, including Montaup's preferred stock, common stock and debenture bonds, to EUA. Montaup would then become a wholly-owned subsidiary of EUA. Also related to this transfer, Eastern Edison filed a Petition for Approval of the transfer or Request for Alternative Findings of No Jurisdiction with the Massachusetts Department of Telecommunications and Energy (MDTE). A public hearing was held at the MDTE on October 18, 1999 at which no one from the public intervened. Eastern Edison is awaiting a decision from the MDTE on its petition, and expects it will receive SEC approval shortly thereafter. In July 1999, in connection with Entergy Nuclear Generation Company's (Entergy) acquisition of Pilgrim Station from Boston Edison, Montaup agreed to buy out its power purchase agreement (approximately 73 mw) with Boston Edison. As a condition of the buy-out, Montaup entered into a reduced term power purchase contract for Pilgrim Station power with Entergy. Accordingly, Montaup has recorded on EUA's Consolidated Balance Sheet as of September 30, 1999, a regulatory asset of approximately $113.4 million, a corresponding current regulatory liability of $105.6 million, and a long-term regulatory liability of $7.8 million. 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: Nuclear Ownership Issues General: Recent actions by the NRC 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 will have on any of the other nuclear power plants in which Montaup has an ownership interest or power contract. Millstone 3: Montaup has a 4.01% ownership interest in Millstone 3, an 1,154 mw nuclear unit that is jointly owned by a number of New England utilities, including subsidiaries of Northeast Utilities (Northeast). Subsidiaries of Northeast are the lead participants in Millstone 3. 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. In October 1996, the NRC, which had raised numerous issues with respect to Millstone 3 and certain of the other nuclear units in which Northeast and its subsidiaries, either individually or collectively, have the largest ownership shares, informed Northeast that it was establishing a Special Projects Office to oversee inspection and licensing activities at Millstone. During the first week of July 1998, after the NRC performed an inspection and verified that several final technical and programmatic issues were resolved, Millstone 3 was restarted, and returned to full power operation on July 14, 1998. The NRC will continue to closely monitor Millstone 3's performance. In August 1997, nine non-operating owners, including Montaup, who together own approximately 19.5% of Millstone 3, 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 3, are Northeast subsidiaries that agreed to be responsible for the proper operation of the unit. The non-operating owners of Millstone 3 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 operation and maintenance (O&M) costs resulting from the shutdown of Millstone 3. The non-operating owners conservatively estimate that their losses exceed $200 million. In December 1997, Northeast filed a motion to dismiss the non- operating owners' claims, or alternatively to stay the pending lawsuit until after the resolution of the arbitration case. These requests were denied in July 1998. In May 1999, Northeast filed a request for summary judgement in the arbitration case. This request was denied in July 1999. In May 1999, all parties entered into a Alternative Dispute Resolution Agreement and began mediation sessions in an effort to reach a settlement of all issues. Montaup understands that Northeast and its subsidiaries, the Connecticut Light and Power Company and Western Massachusetts Electric Company have agreed in principle with New England Power Company (NEP) a subsidiary of New England Electric System, to settle various arbitration and litigation claims asserted by NEP, Montaup and the other non-operating owners of Millstone 3. A settlement on comparable terms has been offered to Montaup. Montaup will give serious consideration to the advisability of the settlement as proposed. Montaup paid its share of Millstone 3's O&M expenses during the prolonged outage on a reservation of right basis. The fact that Montaup paid these expenses is not an admission of financial responsibility for expenses incurred during the outage. Given the recent settlement offered to Montaup, the Company does not expect the outcome of these proceedings to have a material effect on its operating results or financial position. Maine Yankee: Montaup has a 4.0% equity ownership in the permanently closed Maine Yankee nuclear plant. Montaup's share of the total estimated costs for the permanent shutdown, decommissioning, and recovery of the remaining investment in Maine Yankee is approximately $26.5 million and is included with Other Liabilities on the Consolidated Balance Sheet as of September 30, 1999. Also, due to recoverability, a regulatory asset has been recorded for the same amount and is included with Other Assets. On November 6, 1997, Maine Yankee submitted an estimate of its costs, including recovery of unamortized plant investment (including fuel), to FERC reflecting the fact that the plant was no longer operating and had entered the decommissioning phase. On January 14, 1998, the FERC accepted the new rates, subject to refund, and amounts of Maine Yankee's collections for decommissioning. On January 19, 1999, Maine Yankee and the active intervening parties, including the Secondary Purchasers, filed an Offer of Settlement with FERC which was supported by FERC trial staff on February 8, 1999. The FERC approved the Settlement effective June 1, 1999. This agreement constitutes full settlement of the issues raised in this proceeding. Also, as a result of the shutdown, Montaup and the other equity owners were notified by the Secondary Purchasers that they would no longer make payments for purchased power to Maine Yankee. The Secondary Purchase Contracts are between the equity owners as a group and 30 municipalities throughout New England. Presently, the equity owners are making payments to Maine Yankee to cover the payments that would be made by the municipals. On November 28, 1997, the Secondary Purchasers sent a Notice of Initiation of Arbitration to the equity owners of Maine Yankee, which was denied by a Maine judge on April 7, 1998. The judge indicated that the jurisdictional question should be first decided by FERC. On December 15, 1997, the equity owners as a group filed at FERC a Complaint and Petition for Investigation, Contract Modification, and Declaratory Order. A separately negotiated Settlement Agreement filed with FERC on February 5, 1999, was approved by FERC and made effective on June 1, 1999. This settlement resolved issues raised by the Secondary Purchasers by limiting the amount they will pay for decommissioning and settling other points of contention. The outcome of these recent settlements will not have a material effect on EUA's future operating results or financial position. On August 4, 1998, the Maine Yankee Board of Directors selected Stone & Webster Engineering Corporation to execute a $250 million contract for the decommissioning and decontamination of Maine Yankee. The decommissioning plan includes an option for Stone & Webster to repower the Maine Yankee site with a gas-fired plant. Vermont Yankee: Montaup has a 2.5% equity ownership interest in the 540-mw Vermont Yankee nuclear unit. On October 15, 1999, Vermont Yankee accepted a bid from AmerGen Energy Company for AmerGen to purchase the unit for approximately $23.5 million. As part of the agreement, Vermont Yankee will make a one-time payment to the unit's decommissioning fund, and AmerGen will assume responsibility for all future operating costs and costs to decommission the plant at the end of its operating licence in 2012. Vermont Yankee expects to complete this sale by mid-2000. This transaction is subject to approvals from the NRC, the SEC, and the Vermont Public Service Board. Department of Energy Actions: In early 1998, Yankee Atomic, Maine Yankee and Connecticut Yankee, individually, as well as a number of other utilities, filed suit in federal appeals court seeking a court order to require the Department of Energy (DOE) to immediately establish a program for the disposal of spent nuclear fuel. Under the Nuclear Waste Policy Act of 1992, the DOE was to provide for the disposal of radioactive wastes and spent nuclear fuel starting in 1998 and has collected funds from owners of nuclear facilities to do so. On February 19, 1998, Maine Yankee also filed a petition in the U.S. Court of Appeals seeking to compel the Department of Energy to remove and dispose of the spent fuel at the Maine Yankee site. Under their Standard Contract, the DOE had a deadline for beginning the removal process at all nuclear plants on January 31, 1998, which was not met. On May 5, 1998, the Court of Appeals denied several motions brought in the proceeding, including several motions for injunctive relief brought by the utility petitioners. In particular, the Court denied the requests to require the DOE to immediately establish a program for the disposal of spent nuclear fuel. Also, Yankee Atomic, Connecticut Yankee, and Maine Yankee filed lawsuits against the DOE in the U.S. Court of Federal Claims seeking damages of $70 million, $90 million and $128 million, respectively, as a result of the DOE's refusal to accept the spent nuclear fuel. In late October and early November 1998, the U.S. Court of Federal Claims issued rulings with respect to Yankee Atomic, Maine Yankee, and Connecticut Yankee finding that the DOE was financially responsible for failing to accept spent nuclear fuel. These rulings clear the way for Yankee Atomic, Connecticut Yankee and Maine Yankee to pursue at trial their individual damage claims. These trials are expected to begin in early 2000. Management cannot predict at this time the ultimate outcome of these actions. Environmental Matters During the second quarter of 1999, EUA identified four new sites related to the production of manufactured gas at which certain environmental conditions may exist. Three sites are associated with Blackstone and one site is associated with Eastern Edison. EUA has conducted a preliminary assessment of the potential cost of remediation at these sites. An engineering model was recently obtained by the Company to provide the estimated potential costs. Since site specific studies have not yet been performed, EUA has recorded a minimum liability for each of these sites based on this engineering model to recognize risk assessment, monitoring, and legal and administrative costs. In addition, EUA has recorded estimated environmental remediation liabilities for two previously-identified manufactured gas plant sites associated with Blackstone. The sites are the Tidewater site, the location of a former electric generating station, and manufactured gas plant in Pawtucket, Rhode Island, and the Hamlet Avenue Site, a former manufactured gas plant site located in Woonsocket, Rhode Island. Estimates were not previously recorded for these locations since site-specific studies had not been completed and a reliable engineering model deemed essential to develop a reasonable estimate was not previously available. With respect to the Tidewater site, EUA completed its site investigation study during the third quarter of 1999 to determine the nature and extent of contamination and has determined that extensive elevated levels of hazardous substances are present in the surface and subsurface. The Hamlet Street site assessment has not yet been finalized. However, the assessment conducted to date has determined that varying degrees of hazardous substance are present at that site. In the third quarter of 1999, a total estimated remediation liability of $21.2 million was recorded as a long-term liability with a corresponding charge to a regulatory asset on the Consolidated Balance Sheet. Blackstone and Eastern Edison are currently recovering certain environmental cleanup costs in rates. In addition, the Company will seek recovery of certain costs from its insurance carriers and other possible responsible parties. The Company expects, based on prior regulatory approvals, to recover such costs in future rates. As a result, the Company does not believe that the ultimate impact of the cleanup costs associated with these sites will be material to the results of its operations or its financial position. Note D - Financial Information by Business Segment: The following provides information on segments. The Core Electric business includes results of the electric utility operations of Blackstone, Eastern Edison, Newport and Montaup. Energy Related Business includes results of our diversified energy related subsidiaries, EUA Cogenex, EUA Ocean State, EUA Energy Investment Corporation, EUA Energy Services and EUA Telecommunications. Corporate results include the operations of EUA Service and EUA Parent. EUA does not have any intersegment revenues. Financial data for the business segments are as follows (000's): Three Months Ended Nine Months Ended September 30, 1999 September 30, 1999 Operating Net Operating Net Revenues Income Revenues Income Core Electric $125,204 $12,352 $374,504 $26,675 Energy Related 16,519 (1,415) 39,539 (2,749) Corporate 790 500 Subtotal 141,723 11,727 414,043 24,426 Energy Related Asset Adjustments (15,696) Total $141,723 $11,727 $414,043 $8,730 Three Months Ended Nine Months Ended September 30, 1998 September 30, 1998 Operating Net Operating Net Revenues Income Revenues Income Core Electric $120,460 $8,602 $361,008 $26,710 Energy Related 15,573 155 44,377 (731) Corporate 455 222 Total $136,033 $9,212 $405,385 $26,201 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. Merger Update On February 1, 1999, EUA and New England Electric System (NEES) announced a merger agreement under which NEES will acquire all outstanding shares of EUA for $31 per share in cash. The merger agreement, which is subject to the approval of various regulatory agencies, values EUA's equity at approximately $634 million, which represents a 23% premium above the price of EUA shares on December 4, 1998, the last trading day before other regional merger announcements affected EUA's share price. EUA shareholders will continue to receive dividends at the current level, as declared by the Board of Trustees, until the closing of the merger. The closing of the merger is expected to occur by early 2000. The merger agreement contains an upward price adjustment in the event the merger does not close within six months from May 17, 1999, the date EUA shareholders approved the merger plan. Therefore, after November 17, 1999, NEES will pay an additional $0.003 per day per share for EUA's outstanding common stock until the merger closes, up to a maximum price of $31.495 per share. On May 5, 1999, EUA and NEES filed a joint application with the Federal Energy Regulatory Commission (FERC) seeking FERC approval and related waivers or authorizations to merge EUA and NEES and to subsequently merge and consolidate the complimentary operating companies of EUA and NEES. With its approval on September 29, 1999, FERC concluded that the proposed merger will not adversely affect competition, rates or regulation, and that the merger is in the public's best interest. On May 20, 1999, EUA and NEES jointly filed a rate consolidation plan with the Rhode Island Public Utilities Commission reflecting consolidated rates for each company's Rhode Island subsidiaries, indicating savings to Rhode Island customers of approximately $79 million. Hearings are scheduled to start in December 1999. A similar filing was made for EUA's and NEES's Massachusetts subsidiaries on April 30, 1999 with the Massachusetts Department of Telecommunications and Energy (MDTE) indicating savings of over $100 million. A settlement agreement on the Massachusetts filing is expected shortly. On July 19, 1999, a Voluntary Early Retirement Program (VERP) was offered to certain of EUA's and NEES's employees who will be at least fifty-five years of age by December 31, 2000. The VERP offer was accepted by 82% of eligible employees. On October 12, 1999, details of a Severance Plan were distributed. The Severance Plan will provide benefits and provisions for eligible non-union employees who are involuntarily terminated due to the merger. At the same time, the Company also offered a Limited Hardship Early Decision Severance Plan (LHEDO) to designated non-union employees who choose to terminate their employment with EUA rather than be considered for a position in the merged company. Employees who were offered the LHEDO must decide if they will accept the offer by November 29, 1999. Under the LHEDO, employees will receive an additional eight weeks of severance pay for accepting the offer. At this time, EUA cannot reasonably estimate the participation in the LHEDO. Therefore, expenses related to this plan have not yet been recorded. Overview Consolidated Net Earnings for the third quarter of 1999 were approximately $11.7 million compared to approximately $9.2 million in the third quarter of 1998. Net Earnings contributions by Business Unit for the third quarter of 1999 and 1998 were as follows (000's): Increase 1999 1998 (Decrease) Core Electric Business $12,352 $8,602 $3,750 Energy Related Business (1,415) 155 (1,570) Corporate 790 455 335 Consolidated $11,727 $9,212 $2,515 Consolidated Net Earnings for the nine months ended September 30, 1999 were $8.7 million compared to $26.2 million for the same period of 1998. The year-to-date 1999 earnings include the impact of non-recurring after-tax charges of approximately $15.7 million, related to the discontinuance of certain of EUA's energy related activities, discussed below. Net Earnings contributions by Business Unit for the first nine months of 1999 and 1998 were as follows (000's): Increase 1999 1998 (Decrease) Core Electric Business $26,675 $26,710 $(35) Energy Related Business (2,749) (731) (2,018) Corporate 500 222 278 Subtotal $24,426 $26,201 $(1,775) Energy Related Asset Adjustment (15,696) (15,696) Consolidated $ 8,730 $26,201 $(17,471) Energy Related Asset Adjustments The year-to-date 1999 results include non-recurring after-tax charges made in the second quarter of 1999 of $15.7 million, or 77 cents per common share, related to the discontinuance of certain of EUA's energy related activities. These charges were consistent with EUA's efforts in evaluating its investments in energy related projects, and were a result of several pending sales offers and completed sales for its interest in certain of these investments. These non-recurring charges have settled future uncertainty associated with these investments and are as follows: - EUA BIOTEN has executed an agreement with the management of BIOTEN G.P. to, among other things, extend the right of its management to purchase BIOTEN G.P.'s assets. As a result, EUA Energy Investment recorded an after-tax charge to its earnings of approximately $9.4 million in the second quarter of 1999. - On September 30, 1999 EUA Energy Investment sold certain of RENOVA LLC's assets to its management. Due to after-tax charges of approximately $3.5 million recorded for this anticipated sale in the second quarter of 1999 based on a tentative agreement, this transaction did not have an impact on third quarter 1999 earnings. - On August 30, 1999, EUA TransCapacity, sold all of its assets in TransCapacity L.P. and dissolved the TransCapacity Partnership. EUA Energy Investment will not have any further obligations or commitments to TransCapacity L.P., its employees, or its successor. The after-tax loss of $900,000 on this transaction was offset by previously-established reserves at EUA's parent company. - As of June 28, 1999, the management of EUA Cogenex decided to divest certain of its businesses and activities including EUA Citizens Conservation Services, Inc., and the EUA DAY and DayMetrix divisions. EUA Cogenex has received an offer from the management of the EUA DAY division to purchase the business and assets of EUA Day from EUA Cogenex. This offer is still pending. EUA Cogenex anticipates closing this sale by the end of 1999. EUA Cogenex recorded an after-tax charge of $2.9 million in the second quarter of 1999 as a result of this anticipated sale and cessation of continued development of the DayMetrix division. In addition, EUA Cogenex has hired an investment banker to assist in the possible sale of EUA Citizens Conservation Services, Inc. There can be no assurance that EUA Cogenex will consummate a sale of EUA Citizens. Earnings by Business Unit The earnings contribution of the Core Business Unit increased by approximately $3.8 million in the third quarter and were relatively unchanged in the year-to-date period of 1999. Significant increases in primary kilowatthour sales mitigated the impacts of rate reductions pursuant to approved utility restructuring agreements in both the third quarter and year-to-date periods. Warmer weather in this year's third quarter and the continued strength of the regional economy resulted in 8.2% and 4.7% increases in kilowatthour sales for the quarter and year-to-date periods, respectively. Also impacting earnings was the decrease in interest expense in both the third quarter and year to date periods since Eastern Edison redeemed all of its remaining First Mortgage Bonds in July of 1999. Net losses of the Energy Related Business Unit increased by approximately $1.6 million in the third quarter and approximately $2.0 million in the year-to-date period compared to the same periods of 1998. EUA Cogenex posted a loss of approximately $200,000 in the third quarter of 1999, compared to earnings of approximately $400,000 in the third quarter of 1998. Excluding the charge of $2.9 million recorded in the second quarter of 1999 related to the pending sale of EUA Day and the cessation of the development of DayMetrix, operating losses at EUA Cogenex were $1.2 million in the year-to-date period of 1999 compared to minimal earnings in the same period of 1998 as a result of decreased project sales in both periods. EUA Energy Investment generated losses of $2.2 million and $4.4 million for the third quarter and year-to-date periods, respectively, approximately $900,000 and $800,000 greater than the losses generated in the respective periods of 1998. On August 30, 1999, EUA TransCapacity, sold all of its assets in TransCapacity L.P. and dissolved the TransCapacity Partnership. EUA Energy Investment will not have any further obligations or commitments to TransCapacity L.P., its employees, or its successor. The after-tax loss of $900,000 on this transaction was offset by previously-established reserves at EUA's parent company. Therefore, consolidated operating results were not impacted by this transaction. Excluding this transaction, EUA Transcapacity's net losses decreased $300,000 in the third quarter and $500,000 in the year-to-date period as a result of decreased operating activity. In addition, on September 30, 1999, EUA Energy Investment sold certain assets of Renova LLC to its management. Due to after-tax charges of approximately $3.5 million recorded for this sale in the second quarter of 1999 based on a tentative agreement, this transaction did not have an impact on third quarter 1999 earnings. Renova's operating net losses increased $400,000 in the third quarter and $600,000 in the year-to-date periods as compared to the same periods of 1998. The changes in the Corporate business unit's earnings contribution in the third quarter and year-to-date periods reflect the utilization of previously established reserves for the loss on the sale of Transcapacity L.P. in the third quarter of 1999, discussed above. These increases were offset by interest expense on increased short term borrowings used to partially finance Eastern Edison's redemption of its First Mortgage Bonds in July of 1999. Operating Revenues Operating Revenues for the third quarter of 1999 increased by approximately $5.7 million or 4.2% when compared to the same period of 1998. Revenues by Business Unit operations were as follows (000's): Three Months Ended September 30, Increase 1999 1998 (Decrease) Core Electric Business $125,204 $120,460 $4,744 Energy Related Business 16,519 15,573 946 Corporate 0 0 0 Consolidated $141,723 $136,033 $5,690 Core Electric Business revenues increased approximately $4.7 million in the third quarter of 1999 as compared to the same period of 1998. Generation-related revenues increased approximately $1.9 million as a result of the assignment of entitlements from certain power contracts to third parties and associated repurchases and sale of energy to satisfy standard offer requirements. This increase was compounded by the implementation of increased wholesale standard offer rates and offset by a reduction in contract termination charge rates, effective January 1, 1999 and April 1, 1999 respectively. Distribution-related revenues increased approximately $2.9 million primarily due to the impacts of increased kWh sales of 8.2% for the period. Revenues of the Energy Related business unit increased by approximately $900,000 in the third quarter of 1999 compared to the same period of 1998. Increases at Citizens, Cogenex-Canada, Cogenex West and the Cogenex Partnerships aggregating $4.0 million as a result of recently completed projects were offset by decreased project sales at the Cogenex Division and EUA Day of approximately $3.0 million. Operating Revenues for the first nine months of 1999 increased by approximately $8.7 million or 2.1% when compared to the same period of 1998. Operating Revenues by Business Unit for the first nine months of 1999 and 1998 were as follows (000's): Nine Months Ended September 30, Increase 1999 1998 (Decrease) Core Electric Business $374,504 $361,008 $13,496 Energy Related Business 39,539 44,377 (4,838) Corporate 0 0 0 Consolidated $414,043 $405,385 $8,658 Core Electric Business revenues increased approximately $13.5 million for the first nine months of 1999 when compared to the same period of 1998. Generation-related revenues increased approximately $13.1 million as a result of the aforementioned repurchases of energy. Offsetting this increase were impacts of rate reductions to Massachusetts retail customers, pursuant to electric industry restructuring legislation and settlements effective March 1, 1998. An additional reduction in wholesale rates resulted from the implementation of lower contract termination charge rates, offset by increased standard offer rates. Distribution-related revenues decreased approximately $600,000. The net impacts of restructured rates in Massachusetts for a full period were partially offset by the impacts of increased kWh sales for the period. Revenues of the Energy Related business unit decreased by approximately $4.8 million in the nine months ended September 1999 compared to the same period of 1998. Energy savings project sales, paid from savings, and note and lease projects sales of the EUA Cogenex division decreased approximately $6.7 million in aggregate. In addition, decreased revenues of the EUA Cogenex Partnerships and EUA Day aggregating $3.4 million were offset by increased revenues from Citizens, Cogenex-Canada and Cogenex West amounting to approximately $4.6 million. An increase in Renova revenues of approximately $300,000 further offset this decrease. Kilowatthour (kWh) Sales Kilowatthour (kWh) sales increased 8.2% in the third quarter of 1999 and 4.7% in the year-to-date period of 1999 as compared to the same periods of 1998, largely the result of strong economic conditions in EUA's service territory and warmer weather in 1999, particularly during the months of August and September 1999. These changes were led by 10.5% and 7.3% increases in sales to residential customers and 7.5% and 4.8% increases in sales to commercial customers in the third quarter and year-to-date periods, respectively. Operations Expense Fuel and Purchased Power expenses, increased approximately $9.3 million, or 17.7% in the third quarter of 1999 as compared to the same period of 1998. This increase was primarily due to the aforementioned assignment of entitlements from certain power contracts which resulted in repurchases of energy to satisfy standard offer requirements. This increase was compounded by an 8.2% increase in kWh sales in the third quarter of 1999. For the year-to-date period, Fuel and Purchased Power expenses increased approximately $28.5 million, or 18.0%. The requirement to satisfy standard offer needs discussed above, compounded by a 4.7% increase in kWh sales contributed to this increase. Other Operation and Maintenance (O&M) expenses decreased by approximately $2.7 million or 6.0% and $8.2 million or 6.4% for the third quarter and the nine months ended September 30, 1999, respectively, as compared to the same periods in 1998. Total O&M expenses are comprised of three components: Direct, Indirect and Energy Related. Direct expenses of the Core and Corporate Business units decreased by approximately $2.5 million in the third quarter of 1999 and by $1.2 million for the year-to-date period of 1999 as compared to the same periods of 1998. The third quarter change is primarily due to decreased expenses since the sale of Montaup's Somerset plant in April 1999. In the year-to-date period, these decreases were offset by the impacts of adjustments to 1998 employee incentive plan accruals in the first quarter of 1999 and non-recurring expense credits related to billings to Maine utilities for EUA's storm restoration support in February of 1998. Indirect expenses, items over which there is limited short-term control or items which are fully recovered in rates, decreased approximately $2.7 million in the third quarter and $5.9 million in the year-to-date period as compared to the same periods of 1998. Conservation and load management (C&LM) expenses decreased approximately $700,000 and $1.5 million in the respective periods. In addition, jointly-owned units expenses decreased approximately $1.6 million and $4.1 million, respectively, largely due to decreased expenses of Canal 2 after the sale of the unit in December 1998. In addition, FAS106 expenses decreased by approximately $400,000 in both the third quarter and year-to-date periods, respectively. Expenses of the Energy Related Business Unit increased approximately $2.5 million in the third quarter of 1999. This change was the result of increases at Citizens, Cogenex-Canada and the Cogenex Partnerships aggregating approximately $3.7 million as a result of increased operating activity in the quarter. This increase was partially offset by decreased expenses of the Cogenex Division of approximately $800,000. The effects of decreased operating activity at the Cogenex Division and EUA Day were mitigated by increased bad debt, pension and benefit expenses in the third quarter of 1999. Energy related expenses decreased $1.1 million in the year-to-date period. Decreases at the Cogenex Division, the Cogenex Partnerships and EUA Day aggregated approximately $4.5 million. In addition, expenses at Transcapacity decreased $300,000 due to its decreased operating activity and the sale of the Transcapacity L.P. in August 1999. These decreases were largely due to decreased operating activity, partially offset by increased salaries, bad debt and benefits expenses. Offsetting these decreases were increased expenses at EUA Citizens, Cogenex Canada and Cogenex West aggregating approximately $3.9 million due to increased operating activity in the year-to-date period. Depreciation and Amortization Expense Depreciation and Amortization expense decreased approximately $2.6 million or 20.3% in the third quarter and $5.2 million or 13.3% in the nine-month period ended September 30, 1999 when compared to the same periods of last year. These decreases were due largely to decreased depreciable property, particularly after the sale of Montaup's 50% ownership of the Canal Unit 2 generating station in December of 1998 and the sale of the Somerset Generating Station in April of 1999, and further impacted by decreased depreciation at EUA Cogenex. Taxes - Other Than Income Taxes - Other Than Income decreased approximately $800,000 or 13.7% in the third quarter of 1999 and approximately $1.4 million or 7.9% in the year-to-date period of 1999 as compared to the same periods of 1998 as a result of decreased property taxes after the sale of Montaup's Somerset Generating Station in April of 1999 and Montaup's 50% ownership of the Canal Unit 2 Generating Station in December of 1998. Income Taxes EUA's effective income tax rate for the nine months ended September 30, 1999 was approximately 45.8% compared to 40.3% for the same period of 1998. This increase reflects the impact of accelerated reversal of timing differences pursuant to restructuring settlement agreements. Other Income - Net Other Income and (Deductions) - Net excluding energy related asset adjustments, decreased by $800,000 in this year's third quarter and approximately $400,000 in the year-to-date period as compared to same periods of 1998. These decreases were due to decreased interest income at EUA Cogenex in both the third quarter and year-to-date periods. In addition, the year-to-date change was the result of general business liability adjustments recorded by EUA's parent company in the first quarter of 1998. These changes were partially offset by the impacts of decreased expenses at Eastern Edison related to the Massachusetts referendum to repeal deregulation legislation in 1998. Net Interest Charges Net Interest charges decreased by approximately $1.3 million or 14.5% in the third quarter of 1999 and $3.4 million or 12.1% in the year-to-date period as compared to the respective periods of 1998. Interest on long term debt principally decreased as a result of Eastern Edison's redemption of all of its First Mortgage Bonds in July 1999, its $35 million 7.78% Secured Medium Term Notes in August 1999, and the maturities of its $20 million First Mortgage Bonds in May of 1998 and $40 million First Mortgage Bonds in July of 1998. 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 obtained 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 allowing for borrowings in aggregate of up to $145 million from all sources of short-term credit. As of September 30, 1999, various financial institutions have committed up to $75 million under the revolving credit facility. In addition to the $75 million available under the revolving credit facilities, EUA System companies maintain short-term lines of credit with various banks totaling $90 million for an aggregate amount available of $165 million. Eastern Edison and Montaup are negotiating a new $60 million unsecured revolving credit facility. Outstanding short-term debt at September 30, 1999 and December 31, 1998 by Business Unit was as follows (000's): September 30, 1999 December 31, 1998 Core Electric Business $20,860 $2,220 Energy Related Business 9,758 19,354 Corporate 86,850 42,000 Consolidated $117,468 $63,574 In April 1999, Montaup completed the sale of its Somerset Station to NRG Energy Inc. for approximately $55 million. In July 1999, Montaup used the proceeds from this sale to redeem $54.8 million of its outstanding securities wholly-owned by Eastern Edison. Eastern Edison used these proceeds along with a capital contribution from EUA to redeem $40 million of 8%, $40 million of 6 7/8%, and $8 million of 6.35% First Mortgage and Collateral Trust Bonds. In July 1999, EUA filed an application under the Public Utility Holding Company Act with the Securities and Exchange Commission (SEC) requesting authorization for Eastern Edison to transfer all of Eastern Edison's investment in Montaup's securities, including Montaup's preferred stock, common stock and debenture bonds, to EUA. Montaup would then become a wholly-owned subsidiary of EUA. Also related to this transfer, Eastern Edison filed a Petition for Approval of the transfer or Request for Alternative Findings of No Jurisdiction with the MDTE. A public hearing was held at the MDTE on October 18, 1999 at which no one from the public intervened. Eastern Edison is awaiting a decision from the MDTE on its petition, and expects SEC approval shortly thereafter. For the nine months ended September 30, 1999 internally generated funds available after the payment of dividends amounted to approximately $100.0 million while the EUA System's cash construction requirements amounted to approximately $39.1 million 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 Legislation enacted in Rhode Island in 1996 and Massachusetts in 1997 along with approved electric utility industry restructuring settlement agreements in both states and at the federal level, granted EUA's Rhode Island and Massachusetts electric customers with choice of electricity supplier and rate reductions commencing January 1, 1998 and March 1, 1998, respectively. Until a customer chooses an alternative supplier, that customer will receive standard offer service from the retail distribution company. Blackstone and Newport are required to arrange for standard offer service through December 31, 2009 and Eastern Edison must arrange for this service through February 28, 2005. Under the approved settlement agreements, Montaup had guaranteed standard offer supply at a fixed price schedule for the duration of the standard offer periods and Blackstone, Newport and Eastern Edison agreed to subject their standard offer requirements to a competitive bidding process in which competitive suppliers would bid against the guaranteed price. Through its successful divestiture process, combined with a competitive bidding process conducted in late 1998, Montaup has assigned 100% of its standard offer obligation. A majority of this standard offer assignment became effective January 1, 1999; the remainder became effective on September 1, 1999 with the closing of the transfer of power purchase agreements to Constellation Power Source Inc. (Constellation), see Generation Divestiture below. The guaranteed standard offer price will increase over time to encourage customers to leave standard offer service and enter the competitive power supply market. Provisions of the approved settlement agreements also allowed Montaup to replace its all-requirements wholesale contracts with its affiliated retail distribution companies with a contract termination charge (CTC) which permits Montaup to recover, among other things, its above market investments and commitments in generation assets along with an 80% ratepayer/20% shareholder sharing mechanism for ongoing nuclear generation operations. Montaup began billing the CTC coincident with retail access and the distribution companies are recovering the CTC through a non-bypassable transition charge to all of their distribution customers. As part of the approved settlement agreements, Montaup agreed to divest its entire generation portfolio. The net proceeds of the sale, as defined in the settlement agreements, will be used to mitigate Montaup's CTC to its retail affiliates via a Residual Value Credit (RVC). The RVC reduces the fixed component of the CTC by an amount equal to the net proceeds, with a return, over the period commencing on the date the RVC is implemented through December 31, 2009. Effective April 1, 1999, subject to dispute resolution procedures pursuant to restructuring settlement agreements, Montaup reduced its CTC to its retail subsidiaries to reflect the RVC and other adjustments. Montaup lowered its CTC from 3.04 cents per kWh to 2.10 cents per kWh for Eastern Edison and from 3.0 cents per kWh to 2.04 cents per kWh and 2.06 cents per kWh in the case of Blackstone and Newport, respectively. Retail transition charge decreases to reflect these changes were authorized by respective state regulatory bodies effective April 1, 1999 for Eastern Edison and May 1, 1999 for Blackstone and Newport. Effective January 1, 1999 the standard offer service rate for Blackstone and Newport customers was increased from an average 3.2 cents per kilowatthour to an average 3.5 cents per kilowatthour. Coincident with the May 1, 1999 reduction in Blackstone's and Newport's retail transition charge, the standard offer rate was changed to a flat rate of 3.5 cents per kilowatthour for all customer classes. The standard offer service rate for Eastern Edison customers was increased to a flat rate of 3.1 cents per kilowatthour effective January 1, 1999. This rate was further increased to 3.5 cents per kilowatthour coincident with the Eastern Edison retail transition charge decrease effective April 1, 1999. Generation Divestiture By the end of 1998, pursuant to settlement agreements approved by federal and state regulators, Montaup signed agreements to sell all of its non-nuclear power generation assets and power purchase agreements to various non-affiliated parties in connection with electric utility restructuring undertaken in Massachusetts and Rhode Island. At the end of 1998, Montaup sold several diesel-powered generating units (totaling approximately 16 mw) owned by Newport to Illinois-based Wabash Power Equipment Company for approximately $1.4 million and its 50% share (approximately 280 mw) of Unit 2 of the Canal generating station in Sandwich, Massachusetts to Southern Energy Canal, LLC an indirect subsidiary of The Southern Company, for approximately $75 million. On April 7, 1998, Montaup entered into an agreement to transfer power purchase contracts for approximately 170 mw of output from Ocean State Power I and Ocean State Power II to TransCanada Power Marketing Ltd., an indirect subsidiary of TransCanada Pipelines Limited; the transfer was effective June 1, 1999. On December 21, 1998, Montaup entered into an agreement to transfer purchase power contracts totaling approximately 177 mw to Constellation Power Source, Inc., a wholly-owned affiliate of the Baltimore Gas and Electric Company; the transfer became effective on September 1, 1999. On April 26, 1999, Montaup completed the sale of its 170 mw Somerset Generating Station, located in Somerset, Massachusetts, to Somerset Power, LLC, a direct subsidiary of NRG, Inc., for approximately $55 million. In June of 1999, Montaup completed the sale of its and Newport's combined 2.6% (approximately 16 mw) share of the W.F. Wyman Unit 4 in Yarmouth, Maine to FPL Energy Wyman IV LLC, an indirect subsidiary of the Florida-based FPL Group, Inc for $2.4 million. Also in June of 1999, Blackstone sold its hydroelectric facility in Pawtucket, Rhode Island (approximately 1 mw) to Putnam Hydropower LLC, an affiliate of Pawtucket Hydropower Inc. In July 1999, in connection with Entergy Nuclear Generation Company's (Entergy) acquisition of Pilgrim Station from Boston Edison, Montaup agreed to buy out its power purchase agreement (approximately 73 mw) with Boston Edison. As a condition of the buy-out, Montaup entered into a reduced term power purchase contract for Pilgrim Station power with Entergy. Accordingly, Montaup recorded on EUA's Consolidated Balance Sheet as of September 30, 1999, a regulatory asset of approximately $113.4 million, a corresponding current regulatory liability of $105.6 million, and a long-term regulatory liability of $7.8 million. In October 1999, Vermont Yankee agreed to the sell the 540-mw nuclear unit to AmerGen Energy Company for approximately $23.5 million. Montaup has a 2.5% (12 mw) equity ownership interest in the unit. As part of the agreement, Vermont Yankee will make a one-time payment to the unit's decommissioning fund, and AmerGen will assume responsibility for all future operating costs and costs to decommission the plant at the end of its operating license in 2012. Vermont Yankee expects to complete this sale by mid-2000. Montaup also has agreed to sell its ownership interest in the Seabrook Station nuclear power plant to Little Bay Power Corporation, a subsidiary of BayCorp Holdings, Ltd. Montaup has received all federal and state approvals and expects to close on this sale later in 1999. EUA's only remaining generating capacity is approximately 58 mw from its ownership share of the Millstone 3 nuclear facility. EUA ultimately intends to sell and/or transfer its interest in Millstone 3. All of the sale and contract transfer agreements are subject to federal and/or state regulatory approvals, including that of the NRC with respect to the sale of nuclear units. The Year 2000 Issue On June 30, 1999, EUA reported to the North American Electric Reliability Council (NERC) that all of its mission critical systems were Year 2000 ready, consistent with the recommended industry schedule published by NERC. The EUA Year 2000 Program addressed the potential impact on computer systems and embedded systems and components resulting from a common software program code convention that utilized two digits instead of four to represent a year. If not addressed, the year 2000 could have been systemically recognized as the year 1900, causing system or equipment failures or malfunctions, and ultimately resulting in disruptions to Company operations. This disclosure constitutes a Year 2000 Statement and Readiness Disclosure. It is subject to the protections afforded it as such by the Year 2000 Information and Readiness Disclosure Act of 1998. EUA's State of Readiness: To address potential Year 2000 issues, EUA divided the focus of its Year 2000 Program into three major categories of business activity: the generation and delivery of electricity to customers, the acquisition of goods and services (including purchased power), and ongoing general and administrative activities related to the corporate infrastructure and support functions, which included among other things, billings and collections. Based on work completed as of December 31, 1998, the following types and quantities of date sensitive information technology (IT) systems were identified and remediated: >Central Applications: 54 date sensitive items consisting of centralized computing software that addressed major business and operational needs were identified; 67% required repair or replacement. >Server Based Networks: 22 date sensitive items consisting of networked applications, as well as supporting computing and communications equipment were identified; 55% required repair or replacement. >Desktops: 48 categories of items typically consisting of personal computer hardware and software were identified; 52% of such categories required repair or replacement. >Infrastructure: 44 items consisting of components of central IT operations (e.g., the mainframe computer, its operating system and centralized database) were identified; 57 % required repair or replacement. >Embedded Systems and Components: 3,977 items were identified; 96.3% were Y2K ready or inert. 3.7% were tested -- none failed. EUA utilized a four phase approach to address IT issues. The four phases were: Analysis, Remediation, Unit Testing and Integration Testing. The Analysis phase consisted of two stages. The first stage consisted of conducting an inventory of all products, applications and systems, department by department. The second stage consisted of an assessment of the risk (potential impact and likelihood of failure) of each item identified in the inventory. Items identified as not being Year 2000 ready were repaired or replaced during the Remediation phase. The Unit Testing phase involved testing at the module, program and application levels to assure that each such item functioned properly after repair or replacement. Finally, in the Integration Testing phase, dates were moved ahead, data were aged, and all date conditions pertinent to each application or product were tested "end-to-end" to assure that each item was tested in its final complete environment. As of June 30, 1999, each phase described above was 100% completed and all mission critical systems were Year 2000 ready. All mission critical non-information services systems (i.e., embedded systems and components) were also 100% Year 2000 ready as of that date as well. EUA developed a process to identify and assess the Year 2000 readiness of third parties with which it had a material relationship. First, a list of all vendors utilized over the prior two years was developed from the accounts payable system. Sub-lists were then developed and distributed to departments based on the departmental allocation of charges for goods and services. Departmental managements worked with the purchasing department to rank vendors identified as being critical or important. All vendors, regardless of rank, were contacted in writing requesting information regarding their Year 2000 status. Vendors ranked as critical or important were selected for additional inquiry, in the form of additional written inquiry and telephone inquiries. If available, vendor literature, regulatory filings and web sites were also reviewed. Critical vendors included providers of a variety of goods and services, such as telecommunications, banking and other financial services, computer products and services, equipment, fuel and mail delivery. As a result of this process, the purchasing department and/or the department(s) utilizing the goods or services in question have been able to confirm to their satisfaction that all mission critical vendors and a significant majority of the important vendors have provided adequate evidence of their Year 2000 readiness. All remaining vendors are being monitored as the process of gathering their Year 2000 readiness information continues. This process was essentially complete on June 30, 1999. Contingency plans have been developed for services provided by all mission critical vendors. These plans identify workarounds for any mission critical vendor for which there is not an alternative source. Costs to Address EUA's Year 2000 Issues: Through September 30, 1999, EUA has incurred costs of approximately $6.9 million to address Year 2000 issues, including approximately $4.3 million of non-incremental labor, $1.2 million of capital expenditures and $1.4 million of consulting and other costs. The company estimates it will incur additional costs approximating $1.1 million during the period October 1, 1999 through March 31, 2000, to complete its Year 2000 Program including approximately $700,000 of non-incremental labor and $400,000 of consulting and other costs. Risks of EUA's Year 2000 Issues: EUA's first priority continues to be the minimization of any potential disruptions to electric service as a result of the Year 2000. The provision of electric service depends in large part on the viability of the New England power grid which is managed by ISO/NEPOOL. EUA is actively participating on ISO/NEPOOL's Year 2000 operating and oversight committees. EUA's assessment of its own transmission and distribution equipment and facilities indicated that the risk of failure of this equipment does not appear to be significant. However, due to the interconnectivity of the New England power grid, and the reliance on many other entities also connected to the grid, it is not possible to conclude with certainty that there will be no significant interruptions in service. In addition, dependable voice and data telecommunications are critical to EUA's ongoing operations. EUA's internal telecommunication systems were Year 2000 ready as of June 30, 1999. EUA also relies heavily on external telecommunication systems, i.e., the local and regional telephone systems, and has identified these providers as critical vendors. EUA has gathered extensive documentation regarding the Year 2000 efforts and status of the regional telephone companies upon which it relies. In addition, EUA has also had face-to-face meetings with representatives of these companies and attended public conferences sponsored by these companies, at which they have described their Year 2000 process and progress. Each of these companies anticipates being Year 2000 ready and devoid of major system failures. Nevertheless, EUA has provided for several methods for maintaining adequate communications. For example, if the regional, land-line telephone systems were not in service, EUA could rely on mobile or cellular telephones. If those failed, EUA maintains mobile radios. Further, all of EUA's operating locations, including EUA Service Corporation's, are linked through a captive microwave telecommunications system. No other significant reasonably likely failure scenarios stemming solely from problems relating to Year 2000 have been identified thus far. Accordingly, EUA does not currently believe that any Year 2000 related risks in and of themselves constitute reasonably likely worst case scenarios. Rather, EUA's most reasonably likely Year 2000 related worst case scenario would be the occurrence of isolated year 2000 failures such as described above in conjunction with a severe winter storm. However, EUA believes that such year 2000 failures would not likely affect whether the storm event would have a material impact on EUA's business or financial condition. In this context, and based on its communications with key vendors and customers and its long experience with storm events, EUA does not currently anticipate significant adverse effects on its relationships with its customers or vendors, or any resulting material adverse effects on its business or operations. Year 2000 Contingency Plans: Contingency planning teams consisting of managers and employees experienced in system reliability, disaster recovery and risk were established and made responsible for developing contingency plans. The overall strategy was to identify Year 2000 risks, both internal and external to EUA, that could have a material impact on EUA's operations or financial well-being. For such risks, formal, written contingency plans were created. Preliminary plans were developed in March, 1999 and final contingency plans were in place and ready to implement as of June 30, 1999. In addition to the contingency plans described above which are designed to ensure a rapid recovery from any Year 2000 related failures, EUA has also developed a formal, written Implementation Plan. The purpose of this plan is to ensure that the activities necessary to maintain a clean systems environment from July 1, 1999 through the transition weekend and into the year 2000 are properly planned for, appropriately communicated throughout the company, and understood by those responsible for performing the various tasks. This plan includes provisions for additional staffing during the transition weekend to monitor mission critical systems and to resolve any Year 2000 issues which might arise. The Implementation Plan was in place as of June 30, 1999. Summary: The amount of effort and resources necessary to address Year 2000 issues and make EUA Year 2000 ready has been significant. There are currently dedicated teams in place, guided by a formal implementation plan, to ensure EUA remains Year 2000 ready through the remainder of 1999 and into the next century. EUA's Year 2000 program has consistently been on schedule and in accordance with timetables and progress points published by NERC. This effort culminated with the June 30, 1999 reporting to NERC that EUA had achieved 100% Year 2000 readiness for all mission critical systems and embedded components. EUA has utilized independent, outside technical consultants and other experts to review and assess its Year 2000 efforts and status throughout the project. Their findings have validated the progress and status of the company's Year 2000 project and the achievement of Year 2000 readiness. Management is confident that EUA's Year 2000 project has been, and continues to be, well managed with the appropriate resources and plans in place to ensure the Company remains Year 2000 ready and positioned for a successful transition to the Year 2000. Other EUA occasionally makes forward-looking projections of expected future performance or statements of our plans and objectives. These forward-looking statements may be contained in filings with the SEC, press releases and oral statements. This report on Form 10-Q contains information about the Company's future business prospects including, without limitation, statements about the potential impact of Year 2000 issues on the Company's financial condition or results. These statements are considered "forward-looking" within the meaning of the Private Securities Litigation Reform Act. These statements are based on the Company's current plans and expectations and involve risks and uncertainties that could cause actual future activities and results of operations to be materially different from those set forth in the forward-looking statements. The Company expressly undertakes no duty to update any forward-looking statement. PART II - OTHER INFORMATION Item 1. Legal Proceedings Other See "Note C - Commitments and Contingencies: Nuclear Ownership Issues" for a discussion of pending legal actions involving several of the nuclear plants in which Montaup has an ownership interest. Item 5. Other Information 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 was 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 were 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 NEPOOL's bulk power transmission facilities. The NEPOOL Tariff promotes competition in the New England power market through its single transmission 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. On April 20, 1998, FERC accepted the NEPOOL Tariff conditional on NEPOOL's compliance with a number of issues raised by FERC. On July 22, 1998, NEPOOL made its compliance filing at FERC. The NEPOOL Tariff changes and amendments to the Restated NEPOOL Agreement included in the filing effected compliance with the Commission's April 20, 1998 Order. While there were a large number of changes in the filing, the principal areas of change relate to the addition in the NEPOOL Tariff of a separately available Internal Point to Point Service, the addition of a mechanism to allocate costs to update the regional transmission system, and the replacement of a Non-Use Charge with an In-Service Charge across interconnections. A settlement agreement was filed on April 7, 1999. An order accepting the settlement was received on July 30, 1999 and a compliance filing was made on September 28, 1999. 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, automatic generation control, 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 meet 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. On October 29, 1997, FERC issued an order permitting implementation of the installed capability market, which occurred in April of 1998. On April 6, 1999, FERC issued an order approving market rules and on May 1, 1999, the remaining markets (operable capability, energy, automatic generation control and the reserve markets) were implemented. A Notice of Proposed Rulemaking by the FERC dated May 13, 1999 is proposing to amend its regulations under the Federal Power Act (FPA) to facilitate the formation of Regional Transmission Organizations (RTO's). FERC proposes to require that each public utility that owns, operates, or controls facilities for the transmission of electric energy in interstate commerce make certain filings with respect to forming and participating in an RTO. See "Note C - Commitments and Contingencies: Environmental Matters" for a discussion of newly identified sites where EUA could be joint and severally responsible for environmental cleanup costs. Item 6. Exhibits and Reports on Form 8-K (a)Exhibits - None. (b)Reports on Form 8-K - None filed in the quarter ended September 30, 1999. 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 15, 1999 /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-31-1999 SEP-30-1999 PER-BOOK 608021 113611 132487 573292 53618 1481029 102180 216348 39479 358007 28268 6900 127318 0 117468 0 62530 0 0 0 780538 1481029 414043 13757 358505 372262 41781 (6952) 34829 24370 10459 1729 8730 25443 17783 57931 .43 .43
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