-----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, PPGim/iAALek4kItmgPqiHrdDuMAlin00n8VVJP5TQH6vZFsUr3qdRa9P8fPLSDC 4vU9JHKIMQiaKExvhMvYwg== 0000031224-99-000030.txt : 19990517 0000031224-99-000030.hdr.sgml : 19990517 ACCESSION NUMBER: 0000031224-99-000030 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 2 CONFORMED PERIOD OF REPORT: 19990331 FILED AS OF DATE: 19990514 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: 99622857 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 1ST 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 March 31, 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 April 30, 1999 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)
March 31, December 31, ASSETS 1999 1998 Utility Plant and Other Investments: Utility Plant in Service $ 1,002,471 $ 1,000,243 Less: Accumulated Provision for Depreciation and Amortization 362,245 353,780 Net Utility Plant in Service 640,226 646,463 Construction Work in Progress 8,420 5,151 Net Utility Plant 648,646 651,614 Investments in Jointly Owned Companies 68,423 69,485 Non-Utility Plant - Net 54,201 55,274 Total Plant and Other Investments 771,270 776,373 Current Assets: Cash and Temporary Cash Investments 14,572 32,090 Accounts Receivable, Net 103,128 95,267 Notes Receivable 26,904 27,078 Fuel, Materials and Supplies 12,150 13,434 Other Current Assets 8,086 8,448 Total Current Assets 164,840 176,317 Deferred Debits and Other Non-Current Assets 430,939 349,948 Total Assets $ 1,367,049 $ 1,302,638 LIABILITIES AND CAPITALIZATION Capitalization: Common Shares, $5 Par Value $ 102,180 $ 102,180 Other Paid-In Capital 219,370 218,959 Common Share Expense (3,931) (3,931) Retained Earnings 53,486 56,466 Total Common Equity 371,105 373,674 Non-Redeemable Preferred Stock - Net 6,900 6,900 Redeemable Preferred Stock - Net 28,086 27,995 Long-Term Debt - Net 308,425 310,346 Total Capitalization 714,516 718,915 Current Liabilities: Long-Term Debt Due Within One Year 21,913 21,911 Notes Payable 45,011 63,574 Accounts Payable 33,303 29,018 Taxes Accrued 10,974 14,208 Interest Accrued 5,930 6,997 Other Current Liabilities 34,434 34,908 Total Current Liabilities 151,565 170,616 Deferred Credits and Other Non-Current Liabilities 360,109 271,078 Accumulated Deferred Taxes 140,859 142,029 Total Liabilities and Capitalization $ 1,367,049 $ 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 March 31, 1999 1998 Operating Revenues $ 138,877 $ 139,306 Operating Expenses: Fuel and Purchased Power 63,708 54,297 Other Operation and Maintenance 40,340 41,015 Depreciation and Amortization 12,741 12,858 Taxes - Other Than Income 6,459 6,060 Income Taxes - Current 4,203 2,118 - Deferred (Credit) (25) 4,467 Total 127,426 120,815 Operating Income 11,451 18,491 Other Income - Net 3,111 2,758 Income Before Interest Charges 14,562 21,249 Interest Charges: Interest on Long-Term Debt 6,475 7,682 Other Interest Expense 2,057 1,971 Allowance for Borrowed Funds Used During Construction (Credit) (139) (96) Net Interest Charges 8,393 9,557 Net Income 6,169 11,692 Preferred Dividends of Subsidiaries 576 576 Consolidated Net Earnings $ 5,593 $ 11,116 Weighted Average Number of Common Shares Outstanding 20,435,997 20,435,997 Consolidated Basic and Diluted Earnings Per Average Common Share $ 0.27 $ 0.54 Dividends Paid $ 0.415 $ 0.415 See accompanying notes to consolidated condensed financial statements.
EASTERN UTILITIES ASSOCIATES CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS (In Thousands)
Three Months Ended March 31, 1999 1998 CASH FLOW FROM OPERATING ACTIVITIES: Net Income $ 6,169 $ 11,692 Adjustments to Reconcile Net Income to Net Cash Provided from Operating Activities: Depreciation and Amortization 13,859 14,386 Deferred Taxes (117) 4,175 Non-cash Expenses on Sales of Investments in Energy Savings Projects 2,178 1,730 Investment Tax Credit, Net (390) (391) Allowance for Funds Used During Construction (47) (40) Collections and sales of project notes and leases receivable 2,655 4,145 Other - Net 5,961 (5,325) Change in Operating Assets and Liabilities (8,403) (3,943) Net Cash Provided From Operating Activities 21,865 26,429 CASH FLOW FROM INVESTING ACTIVITIES: Construction Expenditures (12,066) (16,130 Collections on Notes and Lease Receivables of EUA Cogenex 2,420 744 Increase in Other Investments (190) (3,157) Net Cash (Used in) Investment Activities (9,836) (18,543 CASH FLOW FROM FINANCING ACTIVITIES: Redemptions: Long-Term Debt (1,928) (2,525) EUA Common Share Dividends Paid (8,481) (8,481) Subsidiary Preferred Dividends Paid (576) (576) Net (Decrease) Increase in Short-Term Debt (18,562) 9,282 Net Cash (Used in) Financing Activities (29,547) (2,300) Net (Decrease) Increase in Cash and Temporary Cash Investments (17,518) 5,586 Cash and Temporary Cash Investments at Beginning of Period 32,090 7,252 Cash and Temporary Cash Investments at End of Period $ 14,572 $ 12,838 Supplemental disclosures of cash flow information: Cash paid during the period for: Interest (Net of Capitalized Interest) $ 8,415 $ 9,885 Income Taxes $ 10,064 $ 7,599 Supplemental schedule of non-cash investing activities: Conversion of Investments in Energy Savings Projects to Notes and Leases Receivable $ - $ 735 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 as amended on Form 10-K/A. 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 March 31, 1999 and the results of operations and cash flows for the three months ended March 31, 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 March 1998, The Accounting Standards Executive Committee of the American Institute of Certified Public Accountants (AICPA) issued Statement of Position 98-1, Accounting For the Costs of Computer Software Developed or Obtained for Internal Use (SOP 98-1), effective in 1999. SOP 98-1 provides specific guidance on whether to capitalize or expense costs within its scope. In April 1998, the AICPA issued SOP 98-5, "Reporting on the Costs of Start-Up Activities." EUA was required to adopt the SOP as of January 1, 1999. SOP 98-5 defines start-up activities as one-time activities an entity undertakes when it opens a new facility, introduces a new product line or service, conducts business in a new territory or with a new class of customer or beneficiary, initiates a new process in an existing facility or commences some new operation. The statement covers the accounting for organization costs and decrees that any such costs should be expensed as incurred in the same manner as the other start-up costs. The statement requires entities to expense previously capitalized costs in the year of adopting SOP 98-5. In June 1998, the Financial Accounting Standards Board issued SFAS 133, "Accounting for Derivative Instruments and Hedging Activities," which is effective in fiscal 2000. This statement 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 is currently evaluating the impact SFAS 133 will have 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. 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 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. The Special Projects Office was 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 plant's 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. On April 8, 1998, Northeast announced that Millstone 3 was ready for NRC inspection, indicating that virtually all of the restart-required physical work had been completed. On June 29, 1998, the NRC authorized Northeast to begin restart activities of Millstone 3. The authorization was given after the NRC staff verified that several final technical and programmatic issues were resolved. Millstone 3 was restarted during the first week of July, 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 arbitration until after the resolution of the arbitration case. These requests were denied in July 1998. 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. EUA cannot predict the ultimate outcome of legal proceedings brought against CL&P, WMECO and Northeast or the impact they may have on Montaup and the EUA system. 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 $30.3 million and is included with Other Liabilities on the Consolidated Balance Sheet as of March 31, 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. FERC also granted intervention requests and ordered a public hearing on the prudency of Maine Yankee's decision to shut down the plant and on the reasonableness of the proposed rate amendments. 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. Upon commission approval, this agreement will constitute full settlement of 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. Prior to shutdown, the municipals had been assigned 0.41% of Montaup's 4.0% entitlement share of Maine Yankee and Montaup had retained a 3.59% share. On November 28, 1997, the Secondary Purchasers sent a Notice of Initiation of Arbitration to the equity owners of Maine Yankee. On December 15, 1997, the equity owners as a group filed at FERC a Complaint and Petition for Investigation, Contract Modification, and Declaratory Order. On April 7, 1998, a Maine judge denied the Secondary Purchasers' motion to compel arbitration and indicated the jurisdictional question should be first decided by FERC. On April 15, 1998, the Secondary Purchasers notified FERC of the judge's decision and asked for expedited action on the pending complaint against them for non-payment. A separately negotiated Settlement Agreement filed with FERC on February 5, 1999, upon approval, would resolve issues raised by the Secondary Purchasers by limiting the amount they will pay for decommissioning and settling other points of contention. Management does not believe that these settlements, if approved, will 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. 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. Management cannot predict at this time the ultimate outcome of these actions. Note D -Financial Information by Business Segments: 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: Three Months Ended March 31, 1999 Operating Net (In Thousands) Revenues Income Core Electric $128,094 $6,770 Energy Related 10,783 (1,027) Corporate 0 (150) Total $138,877 $5,593 Three Months Ended March 31, 1998 Operating Net (In Thousands) Revenues Income Core Electric $126,590 $11,890 Energy Related 12,716 (428) Corporate 0 (346) Total $139,306 $11,116 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 EUA shareholders and various regulatory agencies, values the equity of EUA 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, expected by early 2000. Proxy statements which include details of the merger have been distributed along with voting instructions. Approval of the merger requires a two-thirds shareholder vote. EUA's Annual Meeting of Shareholders is scheduled for May 17, 1999. On April 30, EUA and NEES jointly filed with the Massachusetts Department of Telecommunications and Energy a rate plan reflecting consolidated rates following the merger for each company's Massachusetts subsidiaries. A similar filing for EUA's and NEES's Rhode Island companies before the Rhode Island Public Utilities Commission is expected in the near future. On April 30, the EUA and NEES merger plan received clearance under the federal Hart-Scott-Rodino Act. Under the Act, EUA and NEES had to file certain information with the Federal Trade Commission and the Department of Justice. Those agencies have reviewed the filings and have determined that the merger will not violate anti-trust laws. 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. Overview Consolidated net earnings for the first quarter of 1999 were $5.6 million compared to first quarter 1998 net earnings of $11.1 million. Net Earnings contributions by Business Unit for the first three months of 1999 and 1998 were as follows (in thousands): Three Months Ended March 31, 1999 1998 Core Electric Business $6,770 $11,890 Energy Related Business (1,027) (428) Corporate (150) (346) Consolidated $5,593 $11,116 The decrease in the net earnings contribution of the Core Electric Business reflects a full quarter's impact of Massachusetts restructuring settlement agreements, which became effective March 1, 1998 and provided, among other things, rate reductions to all of EUA's Massachusetts retail customers who represent roughly 60 percent of EUA's retail operations. Also, 1998 first quarter results included $1.7 million of billings to Maine utilities for storm restoration support and $1.7 million of increased unbilled revenue (subsequently offset in the second quarter) due to timing of restructured rates. These negative impacts on earnings were offset somewhat by a 2.6 percent increase in kilowatthour sales for the quarter. Net earnings of our Energy Related Business Unit decreased by approximately $600,000 in the first quarter of 1999 as compared to the same period of a year ago, primarily due to increased losses at EUA Cogenex. Resource requirements during EUA Cogenex sale negotiations in the latter part of 1998 hindered new business activities, the effects of which were felt in this year's first quarter. EUA Energy Investment incurred losses of $1.2 million in this year's first quarter, roughly the same as losses incurred for the same period in 1998. Of the $1.2 million loss, approximately $900,000 were incurred by EUA BIOTEN and TransCapacity L.P. in aggregate, which were slightly less than the losses incurred by those entities in the first quarter of 1998. EUA BIOTEN has not yet been successful in completing its exclusive negotiations with a third party investor, however, it is currently in active negotiations with other potential investors in non-exclusive discussions that would also allow the restructuring of BIOTEN Partnership into a corporation. These various discussions are expected to continue through June 30, 1999. If successful, EUA BIOTEN will transfer its investment in BIOTEN Partnership into a preferred equity investment in a new corporate entity. However, if EUA BIOTEN is unsuccessful in these negotiations, the Company will pursue other options, including the sale of its patented technology or exiting the business. Although management remains cautiously optimistic regarding its investment in EUA BIOTEN, it cannot predict the outcome of these negotiations. EUA BIOTEN's investment in the BIOTEN Partnership is approximately $14.2 million as of March 31, 1999. Net earnings of the Corporate Business Unit increased by approximately $200,000. This change is due primarily to non-recurring general business liability adjustments recorded by EUA in the first quarter of 1998. Kilowatthour Sales Kilowatthour (kWh) sales increased 2.6% in the first quarter of 1999 as company to the first quarter of 1998 largely the result of cooler weather in 1999. This change was led by a 6.6% increase in sales to residential customers. Operating Revenues Operating Revenues for the first three months of 1999 decreased by approximately $400,000 to approximately $138.9 million when compared to the same period of 1998. Operating Revenues by Business Unit for the first quarter of 1999 and 1998 were as follows (in thousands): Three Months Ended March 31, 1999 1998 Core Electric Business $128,094 $126,590 Energy Related Business 10,783 12,716 Corporate 0 0 Consolidated $138,877 $139,306 Core Electric Business revenues increased approximately $1.5 million in the first quarter of 1999 as compared to the same period of 1998. Generation- related revenues increased approximately $4.9 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. Offsetting this increase were the impacts of rate reductions to all of EUA's retail customers, pursuant to electric industry restructuring legislation and settlements effective January 1, 1998, March 1, 1998, in Rhode Island and Massachusetts, respectively. Distribution-related revenues decreased approximately $3.2 million due to the net impacts of restructured rates. This decrease was offset by the impacts of increased kWh sales for the period. Revenues of the Energy Related business unit decreased by approximately $1.9 million in the first quarter of 1999 compared to the same period of 1998. Paid from savings revenue of the EUA Cogenex division decreased $1.1 million in addition to decreased revenues of the EUA Cogenex Partnerships, Citizens and Cogenex-Canada aggregating approximately $1.2 million. Offsetting these decreases were increased revenues of approximately $200,000 of Renova. Operating Expenses Fuel and Purchased Power expenses in aggregate increased approximately $9.4 million, or 17.3% in the first quarter of 1999 as compared to the same period of 1998. This increase is due to the assignment of entitlements from certain power contracts to third parties and associated repurchases of energy to satisfy standard offer requirements. Also impacting this increase was a 2.6% increase in kilowatthour sales in the first quarter of 1999. Other Operation and Maintenance (O&M) expenses for the first quarter of 1999 decreased approximately $700,000 or 1.7% from the same period in 1998 due to the following: direct expenses of the Core and Corporate Business units increased by approximately $2.8 million in this year's first quarter due primarily to employee incentive plan true-ups 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, offset by decreased conservation and load management expense and customer accounts expenses aggregating $400,000. Indirect expenses, items in which we have limited short-term control or items which are fully recovered in rates, decreased by approximately $2.2 million in the first quarter of 1999 as compared to the same period of 1998. This decrease is primarily the result of decreased jointly owned units expense of $2.1 million, $1.5 million of which is due to the sale of Canal Unit 2 in December of 1998. Expenses of the Energy Related Business unit decreased by approximately $300,000 for the period, largely due to decreased expenses at EUA Cogenex's Citizens Corporation, related to decrease operating activity. Income Taxes EUA's effective tax rate for the quarter ended March 31, 1999 was approximately 46.2% compared to 40.1% for the same period of a year ago. This increase reflects the impact of accelerated reversal of timing differences pursuant to restructuring settlement agreements combined with lower taxable income in the first quarter of 1999. Other Income and (Deductions) - Net Other Income and (Deductions) - Net increased by approximately $400,000 in this year's first quarter. This increase is due primarily to general business liability adjustments recorded by EUA, the parent company, in the first quarter of 1998. Net Interest Charges Net Interest charges decreased by approximately $1.2 million or 12.2% in the first quarter of 1999 as compared to the same period of 1998. Interest on long term debt decreased as a result of normal cash sinking fund payments and the maturities of Eastern Edison's $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 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 allowing for borrowings in aggregate of up to $145 million from all sources of short-term credit. As of December 31, 1998, 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 facility, EUA System companies maintain short-term lines of credit with various banks totaling $90 million, for an aggregate amount available of $165 million. Outstanding short-term debt at March 31, 1999 and December 31, 1998 by Business Unit was as follows (in thousands): March 31, 1999 December 31, 1998 Core Electric Business $ - $2,220 Energy Related Business 18,481 19,354 Corporate 26,530 42,000 Consolidated $45,011 $63,574 On December 30, 1998, Montaup completed the sale of its 50% ownership interest in the Canal 2 generating station, in Sandwich Massachusetts, to Southern Energy for approximately $75 million. Montaup used the proceeds from the sale to redeem $55 million of Montaup debenture bonds, wholly owned by Eastern Edison, and paid a special dividend to Eastern Edison. Eastern Edison used these proceeds to repay its outstanding short-term debt and make short-term investments of $25.6 million. In January 1999, Eastern Edison used those investments to retire 551,956 shares of its outstanding, $25 par value, common stock at a price of $41.67 per share. EUA used the proceeds from Eastern Edison's redemption of common stock to pay down a portion of its outstanding short-term debt. For the three months ended March 31, 1999, internally generated funds amounted to approximately $28.4 million while the EUA System's cash construction requirements amounted to approximately $12.1 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. EUA Cogenex was not in compliance with the interest coverage covenant contained in certain of its unsecured note agreements at March 31, 1999. EUA Cogenex has reached agreements with lenders to modify the interest coverage covenant contained in these note agreements and to waive the default. EUA Cogenex expects to be in compliance with provisions of the original interest coverage covenant at June 30, 1999. 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 to purchasers of its generating assets. A majority of this standard offer assignment became effective January 1, 1999 with the remainder to be effective 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 increased to 3.5 cents per kilowatthour coincident with the Eastern Edison retail transition charge decrease effective April 1, 1999. Generation Divestiture On April 26, 1999, Montaup completed the sale of its 170 mw Somerset Generating Station, located in Somerset, Massachusetts, to NRG Energy Inc. (NRG), a subsidiary of Northern States Power Company, for approximately $55 million. Closing of the transaction, originally announced in October 1998, culminates 75 years of power plant operation by Montaup. The sale of Montaup's 50% share (280 mw) of Unit 2 of the Canal generating station in Sandwich, Massachusetts to Southern Energy for $75 million, which was announced in May 1998, was completed on December 30, 1998, and the sale of two diesel-powered generating units (totaling approximately 16 mw) owned by Newport to Illinois-based Wabash Power Equipment Co. for $1.5 million closed on October 1, 1998. Montaup's agreements to transfer purchase power contracts totalling approximately 177 mw to Constellation, to sell its 2.6% (16 mw) share of the W. F. Wyman Unit 4 in Yarmouth Maine to the Florida-based FPL group for approximately $2.4 million and for the transfer of its power purchase contracts with Ocean State Power (170 mw) to TransCanada are anticipated to occur in the second quarter of 1999. The sale of Montaup's 2.9% share (34 mw) of the Seabrook Station nuclear power plant to the Great Bay Power Corporation and the renegotiation of its 11% (73 mw) power entitlement from the Pilgrim Nuclear Power Station in Plymouth, Massachusetts are expected to take place later in 1999. All of the sale and contract transfer agreements are subject to federal and/or state regulatory approvals, including that of the Nuclear Regulatory Commission with respect to the Seabrook sale. Montaup's remaining generating capacity includes approximately 46 mw from its 4.0% joint ownership share of Millstone 3 nuclear unit and 12 mw from its 2.25% equity ownership of the Vermont Yankee nuclear facility. The Year 2000 Issue EUA's Year 2000 Program (Program) continues to proceed on schedule toward its goal of achieving Year 2000 readiness on or before June 30, 1999. The Program is addressing the potential impact on computer systems and embedded systems and components resulting from a common software program code convention that utilizes two digits instead of four to represent a year. If not addressed, the year 2000 may be systemically recognized as the year 1900, which could cause system or equipment failures or malfunctions, and ultimately result 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 has 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 relating to the corporate infrastructure and support functions, which include among other things, billings and collections. Based on work completed as of December 31, 1998, the following date sensitive IT systems and remediation needs were identified: > Central Applications: 54 date sensitive items consisting of centralized computing software that addresses 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% are Year 2000 ready or inert. 3.7% must be tested - any that fail will be replaced. EUA utilizes a four phase approach in addressing information technology (IT) issues. The four phases are: 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 are repaired or replaced during the Remediation phase. The Unit Testing phase involves testing at the module, program and application level to assure that each such item still functions properly after repair or replacement. Finally, in the Integration Testing phase, dates are moved ahead, data are aged, and all date conditions pertinent to each application or product are tested "end-to- end" to assure that each item is tested in its final complete environment. For mission critical systems, as of March 31, 1999, the phases described above were at the following percentages of completion: Analysis - 100%; Remediation - 100%; Unit Testing - 100%. The most recent information regarding Integration Testing is as of April 26, 1999. At that date, Integration Testing was 85% complete. EUA is on schedule to achieve Year 2000 readiness for 100% of mission critical projects by June 30, 1999. For non-I/T projects, as of the end of April 1999, approximately 99% are either Year 2000 ready or not affected by the Year 2000. The remaining items are in the process of being remediated and tested and are scheduled to be Year 2000 ready by June 30, 1999. EUA has an ongoing process to identify and assess the Year 2000 readiness of third parties with which it has 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 a significant majority of the 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. Where necessary, contingency plans will be developed. This process is on schedule to be completed by June 30, 1999. All critical vendors except one are Year 2000 ready or on schedule to be ready by December 31, 1999. The single exception is the municipality which provides infrastructure services to EUA Service Corporation. Contingency plans are in the process of being developed for services provided by this municipality, as well as for all other critical vendors. Such plans will identify workarounds for any critical vendor for which there is not an alternative source. Costs to Address EUA's Year 2000 Issues: Through March 31, 1999, EUA has incurred costs of approximately $4.7 million to address Year 2000 issues, including approximately $2.6 million of non-incremental labor, $1.2 million of capital expenditures and $900,000 of consulting and other costs. Due to their nature, the capital expenditures and the consulting and other costs are not allocable to the various phases of EUA's Year 2000 Program identified above; however, the $2.6 million in non- incremental labor costs can be assigned to particular phases of the Company's Year 2000 project, in the following amounts: Analysis - $600,000; Remediation - $550,000; Unit Testing - $550,000; and Integration Testing - $900,000. EUA estimates it will incur additional costs approximating $5.3 million during the period January 1, 1999 through March 31, 2000, to complete its resolution of Year 2000 issues including approximately $3.8 million of non-incremental labor, $500,000 of capital expenditures and $1.0 million of consulting and other costs. Again, due to the nature of the capital, consulting and other costs, they are generally not allocable to particular phases of EUA's Year 2000 Program; however, certain non-incremental labor costs may be assigned as follows: Integration Testing - $2.6 million. In addition, EUA estimates it will incur approximately $1.2 million in non-incremental labor costs during the period July 1, 1999 through March 31, 2000 for Year 2000 related activities such as: retesting, documentation review, communications outreach and customer and vendor awareness programs, training, maintaining a "clean room" environment, transition weekend preparations, transition weekend activities, and post-transition weekend problem resolution. Because 70% of the total estimated costs associated with the Year 2000 issue relate to non-incremental internal labor, management continues to believe that the Year 2000 will not present a material incremental impact to future operating results or financial condition. 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 to 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 are either Year 2000 ready now, or on schedule to become Year 2000 ready, by 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 have been established and are responsible for developing contingency plans. The overall strategy will be 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. Preliminary plans were developed by March 31, 1999. Final plans are scheduled to be in place and ready to implement, if necessary, by June 30, 1999. Summary: The amount of effort and resources necessary to address Year 2000 issues and make EUA Year 2000 ready is significant. There are dedicated teams in place to ensure EUA's transition into the next century occurs with minimal disruption. By the end of December 1998, EUA had the equivalent of twenty full time employees working on its Year 2000 project. Beginning in 1999, during peak times, up to 7 contract programmers have been added to help EUA's permanent IT staff deal with internal Year 2000 activities. Also, more than 12 vendor-provided IT professionals have been used to help with various short duration Year 2000 projects specifically targeting that vendor's products. EUA's Year 2000 program is on schedule and in accordance with timetables and progress points published by the North American Electric Reliability Council. In addition, EUA is utilizing outside technical consultants and other experts to help ensure that its Year 2000 program remains on schedule and effective and that risk and resource issues are appropriately assessed and addressed. Management believes EUA's Year 2000 project is well managed and has the appropriate resources and plans in place to ensure the Company is 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 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 See "Note C - Commitments and Contingencies: Recent Nuclear Regulatory Commission (NRC) Actions" 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. 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. 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 February 5, 1999, the Registrant filed a current report on Form 8-K with respect to Item 5 (Other Events). Reports on Form 8-K - On January 5, 1999, the Registrant filed a current report on Form 8-K with 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: May 14, 1999 /s/Clifford J. Hebert, Jr. Clifford J. Hebert, Jr. (on behalf of the Registrant and as Principal Financial Officer) EX-27 2 FDS
OPUR1 1000 3-MOS DEC-31-1999 MAR-31-1999 PER-BOOK 648646 122624 164840 368914 62025 1367049 102180 215439 53486 371105 28086 6900 308425 0 45011 0 21913 0 0 0 585609 1367049 138877 4178 123248 127426 11451 3111 14562 8393 6169 576 5593 8481 6475 21865 .27 .27
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