-----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, J2qYfdh/0I2jWjeFgFPAsS7A4YJYdhGaqNzSWiwBAqcVeWNRdHYbHHna/e3gv8jI JEccEXt4K5BApWirmg6psA== 0000031224-99-000025.txt : 19990420 0000031224-99-000025.hdr.sgml : 19990420 ACCESSION NUMBER: 0000031224-99-000025 CONFORMED SUBMISSION TYPE: 10-K405/A PUBLIC DOCUMENT COUNT: 1 CONFORMED PERIOD OF REPORT: 19981231 FILED AS OF DATE: 19990419 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-K405/A SEC ACT: SEC FILE NUMBER: 001-05366 FILM NUMBER: 99596346 BUSINESS ADDRESS: STREET 1: ONE LIBERTY SQ STREET 2: P O BOX 2333 CITY: BOSTON STATE: MA ZIP: 02109 BUSINESS PHONE: 6173579590 FILER: COMPANY DATA: COMPANY CONFORMED NAME: BLACKSTONE VALLEY ELECTRIC CO CENTRAL INDEX KEY: 0000012473 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 050108587 STATE OF INCORPORATION: RI FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K405/A SEC ACT: SEC FILE NUMBER: 000-02602 FILM NUMBER: 99596347 BUSINESS ADDRESS: STREET 1: WASHINGTON HWY STREET 2: P O BOX 111 CITY: LINCOLN STATE: RI ZIP: 02865 BUSINESS PHONE: 617-352-95 MAIL ADDRESS: STREET 1: P O BOX 111 STREET 2: WASHINGTON HIGHWAY CITY: LINCOLN STATE: RI ZIP: 02865 FORMER COMPANY: FORMER CONFORMED NAME: BLACKSTONE VALLEY GAS & ELECTRIC CO DATE OF NAME CHANGE: 19600201 FILER: COMPANY DATA: COMPANY CONFORMED NAME: EASTERN EDISON CO CENTRAL INDEX KEY: 0000014407 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 041123095 STATE OF INCORPORATION: MA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K405/A SEC ACT: SEC FILE NUMBER: 000-08480 FILM NUMBER: 99596348 BUSINESS ADDRESS: STREET 1: 750 W CENTER STREET CITY: WEST BRIDGEWATER STATE: MA ZIP: 02109 BUSINESS PHONE: 5085801213 MAIL ADDRESS: STREET 1: 750 W CENTER STREET CITY: WEST BRIDGEWATER STATE: MA ZIP: 02109 FORMER COMPANY: FORMER CONFORMED NAME: BROCKTON EDISON CO DATE OF NAME CHANGE: 19790729 10-K405/A 1 AMENDMENT #2 OF EUA, BVE AND EECO 1998 10-K SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 Form 10-K/A Amendment No. 2 (Mark One) [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 1998 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 Commission Registrants, State of Incorporation I.R.S. Employer File Number Address; and Telephone Number Identification No. 1-5366 EASTERN UTILITIES ASSOCIATES 04-1271872 (A Massachusetts voluntary association) One Liberty Square Boston, Massachusetts 02109 Telephone (617) 357-9590 0-2602 Blackstone Valley Electric Company 05-0108587 (A Rhode Island Corporation) 750 W. Center Street West Bridgewater, Massachusetts 02379 Telephone (508) 559-1000 0-8480 Eastern Edison Company 04-1123095 (A Massachusetts Corporation) 750 W. Center Street West Bridgewater, Massachusetts 02379 Telephone (508) 559-1000 Securities registered pursuant to Section 12(b) of the Act: Name of each Exchange Registrant Title of Each Class on which registered Eastern Utilities Common Shares, New York Stock Exchange Associates par value $5 per share Pacific Stock Exchange Securities registered pursuant to Section 12(g) of the Act: Registrant Title of Each Class Blackstone Valley 4.25% Non-Redeemable Preferred Stock, Electric Company $100 Par Value 5.60% Non-Redeemable Preferred Stock, $100 Par Value Eastern Edison 6.625% Redeemable Preferred Stock, Company $100 Par Value Indicate by check mark whether the registrants (1) have 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 registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes [X] No [ ] Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained to the best of registrants' knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X] State the aggregate market value of the voting stock held by non-affiliates of the registrants. As of March 15, 1999: Eastern Utilities Associates Common Shares, $5 par value - $579,871,415 Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date: Eastern Utilities Associates Common Shares Outstanding at March 15, 1999: 20,435,997 Blackstone Valley Electric Company Common Shares Outstanding at March 15, 1999: 184,062 Eastern Edison Company Common Shares Outstanding at March 15, 1999: 2,339,401 Portions of the Annual Reports to Shareholders of Eastern Utilities Associates, Blackstone Valley Electric Company, and Eastern Edison Company for the year ended December 31, 1998, are incorporated by reference into Part II. Portions of the Eastern Utilities Associates Proxy Statement, to be filed on or about April 14, 1999 are incorporated by reference into Part III. EXPLANATORY NOTE Eastern Utilities Associates hereby amends its Annual Report on Form 10-K for the year ended December 31, 1998 to reflect changes to Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations, and Part II, Item 8. Financial Statements and Supplementary Data. Except for the Items identified below, the content of the Registrants' original 1998 Form 10-K filed on March 31, 1999, is otherwise unchanged. SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrants have duly caused this amendment to be signed on its behalf by the undersigned, thereunto duly authorized. EASTERN UTILITIES ASSOCIATES By: /s/ John R. Stevens President and Chief Operating Officer (Principal Accounting Officer) BLACKTONE VALLEY ELECTRIC By: /s/ John R. Stevens Vice Chairman and Director (Principal Accounting Officer) EASTERN EDISON COMPANY By: /s/ John R. Stevens Vice Chairman and Director (Principal Accounting Officer) April 16, 1999 Part II - Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations This item is amended and restated in its entirety as follows: The information required by this Item with respect to Blackstone and Eastern Edison is incorporated herein by reference to pages 3 through 10 in the 1998 Blackstone Annual Report and pages 3 through 14 in the 1998 Eastern Edison Annual Report (Exhibits 13-1.01 and 13-1.08) for Blackstone and Eastern Edison, respectively, as previously filed with the Registrants' Form 10-K. The information required by this Item with respect to EUA previously incorporated herein by reference to pages 7 through 24 in the 1998 EUA Annual Report to Shareholders (Exhibit 13-1.03 of the Registrants' 1998 Form 10-K) is replaced in its entirety by the following: Eastern Utilities Associates Management's Discussion and Analysis of Financial Condition and Review of Operations Proposed Merger Agreement - 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 closing of the merger, expected by early 2000. 1998 Operations Overview - Consolidated net earnings for 1998 were $34.7 million, or $1.70 per share, on revenues of $538.8 million, an 8.6% decrease from 1997 earnings of $38.0 million on revenues of $568.5 million. 1998 results include the impacts of the 1998 EUA Cogenex Settlement and tax audit adjustments. 1997 results include the one-time earnings impact of a joint venture termination in 1997. These items are discussed below and listed in the following table. Net Earnings and Earnings Per Share by business unit for 1998 and 1997 were as follows:
1998 1997 Net Earnings (Loss) Earnings (Loss) Net Earnings Earnings (000's) Per Share (000's) Per Share Core Electric Business $35,160 $1.72 $36,025 $1.77 Energy Related Business (792) (0.04) 49 0.00 Corporate 541 0.03 406 0.02 From Operations 34,909 1.71 36,480 1.79 One-Time Impacts: Cogenex Settlement (2,062) (0.10) Tax Audit Adjustments 1,863 0.09 Joint Venture Termination 1,480 0.07 Consolidated $34,710 $1.70 $37,960 $1.86
Major impacts on earnings by business unit are described in the following paragraphs. Cogenex Settlement - EUA Cogenex recorded an after-tax charge of $2.1 million to earnings related to an arbitration panel's decision in a matter involving the 1995 sale of a portfolio of cogeneration units by EUA Cogenex to Ridgewood/Mass Power Partners, et al (Ridgewood). Ridgewood claimed that financial and other warranties in the purchase and sale agreement had been breached. EUA Cogenex entered counterclaims seeking recovery of costs of certain services performed for Ridgewood. The arbitration panel found for the buyer on some of the warranty claims, and awarded damages of approximately $2.6 million plus interest. EUA Cogenex was awarded approximately $400,000 plus interest on its counterclaim. EUA Cogenex paid the arbitration panel's net award less interest and recorded this charge to earnings during the fourth quarter of 1998. EUA Cogenex continues to contest the panel's findings with respect to the interest and legal fees. Tax Audit adjustments - In January 1997, the Internal Revenue Service (IRS) issued a report in connection with its examination of the consolidated federal income tax returns of EUA for 1992 and 1993. This report included an adjustment to disallow EUA's inclusion of its investment in EUA Power's Preferred Stock as a deduction in determining Excess Loss Account (ELA) taxable income in 1992 relating to EUA Power's Common and Preferred Stock that was redeemed in 1993. EUA filed an administrative appeal contesting the IRS position. In January 1999, EUA reached an understanding with the IRS Appeals Office concerning settlement of this matter. Reductions in EUA's tax reserves, to reflect this and other items, resulted in a net $1.9 million addition to fourth quarter 1998 earnings. Termination of power marketing joint venture - In the third quarter of 1997, EUA announced the termination of a power marketing joint venture with an affiliate of Duke Energy Corporation, the establishment of contingency reserves related to certain of its energy-related business activities and other expenses. Collectively, these actions resulted in a net after-tax gain of $1.5 million in third quarter 1997 earnings. Revenues - Total Operating Revenues by business unit for 1998, 1997 and 1996 were as follows:
($ in millions) 1998 1997 1996 Core Electric $480.1 $506.7 $470.7 Energy Related 58.7 61.8 56.4 Corporate - - - Total $538.8 $568.5 $527.1
Core Electric Business: Core Electric Revenues decreased by $26.6 million in 1998 due to the following: Generation related revenues decreased by $24.6 million as a result of rate reductions to all of EUA's retail customers, pursuant to electric industry restructuring legislation and settlement agreements effective January 1, 1998, and March 1, 1998, in Rhode Island and Massachusetts, respectively. Of this decrease, $21.5 million relates to decreased fuel and purchased power expenses in 1998. The remaining change in generation related revenues was due to the net impacts of rate reductions and accrued revenues as prescribed in the previously mentioned settlement agreements. Distribution revenues decreased by $4.2 million in 1998 due to the net impacts of restructured rates, a 1.7% increase in primary kilowatthour (kWh) sales and a $2.2 million increase in conservation and load management (C&LM) recoveries. Core Electric Revenues increased by $36 million in 1997 due to recoveries of increased fuel, purchased power and C&LM expenses aggregating $22.9 million and increased retail distribution revenues of $13.8 million resulting from increased kWh sales and rate increases effective January 1, 1997 for Blackstone and Newport. Energy Related Business: Energy Related Revenues decreased by $3.1 million in 1998 due primarily to decreased EUA Cogenex project sales of $8.1 million offset by increased paid-from-savings revenues and installation and fabrication revenues totalling $5.6 million. Energy Related Revenues increased by $5.5 million in 1997 as result of increased EUA Cogenex project sales of $9.1 million offset by decreased paid- from-savings and installation and fabrication revenues totaling $4.1 million. In addition, EUA TransCapacity revenue increased by $500,000 in 1997. Core Electric Business kWh Sales - Primary kWh sales of electricity by EUA's Core Electric Business unit increased approximately 1.7% in 1998 compared to 1997. This change was led by increases of 2.9% and 2.2% in the industrial and commercial classes, respectively. Total energy sales increased 9.5% in 1998, due mainly to increased sales to the New England Power Pool (NEPOOL) and increased short-term unit contract energy sales. These NEPOOL interchange and short-term unit contract sales essentially recover fuel costs and have little or no earnings impacts. Primary kWh sales of electricity increased 1.4% in 1997 compared to the prior year. This change was led by increases of 2.4% in the residential and industrial customer classes. Total energy sales including NEPOOL interchange and short-term unit contract sales increased 4.6% in 1997. Percentage changes in kWh Sales by class of customer for the past two years were as follows: Percent Increase (Decrease) from Prior Year
1998 1997 Residential 0.3 2.4 Commercial 2.2 (0.7) Industrial 2.9 2.4 Other 4.9 7.4 Total Primary Sales 1.7 1.4 Other Electric Utilities* (100.0) (9.0) Losses and Company Use 13.0 5.1 Total System Requirements 0.5 1.4 Unit Contracts* 71.5 33.7 Total Energy Sales 9.5 4.6
* Effective January 1998, Middleboro and Pascoag are no longer contract demand customers of Montaup. Energy sales to these customers are now included with unit contracts. Expenses - Fuel and Purchased Power: The EUA System's most significant expense items continue to be fuel and purchased power expenses of our Core Electric Business which together comprised about 44% of total operating expenses in 1998. Fuel expense of the Core Electric Business decreased by approximately $10.9 million or 9.9% in 1998. Increased nuclear generation and a 17.1% decrease in the cost of fossil fuels resulted in an 18.7% decrease in the average cost of fuel compared to 1997. Somewhat offsetting the decrease in the average price of fuel was a 9.5% increase in total energy generated and purchased in 1998 compared to 1997. Fuel expense increased by approximately $18.6 million or 20.1% in 1997, due primarily to a 4.6 % increase in total energy generated and purchased and outages of nuclear units in 1997 which contributed to a greater dependence on higher cost fossil fuels for energy requirements, resulting in an increase in average fuel costs of 16.3%. Purchased Power demand expense decreased approximately $10.5 million or 8.8% in 1998 compared to 1997. This decrease was primarily due to decreased billings from the Maine Yankee, Connecticut Yankee and Pilgrim Nuclear units aggregating approximately $8.5 million, and from Ocean State Power (OSP) of approximately $1.9 million. Purchased Power demand expense increased approximately $700,000 or less than 1% in 1997. Other Operation and Maintenance (O&M): O&M expenses for 1998 decreased by $16.8 million or 8.7% compared to 1997. Total O&M expenses are comprised of three components: Direct Controllable, Indirect and Energy Related. O&M expenses by component for 1998, 1997 and 1996 were as follows:
($ in millions) 1998 1997 1996 Direct Controllable $ 87.7 $ 89.1 $ 87.5 Indirect 40.5 51.1 36.7 Energy Related 47.9 52.7 55.7 Total O&M $176.1 $192.9 $179.9
Direct Controllable expenses of our Core Electric and Corporate Business units represent 49.8% of total 1998 O&M expenses and include expense items such as salaries, fringe benefits, insurance and maintenance. In 1998, direct expenses decreased approximately $1.4 million compared to 1997. This change is primarily the result of increased expenses in 1997 related to an April 1997 storm which struck Eastern Edison's service territory. Indirect expenses include items over which we have limited short-term control. Indirects include such expense items as O&M expenses related to Montaup Electric Company's (Montaup) joint ownership interests in generating facilities such as Seabrook I and Millstone 3 (see Note H of Notes to Consolidated Financial Statements for other jointly-owned units), power contracts where transmission rental fees are fixed and C&LM expenses that are fully recovered in revenues. Indirect expenses decreased by approximately $10.6 million in 1998. Jointly owned units expenses decreased approximately $9.4 million in 1998, due largely to the return to service of Millstone 3 in July of 1998 and decreased expenses of Canal Unit 2 and Seabrook I. In addition, charges from other utilities decreased approximately $1.9 million and Other Post-Retirement Benefits and Pension expenses decreased approximately $1.4 million collectively in 1998. These decreases were offset by increased C&LM expense of approximately $2.2 million. Indirect expenses increased by approximately $14.4 million in 1997. This change was primarily due to increased jointly owned unit expenses of approximately $9.0 million, of which approximately $5.0 million was related to the Millstone 3 outage and the remainder was due to increased expenses related to the scheduled maintenance outages at the Canal and Seabrook I units. Also impacting the 1997 change were increased C&LM expenses of approximately $3.3 million, approximately $1.2 million of transmission expenses related to new transmission tariffs implemented by FERC in 1997 to accommodate utility industry restructuring, and increased pension related expenses of approximately $700,000. The Energy Related component relates to O&M expenses of our Energy Related Business unit where changes are tied to changes in business activity. EUA Cogenex continues to be the most active of our Energy Related businesses and incurred 82% of the total O&M expenses of this business unit in 1998. Expenses of the Energy Related Business Unit decreased by approximately $5.2 million in 1998. Expenses of EUA Cogenex decreased approximately $10.3 million in 1998, due primarily to decreased expenses of Cogenex West, Cogenex Canada, Citizens and the Cogenex Partnerships of $9.9 million in aggregate, largely the result of decreased operating activity in 1998. In addition, EUA Cogenex expenses reflect the impact of the sale of RENOVA operations to EUA Energy Investment in May 1998 and ongoing cost control efforts at the Cogenex division which were offset by increased operating expenses at EUA Day in connection with its development of Day Matrix, a division which provides energy metering and control systems. EUA Energy Investment expenses increased by $4.9 million in 1998 due primarily to the impact of the RENOVA sale. Energy Related expenses decreased by approximately $3.0 million in 1997. This decrease was due primarily to decreased employee levels and other ongoing cost control efforts of the EUA Cogenex Division of approximately $2.2 million, decreased expenses of RENOVA of approximately $1.6 million, resulting from decreased operating activity, offset by increased expenses of Cogenex-West of approximately $300,000 as a result of increased marketing activity. Voluntary Retirement Incentives: In June 1997, an early retirement offer was accepted by a group of nine employees who were eligible for but not offered a Voluntary Retirement Incentive offer completed in 1995. The pre-tax cost of the 1997 offer, recorded in that year's second quarter, was approximately $1.4 million. Depreciation and Amortization: Depreciation and Amortization expense increased by approximately $4.1 million or 8.8% in 1998 as compared to 1997. This increase is due largely to increased depreciation at EUA Cogenex directly related to an increase in number of projects placed in service, and amortization of certain regulatory assets at the Core Electric Business pursuant to restructuring settlement agreements. Depreciation and Amortization expense increased by approximately $1.5 million in 1997, due primarily to higher depreciable plant balances at our Core Electric companies and a $500,000 increase in EUA Cogenex depreciation. Income Taxes: EUA files a consolidated federal income tax return for the EUA System. The composite federal and state effective income tax rate for 1998 was 34.5% versus 35.8% in 1997. The effects of accelerated reversal of timing differences pursuant to restructuring settlement agreements were offset in 1998 by the previously discussed tax audit adjustments and the reversal of unamortized investment tax credits related to Canal 2 at the time of its sale, which occurred on December 30, 1998. Other Income (Deductions) - Net: Other Income and (Deductions) - Net decreased by approximately $6.0 million, or 55.0% in 1998 as compared to 1997. This decrease is due largely to the absence of the impacts of the 1997 power marketing joint venture termination and the 1997 favorable resolution of a Massachusetts corporate income tax dispute. Also contributing to the 1998 decrease were non-operating expenses of $2.5 million related to Montaup's divestiture efforts and approximately $800,000 of expenses related to opposition of a 1998 Massachusetts referendum to repeal deregulation legislation. Other Income and (Deductions) - Net increased approximately $5.9 million in 1997. This was primarily due to the net positive impact of the power marketing joint venture termination in 1997, increased interest income related to the favorable resolution of a Massachusetts corporate income tax dispute in 1997, and the impact of changes to the EUA Cogenex pension and post- retirement welfare benefit plans offset by gains recorded in 1996 from the sale of Seabrook II equipment jointly owned by Montaup. The tax issue in question relates to a 1989 Massachusetts State income tax audit which assessed tax liability for certain intercompany transactions. In order to contest the tax assessment, EUA paid the disputed tax liability in 1989. Final resolution of this matter was reached in 1997 in favor of EUA. The disputed tax amount, along with related interest, was returned to EUA in 1997. The one-time benefit to 1997 earnings relates to the interest portion of the refund. Interest Charges: Net Interest charges decreased by approximately $2.0 million or 5.0% in 1998 compared to 1997. Interest on long term debt decreased as a result of normal cash sinking fund payments and the maturities of Eastern Edison's $20 million, 5 7/8% First Mortgage Bonds in May 1998 and $40 million, 5 3/4% First Mortgage Bonds in July 1998. This decrease was partially offset by interest expense on increased short term borrowings, which were used to finance Eastern Edison's long-term debt maturities. Net interest charges for 1997 were relatively unchanged from the 1996 level. Decreased long-term debt interest expense in 1997 resulting from normal cash sinking fund payments was offset by higher interest expense related to increased short-term debt and decreased capitalized interest by EUA Cogenex. FINANCIAL CONDITION AND LIQUIDITY - 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. Core Electric Business: For 1998, 1997 and 1996, Core Electric Business cash construction expenditures were $22.9 million, $21.9 million and $33.3 million, respectively. Internally generated funds available after the payment of dividends supplied approximately 250%, 133%, and 118% of these cash construction requirements in 1998, 1997 and 1996, respectively. 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. Cash construction expenditures of the Core Electric Business for 1999, 2000 and 2001 are estimated to be approximately $33.4 million, $32.5 million and $33.3 million, respectively, and are expected to be financed with internally generated funds. In addition to construction expenditures, projected requirements for scheduled cash sinking fund payments and mandatory redemption of securities of the Core Electric Business for 1999 through 2003 are $11.6 million, $2.3 million, $4.1 million, $38.4 million and $51.4 million, respectively, none of which relates to Blackstone's or Newport's variable rate bonds. Energy Related Business: Capital expenditures of our Energy Related Business amounted to $26.8 million, $51.9 million and $28.1 million, in 1998, 1997 and 1996, respectively. Internally generated funds supplied 143%, 88%, and 72% of cash capital requirements in 1998, 1997, and 1996, respectively. Estimated capital expenditures of the Energy Related Business are $52.7 million, $55.9 million, and $61.3 million in 1999, 2000 and 2001, respectively. Internally generated funds are expected to supply approximately 100% of 1999 estimated capital requirements. In addition to capital expenditures and energy related investments, projected requirements for scheduled cash sinking fund payments and mandatory redemption of securities of the Energy Related Business are $9.2 million in 1999, $59.2 million in 2000, $9.2 million in 2001, $6.0 million in 2002 and $6.0 million in 2003. Corporate: Construction activity of the Corporate Business unit is minimal. Projected requirements for scheduled cash sinking fund payments for the corporate operations for each of the five years following 1998 are $1.1 million. Short-Term Lines of Credit: 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 $165 million. Year-End Short-Term Debt outstanding by business unit: ($ in thousands) 1998 1997 Core Electric Business $ 2,220 $ 7,075 Energy Related Business 19,354 44,609 Corporate 42,000 9,800 Total $63,574 $61,484 During 1998, Eastern Edison used available funds and short-term borrowings to fund $60 million of long-term debt maturities. On December 30, 1998, Montaup received $75.9 million of proceeds from the sale of its 50% ownership share of the Canal 2 generating Station to Southern Energy. Those funds were used to redeem $55 million of debenture bonds and pay a special dividend to Montaup's parent company, Eastern Edison. Eastern Edison used these proceeds to repay its outstanding short-term debt and make short-term investments of $25.6 million. EUA expects to repay the outstanding balances of short-term indebtedness with internally generated funds. Dividend Payments: The preferred stock provisions of the Retail Subsidiaries place certain restrictions upon the payment of dividends on common stock of the respective Retail Subsidiary to EUA. These restrictions relate to cumulative retained earnings available for the payment of such common dividends. At December 31, 1998 and 1997 each of the Retail Subsidiaries was in excess of the minimum requirements which would make these restrictions effective. These restrictions have not, and are not expected to have, an impact on EUA's ability to meet its cash obligations. Interest Rate Risk: EUA is exposed to interest rate risk primarily related to Blackstone's and Newport's variable rate bonds. Refer to the Consolidated Statements of Indebtedness for a listing of EUA's long-term fixed and variable rate debt. Energy Related Businesses - Net Earnings and Earnings Per Share contributions of EUA's Energy Related Businesses for 1998 and 1997 were as follows: 1998 1997
Net Earnings Earnings Net Earnings Earnings (Loss) (Loss) (Loss) (Loss) (000's) Per Share (000's) Per Share EUA Cogenex $ 763 $ 0.04 $ 202 $ 0.01 EUA Ocean State 4,066 0.20 3,967 0.19 EUA Energy Investment (5,287) (0.26) (3,741) (0.18) EUA Energy Services (228) (0.01) (354) (0.02) EUA Telecommunications (106) (0.01) (25) (0.00) From Operations (792) (0.04) 49 0.00 Cogenex Settlement (2,062) (0.10) Total Energy Related Business $(2,854) $(0.14) $ 49 $ 0.00
EUA Cogenex: EUA Cogenex provides energy efficiency products and energy management services throughout North America. EUA Cogenex's net earnings increased approximately $600,000 in 1998 due largely to the transfer of RENOVA operations to EUA Energy Investment Corporation effective May 1, 1998 and to decreased interest expense. EUA Ocean State: EUA Ocean State owns 29.9% of each of the partnerships which developed and operate Units I and II of OSP, twin 250-megawatt (mw) gas-fired generating units in northern Rhode Island. Both units have provided a premium return since their respective in-service dates of December 31, 1990, and October 1, 1991. The slight increase in EUA Ocean State earnings contribution was due primarily to increased availability bonuses in 1998. EUA Energy Investment: EUA Energy Investment was organized to seek out investments in energy related businesses. The change in EUA Energy Investment earnings contribution was due to the sale of RENOVA operations to EUA Energy Investment in 1998. Also impacting this change were increased losses at EUA Transcapacity and EUA BIOTEN in 1998 compared to 1997. EUA BIOTEN is currently in negotiations with a third party investor for the restructuring of BIOTEN Partnership into a corporation. EUA BIOTEN intends to transfer its total partnership investment of $13.5 million at December 31, 1998, into a non-voting preferred equity ownership interest in a newly-formed corporation. Effective March 1, 1999, EUA BIOTEN will no longer have any funding obligations to the BIOTEN partnership or the restructured entity. EUA Energy Investment is continuing in its efforts to negotiate strategic alliances or sales of its other energy related investments, including EUA Transcapacity and RENOVA. EUA can not predict the outcome of these negotiations. EUA Energy Services: The change in earnings of EUA Energy Services is due to reduced operating costs since the power marketing joint venture with an affiliate of Duke Energy Corporation was terminated in 1997. EUA Telecommunications: The slight change in earnings of EUA Telecommunications is due to increased expenses since the company was established in mid-1997. 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. 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. 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 will reduce 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. Montaup has filed to implement the RVC effective April 1, 1999 and is awaiting approval. Generation Divestiture - Montaup now has agreements to sell all of its non- nuclear power generation assets and its 2.9% ownership share of the Seabrook Nuclear Station and has agreements to transfer all of its remaining purchased power contracts with the exception of its purchase power commitment with the Vermont Yankee Nuclear Station. On January 5, 1999, EUA announced that Montaup had agreed to transfer its remaining non-nuclear power purchase contracts, amounting to approximately 177 mw, to Constellation Power Source, Inc. In addition, Montaup has entered into agreements to sell: its 160-mw Somerset, Massachusetts electric generating station for approximately $55 million to NRG Energy, Inc.; 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; its 2.9% share (34 mw) of the Seabrook Station nuclear power plant to the Great Bay Power Corporation, a subsidiary of BayCorp Holdings, Ltd. for $3.2 million. Montaup has also signed agreements for the transfer of power purchase contracts for approximately 170 mw between Montaup and Ocean State Power and for the buyout of its 11% (73 mw) power entitlement from the Pilgrim Nuclear Power Station in Plymouth, Massachusetts. 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. Closing of the non- nuclear sale agreements are anticipated to take place in the first quarter of 1999. The Seabrook sale and Pilgrim buyout are expected to take place later in 1999. Also, 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 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. Environmental Matters - EUA's Core Electric Business subsidiaries and other companies owning generating units from which power is obtained are subject, like other electric utilities, to environmental and land use regulations at the federal, state and local levels. The federal Environmental Protection Agency (EPA), and certain state and local authorities, have jurisdiction over releases of pollutants, contaminants and hazardous substances into the environment and have broad authority to set rules and regulations in connection therewith, such as the Clean Air Act Amendments of 1990, which could require installation of pollution control devices and remedial actions. In 1994, EUA instituted an environmental audit program to ensure compliance with environmental laws and regulations and to identify and reduce liability with respect to those requirements. Because of the nature of the EUA System's business, various by-products and substances are produced or handled which are classified as hazardous under the rules and regulations promulgated by such authorities. The EUA System typically provides for the disposal of such substances through licensed contractors, but statutory provisions generally impose potential joint and several responsibility on the generators of the wastes for clean-up costs. Subsidiaries of EUA have been notified with respect to a number of sites where they may be responsible for such costs, including sites where they may have joint and several liability with other responsible parties. It is the policy of the EUA System companies to notify liability insurers and to initiate claims. However, EUA is unable to predict whether liability, if any, will be assumed by, or can be enforced against, insurance carriers in these matters. As of December 31, 1998, the EUA System had incurred costs of approximately $7.7 million in connection with these sites. These amounts have been financed primarily by internally generated cash. The EUA System is currently amortizing substantially all of its incurred costs over a five-year period consistent with prior regulatory recovery periods and is recovering certain of those costs in rates. EUA estimates that additional costs of up to $2.5 million may be incurred at these sites through 1999 by its subsidiaries. Estimates beyond 1999 cannot be made since site studies, which are the basis of these estimates, have not been completed. In addition to the previously discussed costs, Blackstone is currently litigating responsibility for clean-up costs and related interest aggregating $5.9 million. The clean-up costs were incurred by the Commonwealth of Massachusetts at a site in which Blackstone has been named as a responsible party. See Note J of "Notes to Consolidated Financial Statements" for further discussion. A number of scientific studies in the past several years have examined the possibility of health effects from electric and magnetic fields (EMF) that are found everywhere there is electricity. Research to date has not conclusively established a direct causal relationship between EMF exposure and human health. Additional studies, which are intended to provide a better understanding of the subject, are continuing. Management cannot predict the ultimate outcome of the EMF issue. Nuclear Power Issues - 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. Montaup's share of this estimate is approximately $8.0 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. Montaup has a 4.5% equity ownership in Connecticut Yankee, a nuclear generating facility in the process of decommissioning. Montaup's share of the total estimated costs for the permanent shutdown, decommissioning, and recovery of the investment in Connecticut Yankee is approximately $23.8 million and is included with Other Liabilities on the Consolidated Balance Sheet as of December 31, 1998. Also, due to anticipated recoverability, a regulatory asset has been recorded for the same amount and is included with Other Assets. On August 31, 1998, a FERC law judge rejected Connecticut Yankee's plan to decommission the plant. The judge claimed that estimates of clean-up costs were flawed and certain restoration costs were not supported. The judge also said Connecticut Yankee could not pass on spent fuel storage costs to rate- payers. The judge recommended that Connecticut Yankee withdraw its decommissioning plan and submit a new plan which addresses the issues cited by him. FERC will review the judge's recommendations and issue a decision on this case in the coming months. If FERC concurs with the judge's recommendation, this may result in a write down of certain Connecticut Yankee plant investments. Montaup cannot predict the ultimate outcome of FERC's review . On August 6, 1997, as the result of an economic evaluation, the Maine Yankee Board of Directors voted to permanently close that nuclear plant. Montaup has a 4.0% equity ownership in Maine Yankee. Montaup's share of the total estimated costs for the permanent shutdown, decommissioning, and recovery of the remaining investment in Maine Yankee is approximately $31.0 million and is included with Other Liabilities on the Consolidated Balance Sheet as of December 31, 1998. 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 August 1997 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% share 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. Recent actions by the NRC, some of which are cited above, indicate that the NRC has become more critical and active in its oversight of nuclear power plants. EUA is unable to predict at this time what, if any, ramifications these NRC actions will have on any of the other nuclear power plants in which Montaup has an ownership interest or power contract. Montaup is recovering through rates its share of estimated decommissioning costs for the Millstone 3 and Seabrook I nuclear generating units. Montaup's share of the currently allowed estimated total costs to decommission Millstone 3 is approximately $22.4 million in 1998 dollars and Seabrook I is approximately $14.4 million in 1998 dollars. These figures are based on studies performed for the lead owners of the units. Montaup also pays into decommissioning reserves, pursuant to contractual arrangements, at other nuclear generating facilities in which it has an equity ownership interest or life-of-unit entitlement. Such expenses are currently recovered through rates. 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. The Year 2000 Issue - EUA's Year 2000 Program (the Program) is proceeding on schedule. 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. 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 includes among other things, billings and collections. EUA has adopted 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 services, 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. As of January 31, 1999, each phase described above was at the following percentage of completion: Analysis-100%; Remediation-79%; Unit Testing-78%; Integration Testing-11%. EUA is on schedule to achieve Year 2000 readiness for 100% of mission critical projects by June 30, 1999. For non-IT projects, approximately 90% 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. 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 the 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 Y2K ready or inert. 3.7% must be tested -- any failing will be replaced. 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 as critical, important or convenient. Approximately 150 vendors were 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, telephone inquiries, review of vendor literature, review of regulatory agency filings and web site reviews. 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 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 December 31, 1998, EUA has incurred costs of approximately $3.0 million to address Year 2000 issues, including approximately $1.5 million of non-incremental labor, $1.2 million of capital expenditures and $300,000 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 $1.5 million 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--$400,000; Unit Testing--$400,000; and Integration Testing--$100,000. EUA estimates it will incur additional costs approximating $7.0 million during the period January 1, 1999 through March 31, 2000, to complete its resolution of Year 2000 issues, including approximately $5.5 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: Remediation--$150,000; Unit Testing-- $150,000; Integration Testing--$4 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 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 telecommunications 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 Year 2000 related problems 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 are expected by the end of the first quarter of 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 time tables and program 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. The foregoing constitutes a Year 2000 Statement and Readiness Disclosure subject to the protections afforded it as such by the federal Year 2000 Information and Readiness Disclosure Act of 1998. New Accounting Standards - 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. The Company does not expect SOP 98-1 to have a material impact on its financial position or results of operations. In April 1998, the AICPA issued SOP 98-5, "Reporting on the Costs of Start-Up Activities." EUA is required to adopt the SOP for 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. Although EUA can not currently quantify the impact of adoption as of January 1, 1999, Management estimates the application of SOP 98-5 will not have a material impact on the financial statements. In June 1998, the Financial Accounting Standards Board issued SFAS 133, "Accounting for Derivative Instruments and Hedging Activities," which is effective in 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. Other - A pending class action, filed on March 2, 1998, in the Massachusetts Supreme Judicial Court naming all Massachusetts electric distribution companies, including Eastern Edison, and certain Massachusetts state agencies as defendants, seeks to invalidate certain sections of the Electric Utility Restructuring Act of 1997. The Act directs the Massachusetts Department of Telecommunications and Energy to impose mandatory charges on all electricity sold to customers, except those served by a municipal lighting plant, to fund energy efficiency activities and to promote renewable energy projects. In addition to declaratory judgment, plaintiffs seek remittance of monies paid to each distribution company by customers along with any interest earned. The outcome of this class action is unknown at this time however, Eastern Edison is vigorously defending the lawsuit. 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 oper- ations 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. "Management's Discussion and Analysis of Financial Condition and Review of Operations" provides a summary of information regarding the Company's financial condition and results of operation and should be read in conjunction with the "Consolidated Financial Statements" and "Notes to Consolidated Financial Statements" to arrive at a more complete understanding of such matters. Part II - Item 8. Financial Statements and Supplementary Data This item is amended and restated in its entirety as follows: The information required by this Item with respect to Blackstone and Eastern Edison is incorporated herein by reference to page 2 and pages 12 through 31 in the 1998 Blackstone Annual Report and page 2 and pages 16 through 39 in the 1998 Eastern Edison Annual Report (Exhibits 13-1.01 and 13-1.08) for Blackstone and Eastern Edison, respectively, as previously filed with the Registrants' Form 10-K. The information required by this Item with respect to EUA previously incorporated herein by reference to pages 26 through 41 in the 1998 EUA Annual Report to Shareholders (Exhibit 13-1.03 of the Registrants' 1998 Form 10-K) is replaced in its entirety by the following: Consolidated Statements of Income ($ in thousands except Common Shares and per Share Amounts)
Years Ended December 31, 1998 1997 1996 OPERATING REVENUES $538,801 $568,513 $527,068 OPERATING EXPENSES: Fuel 99,781 110,724 92,166 Purchased Power-Demand 108,936 119,485 118,830 Other Operations 155,943 162,464 154,831 Voluntary Retirement Incentives 1,416 Maintenance 20,143 30,432 25,047 Depreciation and Amortization 51,079 46,941 45,478 Taxes - Other Than Income 23,323 24,021 23,933 Income Taxes 17,957 14,223 10,942 Total Operating Expenses 477,162 509,706 471,227 Operating Income 61,639 58,807 55,841 Equity in Earnings of Jointly Owned Companies 9,524 9,466 10,698 Allowance for Other Funds Used During Construction 173 162 452 Loss on Disposal of Cogeneration Operations (3,172) Income Tax Impact of Loss on Disposal of Cogeneration Operations 1,110 Other Income - Net 4,940 10,986 5,054 Income Before Interest Charges 74,214 79,421 72,045 INTEREST CHARGES: Interest on Long-Term Debt 28,288 32,198 34,035 Amortization of Debt Expense and Premium - Net 1,813 2,548 2,620 Other Interest Expense 7,745 5,245 4,199 Allowance for Borrowed Funds Used During Construction (Credit) (647) (835) (1,735) Net Interest Charges 37,199 39,156 39,119 Net Income 37,015 40,265 32,926 Preferred Dividends of Subsidiaries 2,305 2,305 2,312 Consolidated Net Earnings $34,710 $37,960 $30,614 Average Common Shares Outstanding 20,435,997 20,435,997 20,436,217 Consolidated Basic and Diluted Earnings per Share $1.70 $1.86 $1.50 Dividends Paid per Share $1.66 $1.66 $1.645 The accompanying notes are an integral part of the financial statements.
Consolidated Statements of Cash Flows
Years Ended December 31, ($ in thousands) 1998 1997 1996 CASH FLOW FROM OPERATING ACTIVITIES: Net Income $37,015 $40,265 $32,926 Adjustments to Reconcile Net Income to Net Cash Provided from Operating Activities: Depreciation and Amortization 56,308 51,615 50,690 Amortization of Nuclear Fuel 1,265 1,067 1,676 Deferred Taxes (17,854) (6,317) 11,610 Non-cash Expenses/(Gains) on Sales of Investments in Energy Savings Projects 10,002 15,993 8,262 Investment Tax Credit, Net (3,081) (1,201) (1,207) Allowance for Other Funds Used During Construction (173) (162) (452) Collections and Sales of Project Notes and Leases Receivable 17,261 19,148 7,776 Other - Net (1,514) (5,726) 6,373 Changes in Operating Assets and Liabilities: Accounts Receivable (2,621) (2,494) (5,777) Materials and Supplies (2,232) 2,929 2,385 Accounts Payable (6,018) 1,225 (1,958) Taxes Accrued 11,145 59 (1,539) Other - Net (2,563) (664) 4,930 Net Cash Provided from Operating Activities 96,940 115,737 115,695 CASH FLOW FROM INVESTING ACTIVITIES: Construction Expenditures (51,201) (76,118) (62,730) Proceeds from Divestiture of Generation Assets 76,873 Collections on Notes and Lease Receivables of EUA Cogenex 11,558 10,076 3,665 Other Investments (2,071) 312 (3,889) Net Cash Provided from (Used in) Investing Activities 35,159 (65,730) (62,954) CASH FLOW FROM FINANCING ACTIVITIES Redemptions: Long-Term Debt (73,122) (28,617) (20,617) Preferred Stock - (90) Premium on Reacquisition and Financing Expenses - (15) EUA Common Share Dividends Paid (33,924) (33,924) (33,618) Subsidiary Preferred Dividends Paid (2,305) (2,305) (2,314) Net Increase in Short-Term Debt 2,090 9,636 12,308 Net Cash (Used in) Financing Activities (107,261) (55,210) (44,346) NET INCREASE (DECREASE) IN CASH AND TEMPORARY CASH INVESTMENTS: 24,838 (5,203) 8,395 Cash and Temporary Cash Investments at Beginning of Year 7,252 12,455 4,060 Cash and Temporary Cash Investments at End of Year $32,090 $7,252 $12,455 Cash Paid during the year for: Interest (Net of Amounts Capitalized) $37,087 $40,172 $40,658 Income Taxes $25,976 $28,921 $11,530 Conversion of Investments in Energy Savings Projects to Notes and Leases Receivable $4,529 $5,404 $7,779 The accompanying notes are an integral part of the financial statements.
Consolidated Balance Sheets
Years Ended December 31, ($ in thousands) 1998 1997 ASSETS Utility Plant and Other Investments: Utility Plant in Service $1,000,243 $1,079,361 Less Accumulated Provisions for Depreciation and Amortization 353,780 376,722 Net Utility Plant in Service 646,463 702,639 Construction Work in Progress 5,151 5,538 Net Utility Plant 651,614 708,177 Non-utility Property - Net 55,274 71,516 Investments in Jointly Owned Companies 69,485 69,749 Other 55,320 62,834 Total Utility Plant and Other Investments 831,693 912,276 Current Assets: Cash and Temporary Cash Investments 32,090 7,252 Accounts Receivable: Customers, Net 55,286 64,214 Accrued Unbilled Revenues 10,655 14,103 Other 29,326 14,329 Notes Receivable 27,078 27,693 Materials and Supplies (at average cost): Fuel 6,024 4,304 Plant Materials and Operating Supplies 7,410 6,897 Other Current Assets 8,448 7,177 Total Current Assets 176,317 145,969 Other Assets 294,628 212,507 Total Assets $1,302,638 $1,270,752 LIABILITIES AND CAPITALIZATION Capitalization: Common Equity $373,674 $373,467 Non-Redeemable Preferred Stock of Subsidiaries - Net 6,900 6,900 Redeemable Preferred Stock of Subsidiaries - Net 27,995 27,612 Long-Term Debt - Net 310,346 332,802 Total Capitalization 718,915 740,781 Current Liabilities: Short-Term Debt 63,574 61,484 Long-Term Debt Due Within One Year 21,911 72,518 Accounts Payable 29,018 35,036 Taxes Accrued 14,208 3,063 Interest Accrued 6,997 8,624 Other Current Liabilities 34,908 33,327 Total Current Liabilities 170,616 214,052 Other Liabilities 271,078 152,526 Accumulated Deferred Taxes 142,029 163,393 Commitments and Contingencies (Note J) Total Liabilities and Capitalization $1,302,638 $1,270,752 The accompanying notes are an integral part of the financial statements.
Consolidated Statements of Retained Earnings
Years Ended December 31, ($ in thousands) 1998 1997 1996 Retained Earnings - Beginning of Year $56,062 $52,404 $56,228 Consolidated Net Earnings 34,710 37,960 30,614 Total 90,772 90,364 86,842 Dividends Paid - EUA Common Shares 33,924 33,924 33,618 Other 382 378 820 Retained Earnings - Accumulated since June 1991 Accounting Reorganization $56,466 $56,062 $52,404
Consolidated Statements of Equity Capital & Preferred Stock
Years Ended December 31, ($ in thousands) 1998 1997 EASTERN UTILITIES ASSOCIATES: Common Shares: $5 par value 36,000,000 shares authorized, 20,435,997 shares outstanding in 1998 and 1997 $102,180 $102,180 Other Paid-In Capital 218,959 219,156 Common Share Expense (3,931) (3,931) Retained Earnings - Accumulated since June 1991 Accounting Reorganization 56,466 56,062 Total Common Equity 373,674 373,467 CUMULATIVE PREFERRED STOCK OF SUBSIDIARIES: Non-Redeemable Preferred: Blackstone Valley Electric Company: 4.25% $100 par value 35,000 shares 3,500 3,500 5.60% $100 par value 25,000 shares 2,500 2,500 Premium 129 129 Newport Electric Corporation: 3.75% $100 par value 7,689 shares 769 769 Premium 2 2 Total Non-Redeemable Preferred Stock 6,900 6,900 Redeemable Preferred: Eastern Edison Company: 65/8% $100 par value 300,000 shares 30,000 30,000 Expense, Net of Premium (335) (335) Preferred Stock Redemption Costs (1,670) (2,053) Total Redeemable Preferred Stock 27,995 27,612 Total Preferred Stock of Subsidiaries $34,895 $34,512 Authorized and Outstanding. Authorized 400,000 shares. 300,000 shares outstanding at December 31, 1998. The accompanying notes are an integral part of the financial statements.
Consolidated Statements of Indebtedness
Years Ended December 31, ($ in thousands) 1998 1997 EUA Service Corporation: 10.2% Secured Notes due 2008 $6,200 $7,900 EUA Cogenex Corporation: 7.0% Unsecured Notes due 2000 50,000 50,000 9.6% Unsecured Notes due 2001 9,600 12,800 10.56% Unsecured Notes due 2005 24,500 28,000 EUA Ocean State Corporation: 9.59% Unsecured Notes due 2011 26,114 28,590 Blackstone Valley Electric Company: First Mortgage Bonds: 9 1/2% due 2004 (Series B) 9,000 10,500 10.35% due 2010 (Series C) 18,000 18,000 Variable Rate Demand Bonds due 2014 6,500 6,500 Eastern Edison Company First Mortgage and Collateral Trust Bonds: 5 7/8% due 1998 - 20,000 5 3/4% due 1998 - 40,000 7.78 % Secured Medium Term Notes due 2002 35,000 35,000 6 7/8% due 2003 40,000 40,000 6.35% due 2003 8,000 8,000 8.0% due 2023 40,000 40,000 Pollution Control Revenue Bonds: 5 7/8% due 2008 40,000 40,000 Newport Electric Corporation: First Mortgage Bonds: 9.0% due 1999 1,386 1,386 9.8% due 1999 8,000 8,000 8.95% due 2001 1,950 2,600 Small Business Administration Loan: 6.5% due 2005 533 628 Variable Rate Revenue Refunding Bonds due 2011 7,925 7,925 Unamortized (Discount) - Net (451) (509) 332,257 405,320 Less Portion Due Within One Year 21,911 72,518 Total Long-Term Debt - Net $310,346 $332,802 Weighted average interest rate was 3.6% for 1998 and 3.7% for 1997. The accompanying notes are an integral part of the financial statements.
Notes to Consolidated Financial Statements December 31, 1998, 1997 and 1996 (A) Nature of Operations and Summary of Significant Accounting Policies: General: Eastern Utilities Associates (EUA) is a public utility holding company headquartered in Boston, Massachusetts. Its subsidiaries are principally engaged in the generation, transmission, distribution and sale of electricity; energy related services such as energy management; and promoting the conservation and efficient use of energy. See "Generation Divestiture" below for a discussion of EUA's planned divestiture of generating capacity. Estimates: 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. Basis of Consolidation: The consolidated financial statements include the accounts of EUA and all subsidiaries. All material intercompany transactions between the consolidated subsidiaries have been eliminated. System of Accounts: The accounts of EUA and its consolidated subsidiaries are maintained in accordance with the uniform system of accounts prescribed by the regulatory bodies having jurisdiction. Jointly Owned Companies: Montaup Electric Company (Montaup) follows the equity method of accounting for its stock ownership investments in jointly owned companies including four regional nuclear generating companies. Montaup's investments in these nuclear generating companies range from 2.5% to 4.5%. Three of the four facilities, Yankee Atomic, Connecticut Yankee and Maine Yankee, have been permanently shut down and are in the process of decommissioning. Montaup's share of total estimated costs for the permanent shutdown, decommissioning and recovery of the investment in Yankee Atomic, Connecticut Yankee and Maine Yankee is $3.7 million, $23.8 million and $31.0 million, respectively. These amounts are included with Other Liabilities on the Consolidated Balance Sheet as of December 31, 1998. Also, due to anticipated recoverability, a regulatory asset has been recorded for the same amount and is included with Other Assets. Montaup is entitled to electricity produced from the remaining facility, Vermont Yankee, based on its ownership interest and is billed for its entitlement pursuant to a contractual agreement which is approved by the Federal Energy Regulatory Commission (FERC). Montaup also has a stock ownership investment of 3.27% in each of two companies which own and operate certain transmission facilities between the Hydro Quebec electric system and New England. EUA Ocean State Corporation (EUA Ocean State) follows the equity method of accounting for its 29.9% partnership interest in the Ocean State Power Project (OSP). Also, EUA Energy Investment follows the equity method of accounting for its partnership interest in BIOTEN, G.P. and for its 20% stock ownership in Separation Technologies, Inc. EUA is attempting to restructure its partnership interest in the BIOTEN, G.P. to a preferred equity position. These ownership interests and Montaup's stock ownership investments are included in "Investments in Jointly Owned Companies" on the Consolidated Balance Sheet. Plant and Depreciation: Utility plant is stated at original cost. The cost of additions to utility plant includes contracted work, direct labor and material, allocable overhead, allowance for funds used during construction and indirect charges for engineering and supervision. For financial statement purposes, depreciation is computed on the straight-line method based on estimated useful lives of the various classes of property. On a consolidated basis, provisions for depreciation on utility plant were equivalent to a composite rate of approximately 3.5% in 1998, 3.6% in 1997, 3.7% in 1996 based on the average depreciable property balances at the beginning and end of each year. Beginning in 1998, coincident with billing a contract termination charge (CTC) to its retail affiliates, Montaup commenced recovery of its net investment in generation related assets through the CTC over a twelve-year period. The difference between the annual recovery and annual depreciation expense pursu- ant to Generally Accepted Accounting Principles is being deferred. Non-utility property and equipment of EUA Cogenex Corporation (EUA Cogenex) is stated at original cost. For financial statement purposes, depreciation on office furniture and equipment, computer equipment and real property is computed on the straight-line method based on estimated useful lives ranging from five to forty years. Project equipment is depreciated over the term of the applicable contracts or based on the estimated useful lives, whichever is shorter, ranging from five to fifteen years. Allowance for Funds Used During Construction (AFUDC) and Capitalized Interest: AFUDC represents the estimated cost of borrowed and equity funds used to finance the EUA System's construction program. In accordance with regulatory accounting, AFUDC is capitalized as a cost of utility plant in the same manner as certain general and administrative costs. AFUDC is not an item of current cash income but is recovered over the service life of utility plant in the form of increased revenues collected as a result of higher depreciation expense. The combined rate used in calculating AFUDC was 8.0% in 1998 and 1997, and 9.0% in 1996. The caption "Allowance for Borrowed Funds Used During Construction" also includes interest capitalized for non-regulated entities in accordance with FASB Statement No. 34. Operating Revenues: Utility revenues are based on billing rates authorized by applicable federal and state regulatory commissions. Eastern Edison Company (Eastern Edison), Blackstone Valley Electric Company (Blackstone) and Newport Electric Corporation (Newport) (collectively, the Retail Subsidiaries) accrue the estimated amount of unbilled revenues at the end of each month to match costs and revenues more closely. Montaup recognizes revenues when billed. In 1998, Montaup and the Retail Subsidiaries also began recording revenues in an amount management believes to be recoverable pursuant to provisions of approved settlement agreements and enabling state legislation. Provisions of the approved restructuring settlement agreements in conjunction with accounting provisions of SFAS 71 allow Montaup and the retail subsidiaries to accrue and/or defer revenue related to the future recovery of certain items. Montaup has accrued revenues and recorded associated regulatory assets and liabilities for certain items during 1998 commencing with the implementation of the aforementioned settlement agreements and billing of the Contract Termination Charge (CTC), January 1, 1998 in Rhode Island and March 1, 1998 in Massachusetts. Montaup was authorized to accrue an amount of lost revenue equal to the difference in revenues Montaup would have collected under its previously approved rates and revenues collected pursuant to the settlement agreements. The settlements also provide Montaup with a nuclear PBR provision under which Montaup normalizes expenses and revenues for 80% of going forward operations of Montaup's nuclear interests. Montaup was also allowed to accrue a return enhancement related to stranded investments charged to its Rhode Island retail affiliates during the generation divestiture period as an incentive to divest. Also, Montaup is normalizing the difference between GAAP depreciation expense on generation plant assets prior to divestiture and the recovery level included in the settlement agreements. Montaup has also accrued revenue related to the two-month delay in implementing the Massachusetts settlement agreement from January 1, 1998 to March 1, 1998. Finally, Montaup normalizes for the difference in actual versus estimated CTC variable components costs and revenues. Settlement provisions and SFAS 71 also provide for Eastern Edison to accrue revenue equal to the approved deferral of standard offer costs which will be collected in the future. The following table reflects the nature and amount of accrued and/or deferred revenue and the associated balance sheet placement. Amount Balance Accrued Sheet (Deferred) Placement $000 Lost revenue $ 18,527 Other Asset/Accrued CTC Assets Mass. Delay Credit 768 Other Asset/Accrued CTC Assets R.I. Return True-up 1,970 Other Asset/Accrued CTC Assets Depr. Norm. (12 yr S/L vs. CTC Level) 10,933 Other Asset/Accrued CTC Assets Depr. Norm (GAAP vs. 12 yr S/L) (14,294) Other Liab./Reg. Liab. Nuclear PBR 3,933 Other Asset/Other Reg. Assets CTC Variable Component Norm. (23,793) Other Liab./Reg. Liab. Eastern Edison Standard Offer Deferral 8,782 Other Accts. Rec./Reg. Assets EUA Cogenex's revenues are recognized based on financial arrangements established by each individual contract. Under paid-from-savings contracts, revenues are recognized as energy savings are realized by customers. Revenue from the sale of energy savings projects and sales-type leases are recognized when the sales are complete. Interest on the financing portion of the contracts is recognized as earned at rates established at the outset of the financing arrangement. All construction and installation costs are recognized as contract expenses when the contract revenues are recorded. In circumstances in which material uncertainties exist as to contract profitability, cost recovery accounting is followed and revenues received under such contracts are first accounted for as recovery of costs to the extent incurred. Federal Income Taxes: EUA and its subsidiaries generally reflect in income the estimated amount of taxes currently payable, and provide for deferred taxes on certain items subject to temporary timing differences to the extent permitted by the various regulatory agencies. EUA's rate-regulated subsidiaries amortize previously deferred investment tax credits (ITC) over the productive lives of the related assets. Beginning in 1998, Montaup is amortizing previously deferred ITC related to generation investments recoverable through the CTC over a twelve-year period. Unamortized ITC related to the Canal 2 generating unit was reversed at the time of the Canal 2 sale, December 30, 1998. Cash and Temporary Cash Investments: EUA considers all highly liquid investments and temporary cash investments with a maturity of three months or less when acquired to be cash equivalents. Other Assets: The components of Other Assets at December 31, 1998 and 1997 are detailed as follows:
($ in thousands) 1998 1997 Regulatory Assets: Unamortized losses on reacquired debt $10,979 $12,299 Unrecovered plant and decommissioning costs 66,934 68,345 Deferred FAS 109 costs (Note B) 50,167 57,732 Deferred FAS 106 costs 9,167 3,310 Mendon Road judgment (Note J) 6,154 6,154 Unrecovered CTC assets 33,161 Accrued CTC assets 32,198 Other regulatory assets 21,947 15,524 Total regulatory assets 230,707 163,364 Other deferred charges and assets: Split dollar life insurance premiums 24,803 15,502 Unamortized debt expenses 3,381 3,954 Goodwill 6,436 6,642 Other 29,301 23,045 Total Other Assets $294,628 $212,507
Regulatory assets represent deferred costs for which future revenues are expected in accordance with regulatory practices. These costs are expensed when the corresponding revenues are received in order to appropriately match revenues and expenses. Regulatory Accounting: Core Electric companies are subject to certain accounting rules that are not applicable to other industries. These accounting rules allow regulated companies, in appropriate circumstances, to establish regulatory assets and liabilities which defer the current financial impact of certain costs that are expected to be recovered in future rates. In light of approved restructuring settlement agreements and restructuring legislation in both Massachusetts and Rhode Island, EUA has determined that Montaup no longer will apply the provisions of Financial Accounting Standards Board's (FASB) Statement of Financial Accounting Standards No. 71 (FAS71), "Accounting for the Effects of Certain Types of Regulation" for the generation portion of its business. Montaup ceased applying SFAS 71 to its ongoing generation portion of its business effective January 1, 1998. Approved restructuring settlement agreements with parties in Massachusetts and Rhode Island, the two states in which Montaup operates, allow Montaup full recovery or stranded generation investments as of December 31, 1997 and as such Montaup incurred no asset impairment. As disclosed in Footnote A under the caption "GENERATION DIVESTITURE", Montaup has agreements to divest all of its generation assets and power purchase agreements with the exception of its 4.0% (46mw) ownership interest in the Millstone 3 nuclear station and is 12 mw entitlement from the Vermont Yankee nuclear unit. Post-divestiture ongoing generation operations will include the two aforementioned nuclear units in which Montaup will continue to have an interest. The approved settlement agreements also provide Montaup with recovery of 100% of embedded nuclear investments as of December 31, 1997 and recovery of 80% of its post 1997 on going nuclear generation operations. Because only 20% of Montaup's remaining nuclear operations will no longer be subject to the accounting treatment pursuant to SFAS 71 and would be subject to market risk, Management believes that the discontinuation of SFAS 71 for Montaup's post-divestiture generation business will not have a material impact on EUA's results of operations or financial position. EUA believes its transmission and retail distribution businesses continue to meet the criteria for continued application of FAS71. Generation Divestiture: Terms of approved electric utility restructuring settlement agreements provide that EUA exit the electric generation business. Through separately negotiated agreements, EUA has agreements to divest all of its generation assets and power purchase contracts, with the exception of its 4.0% (46 mw) ownership interest in the Millstone 3 nuclear station and its 12 mw entitlement from Vermont Yankee. All of the agreements are subject to approval of various state and federal regulatory agencies. EUA has agreed to sell generating assets totaling 509 mw to various parties for $133.2 million in aggregate. The net proceeds from the sales, as defined in the settlement agreements, will be recorded as a regulatory liability at the time of sale and will be returned to customers via a Residual Value Credit (RVC) through the year 2009. EUA has also agreed to make contribution payments to two parties in exchange for their assumption of all future obligations under six purchased power contracts. These fixed monthly payments ranging from $850,000 to $2.6 million, will be made from the effective date through 2009. EUA may be required to record a liability for these fixed contributions, but in such an event would record a regulatory asset for a like amount due to recoverability. In addition, EUA has agreed to a buyout of its obligations under the Pilgrim Nuclear purchased power contract in conjunction with the sale of the unit by Boston Edison Co. (BEC) to Entergy Nuclear Generating Co. (Entergy). This agreement provides for a buyout payment by EUA to BEC of $115.8 million , assuming a June 30, 1999 closing, along with a short-term, fixed-price purchased power agreement with Entergy for declining shares of the unit's output beginning with 11% in 1999 and ending with 5.5% in 2004. Entergy will assume all future operating and decommissioning obligations. EUA will continue to attempt to sell and/or transfer its minority interests in Millstone 3 and Vermont Yankee. Until such time as these units are divested, EUA will share 80% of the operating costs and revenues associated with the units with customers and 20% with shareholders. (B) Income Taxes: EUA adopted FASB Statement No. 109, "Accounting for Income Taxes" (FAS109), which requires recognition of deferred income taxes for temporary differences that are reported in different years for financial reporting and tax purposes using the liability method. Under the liability method, deferred tax liabilities or assets are computed using the tax rates that will be in effect when temporary differences reverse. Generally, for regulated companies, the change in tax rates may not be immediately recognized in operating results because of ratemaking treatment and provisions in the Tax Reform Act of 1986. Total deferred tax assets and liabilities for 1998 and 1997 include the following: Deferred Tax Deferred Tax Assets Liabilities
($ in thousands) 1998 1997 1998 1997 Plant Related Plant Related Differences $22,776 $18,947 Differences $185,590 $191,274 Deregulation 23,301 Refinancing Costs 1,325 1,406 NOL Deregulation 12,993 Carryforward 1,973 2,294 Employee Benefit Employee Accruals 4,481 3,670 Benefit Accruals 5,294 4,975 Acquisitions 3,334 3,650 Other 14,075 14,157 Other 8,393 11,066 Total $70,753 $44,023 Total $212,782 $207,416
As of December 31, 1998 and 1997, EUA has recorded on its Consolidated Balance Sheet a regulatory liability to ratepayers of approximately $15.5 million and $18.8 million respectively. These amounts primarily represent excess deferred income taxes resulting from the reduction in the federal income tax rate and also include deferred taxes provided on investment tax credits. Also at December 31, 1998 and 1997, a regulatory asset of approximately $50.2 million and $57.7 million, respectively, has been recorded, representing the cumulative amount of federal income taxes on temporary depreciation differences which were previously flowed through to ratepayers. Components of income tax expense for the year 1998, 1997, and 1996 are as follows:
($ in thousands) 1998 1997 1996 Federal: Current $30,755 $17,249 $ (231) Deferred (14,054) (4,901) 9,838 Investment Tax Credit, Net (3,000) (1,120) (1,125) 13,701 11,228 8,482 State: Current 5,217 3,623 2,823 Deferred (961) (628) (363) 4,256 2,995 2,460 Charged to Operations 17,957 14,223 10,942 Charged to Other Income: Current 4,416 9,142 4,798 Deferred (2,839) (789) 2,135 Investment Tax Credit, Net (81) (81) (82) 1,496 8,272 6,851 Total Income Tax Expense $19,453 $22,495 $17,793
Total income tax expense was different from the amounts computed by applying federal income tax statutory rates to book income subject to tax for the following reasons:
($ in thousands) 1998 1997 1996 Federal Income Tax Computed at Statutory Rates $19,764 $21,966 $17,751 (Decrease) Increase in Tax from: Equity Component of AFUDC (60) (57) (189) Depreciation Differences 1,320 (12) 2 Amortization of ITC (3,081) (1,201) (1,207) State Taxes, Net of Federal Income Tax Benefit 2,803 2,092 1,952 Other (1,293) (293) (516) Total Income Tax Expense $19,453 $22,495 $17,793
(C) Capital Stock: The Agreement and Plan of Merger dated February 1, 1999 by and among New England Electric System (NEES) and EUA, which is subject to EUA shareholder and various regulatory agencies' approval, provides for NEES to purchase all of the outstanding EUA shares for $31 per share in cash. The transaction is expected to be completed by early 2000. There was no change in the number of common shares outstanding during 1998 and 1997. As permitted, the Company accounts for its stock-based compensation, as discussed below, using the method prescribed in Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" (APB25) and as permitted under FASB Statement No. 123, "Accounting for Stock-Based Compensation" (FAS123). The Company established a Restricted Stock Plan in 1989. Under the Restricted Stock Plan, executives and certain key employees may be granted restricted common shares of the Company. In 1998, 1997 and 1995, approximately 74,000 shares, 95,000 shares and 61,000 shares, respectively, of restricted common shares, valued at approximately $1.8 million, $2.4 million and $1.4 million, respectively, were granted. The issued shares are restricted for a period ranging from two to five years and all shares are subject to forfeiture if specified employment services are not met. There are no exercise prices related to these share grants. During the applicable restriction period, the recipient has all the voting, dividend, and other rights of a record holder except that the shares are nontransferable. The annual compensation expense related to these grant awards was approximately $1.6 million in 1998 and was immaterial for 1997 and 1996. There are no material differences in the Company recording its annual compensation expense under APB25 from the requirements under FAS123. All of the restricted shares will become immediately vested upon the completion of EUA's plan of merger with NEES. The preferred stock provisions of the Retail Subsidiaries place certain restrictions upon the payment of dividends on common stock by each company. At December 31, 1998 and 1997, each company was in excess of the minimum requirements which would make these restrictions effective. In the event of involuntary liquidation, the holders of non-redeemable preferred stock of the Retail Subsidiaries are entitled to $100 per share plus accrued dividends. In the event of voluntary liquidation, or if redeemed at the option of these companies, each share of the non-redeemable preferred stock is entitled to accrued dividends plus the following: Company Issue Amount Blackstone: 4.25% issue $104.40 5.60% issue 103.82 Newport: 3.75% issue 103.50 (D) Redeemable Preferred Stock: Eastern Edison's 6 5/8% Preferred Stock issue is entitled to an annual mandatory sinking fund sufficient to redeem 15,000 shares commencing September 1, 2003. The redemption price is $100 per share plus accrued dividends. All outstanding shares of the 6 5/8% issue are subject to mandatory redemption on September 1, 2008, at a price of $100 per share plus accrued dividends. In the event of liquidation, the holders of Eastern Edison's 6 5/8% Preferred Stock are entitled to $100 per share plus accrued dividends. (E) Long-Term Debt: The various mortgage bond issues of Blackstone, Eastern Edison, and Newport are collateralized by substantially all of their utility plant. In addition, Eastern Edison's bonds are collateralized by securities of Montaup, which are wholly-owned by Eastern Edison. On December 30, 1998, Montaup redeemed $55 million of debenture bonds and paid a $19 million special dividend to Eastern Edison with proceeds received from the sale of its 50% ownership share of the Canal 2 generating station. The principal amount of Montaup securities wholly-owned by Eastern Edison at December 31, 1998 was approximately $181 million. Blackstone's Variable Rate Demand Bonds are collateralized by an irrevocable Letter of Credit which expires on January 21, 2000. The letter of credit permits an extension of one year upon mutual agreement of the bank and Blackstone. Newport's Variable Rate Electric Energy Facilities Revenue Refunding Bonds are collateralized by an irrevocable Letter of Credit which expires on January 6, 2000, and permits an extension of one year upon mutual agreement of the bank and Newport. EUA Service Corporation's (EUA Service) 10.2% Secured Notes due 2008 are collateralized by certain real estate and property of the company. In July, Eastern Edison used short-term borrowings to redeem $20 million of 5 7/8% and $40 million of 5 3/4%, First Mortgage and Collateral Trust Bonds at maturity. On December 30, 1998, Eastern repaid outstanding short-term borrowings with proceeds received from the redemption of Montaup securities. The EUA System's aggregate amount of current cash sinking fund requirements and maturities of long-term debt, (excluding amounts that may be satisfied by available property additions) for each of the five years following 1998 are: $21.9 million in 19 99, $62.5 million in 2000, $14.3 million in 2001, $46 million in 2002, and $60 million in 2003. (F) Fair Value Of Financial Instruments: The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate: Cash and Temporary Cash Investments: The carrying amount approximates fair value because of the short-term maturity of these instruments. Long Term Notes Receivable and Net Investment in Sales-Type Leases: The fair value of these assets are based on market rates of similar securities. Preferred Stock and Long-Term Debt of Subsidiaries: The fair value of the System redeemable preferred stock and long-term debt were based on quoted market prices for such securities at December 31, 1998 and 1997. The estimated fair values of the System's financial instruments at December 31, 1998 and 1997, were as follows: Carrying Amount Fair Value
($ in thousands) 1998 1997 1998 1997 Cash and Temporary Cash Investments $32,090 $7,252 $32,090 $7,252 Long-Term Notes Receivable and Net Investment in Sales-Type Leases 40,934 46,192 42,052 47,200 Redeemable Preferred Stock 30,000 30,000 32,625 31,613 Long-Term Debt 332,708 405,829 350,392 429,035
(G) Lines Of Credit: 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. At December 31, 1998, the EUA System had unused short-term lines of credit of approximately $101.4 million. During 1998, the weighted average interest rate for short-term borrowings was 5.8%. (H) Jointly Owned Facilities: At December 31, 1998, in addition to the stock ownership interests discussed in Note A, Nature of Operations and Summary of Significant Accounting Policies - Jointly Owned Companies, Montaup and Newport had direct ownership interests in the following electric generating facilities:
Accumulated Net Utility Provision for Utility Construction Percent Plant in Depreciation Plant in Work in ($ in thousands) Owned Service & Amortization Service Progress Montaup: Wyman Unit 4 1.96% $4,041 $2,388 $1,653 $ Seabrook Unit I 2.90% 194,169 47,277 146,892 480 Millstone Unit 3 4.01% 178,598 65,705 112,893 347 Newport: Wyman Unit 4 0.67% 1,312 805 507
The foregoing amounts represent Montaup's and Newport's interest in each facility, including nuclear fuel where appropriate, and are included on the like-captioned lines on the Consolidated Balance Sheet. At December 31, 1998, Montaup's total net investment in nuclear fuel of the Seabrook and Millstone Units amounted to $2.5 million and $1.9 million, respectively. Montaup's and Newport's shares of related operating and maintenance expenses with respect to units reflected in the preceding table are included in the corresponding operating expenses. EUA has entered into agreements to sell its joint ownership shares in Wyman Unit 4 and Seabrook Unit I. Closing of the Wyman sale is expected in the first quarter of 1999 and the Seabrook sale is expected to close later in 1999. Both agreements are subject to approval of various regulatory agencies. (I) Financial Information By Business Segments: Statement of Financial Accounting Standards No. 131, Disclosures about Segments of an Enterprise and Related Information (SFAS 131), requires disclosure of certain financial and descriptive information by operating segments. The Core Electric Business includes results of the electric utility operations of Blackstone, Eastern Edison, Newport and Montaup. Energy Related Business includes results of our diversified energy- related subsidiaries, EUA Cogenex, EUA Ocean State, EUA Energy Investment Corporation (EUA Energy), EUA Energy services and EUA Telecommunications. Corporate results include the operations of EUA Service and EUA Parent. EUA does not have any intersegment revenues. Financial data for the business segments are as follows:
Pre-Tax Depreciation Cash Equity in Net Net Operating Operating Income and Construction Subsidiary Interest Interest ($ in thousands) Revenues Income Taxes Amortization Expenditures Earnings Charges Income Year Ended December 31, 1998 Core Electric $480,080 $84,586 $22,685 $38,804 $22,888 $1,390 $23,593 $528 Energy Related 58,721 (2,945) (1,387) 12,267 26,801 8,134 12,219 7,210 Corporate (2,045) (1,845) 8 1,512 1,387 63 Total $538,801 $79,596 $19,453 $51,079 $51,201 $9,524 $37,199 $7,801 Year Ended December 31, 1997 Core Electric $506,696 $78,795 $20,303 $36,069 $21,870 $1,599 $24,668 $1,678 Energy Related 61,817 (3,785) 547 10,858 51,941 7,867 13,295 8,854 Corporate (1,980) 1,645 14 2,307 1,193 16 Total $568,513 $73,030 $22,495 $46,941 $76,118 $9,466 $39,156 $10,548 Year Ended December 31, 1996 Core Electric $470,719 $80,042 $21,039 $35,178 $33,337 $1,587 $24,290 $ 394 Energy Related 56,349 (11,536) (3,888) 10,290 28,121 9,111 13,494 7,212 Corporate (1,723) 642 10 1,272 1,335 156 Total $ 527,068 $66,783 $17,793 $45,478 $62,730 $10,698 $39,119 $7,762
Years ended December 31, ($ in thousands) 1998 1997 Total Plant and Other Investments Core Electric $648,281 $703,132 Energy Related 164,439 187,752 Corporate 18,973 21,392 Total Plant and Other Investments 831,693 912,276 Other Assets Core Electric 370,360 257,888 Energy Related 67,780 73,109 Corporate 32,805 27,479 Total Other Assets 470,945 358,476 Total Assets $1,302,638 $1,270,752
(J) Commitments And Contingencies: Plan of Merger Agreement: On February 1, 1999, EUA and New England Electric System (NEES) entered into an Agreement and Plan of Merger under which NEES will acquire all outstanding shares of EUA for $31 per share in cash. Under certain terms of the merger agreement, if the merger agreement is terminated by EUA, EUA would pay NEES a termination fee of $20 million plus up to $5 million for documented out-of-pocket expenses. Nuclear Fuel Disposal and Nuclear Plant Decommissioning Costs: The owners (or lead participants) of the nuclear units in which Montaup has an interest have made, or expect to make, various arrangements for the acquisition of uranium concentrate, the conversion, enrichment, fabrication and utilization of nuclear fuel and the disposition of that fuel after use. The owners (or lead participants) of United States nuclear units have entered into contracts with the Department of Energy (DOE) for disposal of spent nuclear fuel in accordance with the Nuclear Waste Policy Act of 1982 (NWPA). The NWPA requires (subject to various contingencies) that the federal government design, license, construct and operate a permanent repository for high level radioactive wastes and spent nuclear fuel and establish a prescribed fee for the disposal of such wastes and nuclear fuel. The NWPA specifies that the DOE provide for the disposal of such waste and spent nuclear fuel starting in 1998. Objections on environmental and other grounds have been asserted against proposals for storage as well as disposal of spent nuclear fuel. The DOE now estimates that a permanent disposal site for spent fuel will not be ready to accept fuel for storage or disposal until as late as the year 2010. In early 1998, a number of utilities filed suit in federal appeals court seeking, among other things, an order requiring the DOE to immediately establish a program for the disposal of spent nuclear fuel. Montaup owns a 4.01% interest in Millstone 3 and a 2.9% interest in Seabrook I. Northeast Utilities, the operator of the units, indicates that Millstone 3 has sufficient on-site storage facilities which, with rack additions, can accommodate its spent fuel for the projected life of the unit. At the Seabrook Project, there is on-site storage capacity which, with rack additions, will be sufficient to at least the year 2011. The Energy Policy Act of 1992 requires that a fund be created for the decommissioning and decontamination of the DOE uranium enrichment facilities. The fund will be financed in part by special assessments on nuclear power plants in which Montaup has an interest. These assessments are calculated based on the utilities' prior use of the government facilities and have been levied by the DOE, starting in September 1993, and will continue over 15 years. This cost is passed on to the joint owners or power buyers as an additional fuel charge on a monthly basis and is currently being recovered by Montaup through rates. Montaup has a 4.5% equity ownership in Connecticut Yankee, a nuclear generating facility which is in the process of decommissioning. Montaup's share of the total estimated costs for the permanent shutdown, decommissioning, and recovery of the investment in Connecticut Yankee is approximately $23.8 million. On August 31, 1998, a FERC law judge rejected Connecticut Yankee's filed plan to decommission the plant. The judge claimed that estimates of clean-up costs were flawed and certain restoration costs were not supported. The judge also said Connecticut Yankee could not pass on spent fuel storage costs to rate- payers. The judge recommended that Connecticut Yankee withdraw its decommissioning plan and submit a new plan which addresses the issues cited by him. FERC will review the judge's recommendations and issue a decision on this case in the coming months. If FERC concurs with the judge's recommendation, this may result in a write down of certain of Connecticut Yankee plant investments. Montaup cannot predict the ultimate outcome of FERC's review. In August 1997, as the result of an economic evaluation, the Maine Yankee Board of Directors voted to permanently close that nuclear plant. Montaup has a 4.0% equity ownership in Maine Yankee. Montaup's share of the total estimated costs for the permanent shutdown, decommissioning, and recovery of the remaining investment in Maine Yankee is approximately $31.0 million. In January 1998, FERC accepted Maine Yankee's rate filing, subject to refund, for the recovery of its costs during the decommissioning period. On January 19, 1999, Maine Yankee and the active intervening parties filed an Offer of Settlement with FERC which was supported by FERC trial staff. Upon commission approval, this agreement will constitute full settlement of issues raised in this proceeding. Also, Montaup is recovering through rates its share of estimated decommissioning costs for Millstone 3 and Seabrook I. Montaup's share of the current estimate of total costs to decommission Millstone 3 is $22.4 million in 1998 dollars, and Seabrook I is $14.4 million in 1998 dollars. These figures are based on studies performed for the lead owners of the units. Montaup also pays into decommissioning reserves pursuant to contractual arrangements with other nuclear generating facilities in which it has an equity ownership interest or life of the unit entitlement. Such expenses are currently recoverable through rates. Pensions: EUA maintains a noncontributory defined benefit pension plan covering most of the employees of the EUA System (Retirement Plan). Retirement Plan benefits are based on years of service and average compensation over the four years prior to retirement. It is the EUA System's policy to fund the Retirement Plan on a current basis in amounts determined to meet the funding standards established by the Employee Retirement Income Security Act of 1974. Total pension (income) expense for the Retirement Plan, including an amount related to the 1997 voluntary retirement incentive offer, for 1998, 1997 and 1996 included the following components:
($ in thousands) 1998 1997 1996 Service cost $2,929 $2,816 $3,126 Interest cost 10,390 10,116 9,765 Expected return on assets (15,033) (13,761) (12,817) Net amortization: Prior service cost 671 667 700 Net actuarial (gain) (395) (183) Transition obligation (asset) (274) (274) (274) Net periodic pension (income) expense (1,712) (619) 500 Subsidiary Curtailment (131) Total periodic pension (income) expense $(1,712) $(750) $500 Assumptions used to determine pension costs: Discount Rate 7.25% 7.50% 7.25% Compensation Increase Rate 4.25% 4.25% 4.25% Long-Term Return on Assets 9.50% 9.50% 9.50%
The following tables set forth the actuarial present value of projected benefit obligations, fair value of assets and funded status at December 31, 1998 and 1997: Reconciliation of Projected Benefit Obligation
($ in thousands) 1998 1997 Beginning of Year Benefit Obligation $144,915 $136,286 Service Cost 2,929 2,816 Interest Cost 10,390 10,116 Actuarial loss 9,256 4,519 Disbursements (8,032) (8,403) Settlements or curtailments (419) End of year benefit obligation $159,458 $144,915 Reconciliation of Fair Value of Assets ($ in thousands) 1998 1997 Beginning of Year Fair Value of Assets $182,795 $161,300 Actual return on plan assets 38,074 29,898 Disbursements (8,032) (8,403) End of Year Fair Value of Assets $212,837 $182,795 Reconciliation of Funded Status ($ in thousands) 1998 1997 Projected benefit obligation (PBO) $(159,458) $(144,915) Fair value of plan assets (FVA) 212,837 182,795 PBO less than FVA (funded status) 53,379 37,880 Unrecognized prior service cost 4,153 4,768 Unrecognized net transition obligation (asset) (662) (936) Unrecognized net actuarial (gain) (54,845) (41,399) Net amount recognized $2,025 $313
The discount rate used to determine pension obligations, effective January 1, 1999 was changed from 7.25% to 6.75% and was used to calculate the plan's funded status at December 31, 1998. The voluntary retirement incentive also resulted in $1.3 million of non- qualified pension benefits which were expensed in 1997. At December 31, 1998, approximately $2.7 million was included in other liabilities for these unfunded benefits. EUA also maintains non-qualified supplemental retirement plans for certain officers and trustees of the EUA System (Supplemental Plans). Benefits provided under the Supplemental Plans are based primarily on compensation at retirement date. EUA maintains life insurance on certain participants of the Supplemental Plans, and policy cash values and death benefits may be available to offset EUA's obligations under the Supplemental Plans. As of December 31, 1998, approximately $6.5 million was included in accrued expenses and other liabilities for these plans. Expenses related to the Supplemental Plans were $1.1 million in 1998, $1.9 million in 1997, and $1.5 million in 1996. EUA also provides a defined contribution 401(k) savings plan for substantially all employees. EUA's matching percentage of employees' voluntary contributions to the plan, amounted to $1.5 million in 1998 and 1997, and $1.3 million in 1996. Post-Retirement Benefits: Retired employees are entitled to participate in health care and life insurance benefit plans. Health care benefits are subject to deductibles and other limitations. Health care and life insurance benefits are partially funded by EUA System companies for all qualified employees. The total cost of post-retirement benefits other than pensions, including an amount related to the 1997 voluntary retirement incentive offer, for 1998, 1997 and 1996 includes the following components:
($ in thousands) 1998 1997 1996 Service cost $967 $949 $1,123 Interest cost 4,526 4,434 4,449 Expected return on assets (1,849) (1,254) (847) Net amortization: Net actuarial (gain) (780) (842) (617) Transition obligation 3,289 3,289 3,313 Net periodic postretirement benefit cost 6,153 6,576 7,421 Subsidiary Curtailment (548) Voluntary Retirement Incentive 172 Total periodic postretirement Benefit cost $6,153 $6,200 $7,421 Assumptions used to determine post-retirement costs Discount rate 7.25% 7.50% 7.25% Health care cost trend rate - near-term 6.00% 7.00% 9.00% - long-term 5.00% 5.00% 5.00% Compensation increase rate 4.25% 4.25% 4.25% Long-term return on assets - union 8.50% 8.75% 8.50% - non-union 7.50% 7.75% 7.50%
The following tables forth the actuarial present value of accumulated postretirement benefit obligation, fair value of assets and funded status at December 31, 1998. Reconciliation of Accumulated Post-retirement Benefit Obligation ($ in thousands) 1998 1997 Beginning of Year Benefit Obligation $ 64,826 $ 62,122 Service Cost 967 949 Interest Cost 4,526 4,434 Participant Contributions 151 211 Actuarial Loss 2,644 242 Disbursements (3,486) (2,791) Settlements or Curtailments (341) End of Year Benefit Obligation $ 69,628 $ 64,826 Reconciliation of Fair Value Assets ($ in thousands) 1998 1997 Beginning of Year Fair Value of Assets $ 23,729 $ 17,743 Actual return on plan assets 3,007 1,433 Company contributions 6,794 7,133 Participant contributions 151 211 Disbursements (3,486) (2,791) End of Year Fair Value of Assets $ 30,195 $ 23,729 Reconciliation of Funded Status ($ in thousands) 1998 1997 Accumulated post-retirement benefit obligation (APBO) $(69,628) $(64,826) Fair value of plan assets (FVA) 30,195 23,729 APBO (in excess of) FVA (Funded Status) (39,433) (41,097) Unrecognized net transition obligation (asset) 46,046 49,335 Unrecognized net actuarial (gain) (13,967) (16,233) Net amount recognized $(7,354) $(7,995) Effect of 1% Change in Assumed Health Care Cost Trend Rate One Percentage Point ($ in thousands) Increase Decrease Effect on 1998 service and interest cost components of net-periodic costs $814 $(649) Effect on 1998 accumulated post-retirement benefit obligation $8,578 $(6,996) The discount rate used to determine post-retirement benefit obligations effective January 1, 1999 was changed from 7.25% to 6.75% and was used to calculate the funded status of post-retirement benefits at December 31, 1998. Long-Term Purchased Power Contracts: The EUA System is committed under long- term purchased power contracts, expiring on various dates through September 2021, to pay demand charges whether or not energy is received. Under terms in effect at December 31, 1998, the aggregate annual minimum commitments for such contracts are approximately $111 million in 1999, $109 million in 2000, $111 million in 2001, $108 million in 2002, $101 million in 2003 and will aggregate approximately $927 million for the ensuing years. In addition, the EUA System is required to pay additional amounts depending on the actual amount of energy received under contracts in effect. The demand costs associated with these contracts are reflected as Purchased Power-Demand on the Consolidated Statement of Income. Such costs are currently recoverable through rates. Pending regulatory approval, certain power contract transfers related to the divestiture of EUA's generating assets will become effective in 1999. Upon completion of the power contract transfers, the demand charges will be reduced to $54 million in 1999, $43 million in 2000, $40 million in 2001, $42 million in 2002, $26 million in 2003, and $162 million in the ensuing years. Environmental Matters: There is an extensive body of federal and state statutes governing environmental matters, which permit, among other things, federal and state authorities to initiate legal action providing for liability, compensation, cleanup, and emergency response to the release or threatened release of hazardous substances into the environment and for the cleanup of inactive hazardous waste disposal sites which constitute substantial hazards. Because of the nature of the EUA System's business, various by-products and substances are produced or handled which are classified as hazardous under the rules and regulations promulgated by the United States Environmental Protection Agency (EPA) as well as state and local authorities. The EUA System generally provides for the disposal of such substances through licensed contractors, but these statutory provisions generally impose potential joint and several responsibility on the generators of the wastes for cleanup costs. Subsidi- aries of EUA have been notified with respect to a number of sites where they may be responsible for such costs, including sites where they may have joint and several liability with other responsible parties. It is the policy of the EUA System companies to notify liability insurers and to initiate claims. EUA is unable to predict whether liability, if any, will be assumed by, or can be enforced against, the insurance carriers in these matters. On December 13, 1994, the United States District Court for the District of Massachusetts (District Court) issued a judgment against Blackstone, finding Blackstone liable to the Commonwealth of Massachusetts (Commonwealth) for the full amount of response costs incurred by the Commonwealth in the cleanup of a by-product of manufactured gas at a site at Mendon Road in Attleboro, Massachusetts. The judgment also found Blackstone liable for interest and litigation expenses calculated to the date of judgment. The total liability is approximately $5.9 million, including approximately $3.6 million in interest which had accumulated since 1985. Due to the uncertainty of the ultimate outcome of this proceeding and anticipated recoverability whether through rates, insurance providers or other parties, Blackstone recorded an asset for the amount funded under the escrow agreement (discussed below) consistent with provisions of SFAS 5, specifically paragraphs 3, 10, and 13 and SFAS 71, specifically paragraphs 3 and 9. This amount is included with Other Assets on the Consolidated Balance Sheets at December 31, 1998 and 1997. Should the EPA determine the substance to be non-toxic, the company may be able to retain the entire escrowed amount and would relieve both the asset and liability from its balance sheet at that time. However should the EPA determine that the substance is hazardous, the company would amortize its asset, net of amounts recovered through insurance proceeds or from other parties, over a five year period in accordance with the company's established rate recovery mechanisms of similar costs. Blackstone filed a Notice of Appeal of the District Court Judgment and filed its brief with the United States Court of Appeals for the First Circuit (First Circuit) on February 24, 1995. On October 6, 1995, the First Circuit vacated the District Court's judgment and ordered the District Court to refer the matter to the EPA to determine whether the chemical substance, ferric ferrocyanide (FFC), contained within the by-product is a hazardous substance. On January 20, 1995, Blackstone entered into an escrow agreement with the Commonwealth whereby Blackstone deposited $5.9 million with an escrow agent who transferred the funds into an interest bearing money market account. The distribution of the proceeds of the escrow account will be determined upon the final resolution of the judgment. No additional interest expense will accrue on the judgment amount. On January 28, 1994, Blackstone filed a complaint in the District Court, seeking, among other relief, contribution and reimbursement from Stone & Webster Inc., of New York City and several of its affiliated companies (Stone & Webster), and Valley Gas Company of Cumberland, Rhode Island (Valley) for any damages incurred by Blackstone regarding the Mendon Road site. On November 7, 1994, the Court denied motions to dismiss the complaint which were filed by Stone & Webster and Valley. This proceeding was stayed in December 1995 pending final EPA determination as to whether FFC is a hazardous substance. In addition, Blackstone has notified certain liability insurers and has filed claims with respect to the Mendon Road site, as well as other sites. Blackstone reached settlement with one carrier for reimbursement of legal costs related to the Mendon Road case. In January 1996, Blackstone received the proceeds of the settlement. As of December 31, 1998, the EUA System had incurred costs of approximately $7.7 million (excluding the $5.9 million Mendon Road judgment) in connection with the investigation and clean-up of these sites, substantially all of which relate to Blackstone. These amounts have been financed primarily by internally generated cash. Blackstone is currently amortizing all of its incurred costs over a five-year period consistent with prior regulatory recovery periods and is recovering certain of those costs in rates. EUA estimates that additional costs of up to $2.5 million (excluding the $5.9 million Mendon Road judgment) may be incurred at these sites through 1999, substantially all of which relates to sites at which Blackstone is a potentially responsible party. Estimates beyond 1999 cannot be made since site studies, which are the basis of these estimates, have not been completed. As a result of the recoverability of cleanup costs in rates and the uncertainty regarding both its estimated liability, as well as its potential contributions from insurance carriers and other responsible parties, EUA does not believe that the ultimate impact of the environmental costs will be material to the financial position of the EUA System or to any individual subsidiary and thus no loss provision is required at this time. The Clean Air Act Amendments created new regulatory programs and generally updated and strengthened air pollution control laws. These amendments expanded the regulatory role of the EPA regarding emissions from electric generating facilities and a host of other sources. EUA System generating facilities were first affected in 1995, when EPA regulations took effect for facilities owned by the EUA System. Montaup's coal-fired Somerset Unit 6 is utilizing lower sulfur content coal to meet the 1995 air standards. EUA does not anticipate the impact from the Amendments to be material to the financial position of the EUA System. In July 1997, the EPA issued a new and more stringent rule covering ozone particulate matter which is to be followed by promulgation of more stringent ozone and particulate matter standards. The effect that such standards will have on the EUA System cannot be determined by management at this time. Eastern Edison, Montaup, the Massachusetts Attorney General and Division of Energy Resources entered into a settlement regarding electric utility industry restructuring in Massachusetts. The settlement includes a plan for emissions reductions related to Montaup's Somerset Station Units 5 and 6. The basis for SO2 and NOx emission reductions in the proposed settlement is an allowance cap calculation. Montaup may meet its allowance caps by any combination of control technologies, fuel switching, operational changes, and/or the use of purchased or surplus allowances. The settlement was approved by FERC on December 19, 1997. In April 1992, the Northeast States for Coordinated Air Use Management (NESCAUM), an environmental advisory group for eight northeast states including Massachusetts and Rhode Island, issued recommendations for NOx controls for existing utility boilers required to meet the ozone non-attainment requirements of the Clean Air Act. The NESCAUM recommendations are more restrictive than the Clean Air Act requirements. The Massachusetts Department of Environmental Management has amended its regulations to require that Reasonably Available Control Technology (RACT) be implemented at all stationary sources potentially emitting 50 tons or more per year of NOx. Similar regulations have been issued in Rhode Island. Montaup has initiated compliance, through, among other things, selective noncatalytic reduction processes. See Note A regarding EUA's planned divestiture of generation assets. A number of scientific studies in the past several years have examined the possibility of health effects from EMF that are found wherever there is electricity. While some of the studies have indicated some association between exposure to EMF and health effects, many others have indicated no direct association. Some states have enacted regulations to limit the strength of magnetic fields at the edge of transmission line rights-of-way. Rhode Island has enacted a statute which authorizes and directs the Energy Facility Siting Board to establish rules and regulations governing construction of high voltage transmission lines of 69 kv or more. Management cannot predict the ultimate outcome of the EMF issue. Guarantee of Financial Obligations: EUA has guaranteed or entered into equity maintenance agreements in connection with certain obligations of its subsidiaries. EUA has guaranteed the repayment of EUA Cogenex's $24.5 million, 10.56% unsecured long-term notes due 2005 and EUA Ocean State's $26.1 million, 9.59% unsecured long-term notes due 2011. In addition, EUA has entered into equity maintenance agreements in connection with the issuance of EUA Service's 10.2% Secured Notes and EUA Cogenex's 9.6% Unsecured Notes. Under the December 1992 settlement agreement with EUA Power, EUA reaffirmed its guarantee of up to $10 million of EUA Power's share of the decommissioning costs of Seabrook I and any costs of cancellation of Seabrook I or Seabrook II. EUA guaranteed this obligation in 1990 in order to secure the release to EUA Power of a $10 million fund established by EUA Power at the time EUA Power acquired its Seabrook interest. EUA has not provided a reserve for this guarantee because management believes it unlikely that EUA will ever be required to honor the guarantee. Montaup is a 3.27% equity participant in two companies which own and operate transmission facilities interconnecting New England and the Hydro Quebec system in Canada. Montaup has guaranteed approximately $4.1 million of the outstanding debt of these two companies. In addition, Montaup and Newport have minimum rental commitments which total approximately $11.2 million and $1.4 million, respectively, under a noncancelable transmission facilities support agreement for years subsequent to 1998. Other: Since early 1997, fourteen plaintiffs brought suits against numerous defendants, including EUA, for injuries and illness allegedly caused by exposure to asbestos over approximately a thirty-year period, at premises, including some owned by EUA companies. The total damages claimed in all of these complaints was $34 million in compensatory and punitive damages, plus exemplary damages and interest and costs. Each complaint names between fifteen and twenty-eight defendants, including EUA. These complaints have been referred to the applicable insurance companies. Counsel has been retained by the insurers and is actively defending all cases. Four cases have been dismissed as against the EUA Companies. EUA cannot predict the ultimate outcome of this matter at this time. A pending class action, filed on March 2, 1998, in the Massachusetts Supreme Judicial Court naming all Massachusetts electric distribution companies, including Eastern Edison, and certain Massachusetts state agencies as defendants, seeks to invalidate certain sections of the Electric Utility Restructuring Act of 1997. The Act directs the Massachusetts Department of Telecommunications and Energy to impose mandatory charges on all electricity sold to customers, except those served by a municipal lighting plant, to fund energy efficiency activities and to promote renewable energy projects. In addition to declaratory judgment, plaintiffs seek remittance of monies paid to each distribution company by customers along with any interest earned. The outcome of this class action is unknown at this time however, Eastern Edison is vigorously defending the lawsuit. Cogenex Settlement - EUA Cogenex recorded an after-tax charge of $2.1 million to earnings related to an arbitration panel's decision in a matter involving the 1995 sale of a portfolio of cogeneration units by EUA Cogenex to Ridgewood/Mass Power Partners, et al (Ridgewood). Ridgewood claimed that financial and other warranties in the purchase and sale agreement had been breached. EUA Cogenex entered counterclaims seeking recovery of costs of certain services performed for Ridgewood. The arbitration panel found for the buyer on some of the warranty claims, and awarded damages of approximately $2.6 million plus interest. EUA Cogenex was awarded approximately $400,000 plus interest on its counterclaim. EUA Cogenex paid the arbitration panel's net award less interest and recorded this charge to earnings during the fourth quarter of 1998. EUA Cogenex continues to contest the panel's findings with respect to the interest and legal fees. Termination of Power Marketing Joint Venture - In the third quarter of 1997, EUA announced the termination of a power marketing joint venture with an affiliate of Duke Energy Corporation, the establishment of contingency reserves related to certain of its energy-related business activities and other expenses. Collectively, these actions resulted in a net after-tax gain of $1.5 million in third quarter 1997 earnings. The gross pre-tax gain related to the joint venture termination was $6.6 million. The gain was offset by contingency reserves for EUA's non-core business operations, industry restructuring matters, the Millstone 3 outage, interest and insurance aggregating $4.4 million. Also, EUA recorded expenses of $200,000 related to industry restructuring efforts. Report of Independent Accountants To the Trustees and Shareholders of Eastern Utilities Associates In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of equity capital and preferred stock and indebtedness present fairly, in all material respects, the financial position of Eastern Utilities Associates (the Company) and its subsidiaries at December 31, 1998 and 1997, and their consolidated statements of income, retained earnings and cash flows present fairly their results of operations and cash flows for each of the three years in the period ended December 31, 1998, in conformity with generally accepted accounting principles. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with generally accepted auditing standards which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above. PricewaterhouseCoopers LLP Boston, Massachusetts March 5, 1999 Report of Management The management of Eastern Utilities Associates is responsible for the consolidated financial statements and related information included in this annual report. The financial statements are prepared in accordance with generally accepted accounting principles and include amounts based on the best estimates and judgments of management, giving appropriate consideration to materiality. Financial information included elsewhere in this annual report is consistent with the financial statements. The EUA System maintains an accounting system and related internal controls which are designed to provide reasonable assurances as to the reliability of financial records and the protection of assets. The System's staff of internal auditors conducts reviews to maintain the effectiveness of internal control procedures. PricewaterhouseCoopers LLP an independent accounting firm, is engaged by EUA to audit and express an opinion on our financial statements. Their audit includes a review of internal controls to the extent required by generally accepted auditing standards for such audit. The Audit Committee of the Board of Trustees, which consists solely of outside Trustees, meets with management, internal auditors and PricewaterhouseCoopers LLP to discuss auditing, internal controls and financial reporting matters. The internal auditors and PricewaterhouseCoopers LLP have free access to the Audit Committee without management present. Quarterly Financial and Common Share Information (unaudited) ($ in thousands except per Share and Share Price Amounts)
Basic and Diluted Earnings Dividends Common Share Consolidated per Average Paid per Market Price Operating Operating Net Net Common Common Revenues Income Income Earnings Share Share High Low FOR THE QUARTERS ENDED 1998: December 31 $133,416 $15,153 $9,085 $8,509 $0.42 $0.415 28 1/4 24 5/8 September 30 136,033 15,461 9,788 9,212 0.45 0.415 26 15/16 24 5/16 June 30 130,046 12,531 6,449 5,872 0.29 0.415 27 3/8 24 7/16 March 31 139,306 18,492 11,693 11,117 0.54 0.415 27 11/16 23 11/16 FOR THE QUARTERS ENDED 1997: December 31 $145,878 $15,378 $11,158 $10,582 $0.52 $0.415 26 5/8 20 1/8 September 30 142,026 15,896 11,542 10,966 0.54 0.415 19 15/16 18 7/16 June 30 138,856 11,327 6,510 5,933 0.29 0.415 18 1/2 16 3/8 March 31 141,753 16,206 11,055 10,479 0.51 0.415 19 5/8 17 1/4
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