-----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, LE+TK3Cwqupy18EYLoqkw2A6TnbZd+KNa1HSTyqqb0GkUD7IugvZ7mEd4HPx7hXQ dVP9BuNYezWcnVBKMVVvbw== 0000031224-97-000022.txt : 19970327 0000031224-97-000022.hdr.sgml : 19970327 ACCESSION NUMBER: 0000031224-97-000022 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 14 CONFORMED PERIOD OF REPORT: 19961231 FILED AS OF DATE: 19970321 DATE AS OF CHANGE: 19970326 SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: EASTERN UTILITIES ASSOCIATES CENTRAL INDEX KEY: 0000031224 STANDARD INDUSTRIAL CLASSIFICATION: 4911 IRS NUMBER: 041271872 STATE OF INCORPORATION: MA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K405 SEC ACT: 1934 Act SEC FILE NUMBER: 001-05366 FILM NUMBER: 97560772 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: 4911 IRS NUMBER: 050108587 STATE OF INCORPORATION: RI FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K405 SEC ACT: 1934 Act SEC FILE NUMBER: 000-02602 FILM NUMBER: 97560773 BUSINESS ADDRESS: STREET 1: WASHINGTON HWY STREET 2: P O BOX 111 CITY: LINCOLN STATE: RI ZIP: 02865 BUSINESS PHONE: 617-352-9590 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: 4911 IRS NUMBER: 041123095 STATE OF INCORPORATION: MA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K405 SEC ACT: 1934 Act SEC FILE NUMBER: 000-08480 FILM NUMBER: 97560774 BUSINESS ADDRESS: STREET 1: 110 MULBERRY ST CITY: BROCKTON STATE: MA ZIP: 02403 BUSINESS PHONE: 5085801213 MAIL ADDRESS: STREET 1: 110 MULBERRY STREET CITY: BOSTON STATE: MA ZIP: 02403 FORMER COMPANY: FORMER CONFORMED NAME: BROCKTON EDISON CO DATE OF NAME CHANGE: 19790729 10-K405 1 EUA, BVE AND EECO 1996 10-K SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 Form 10-K (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, 1996 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) Washington Highway Lincoln, Rhode Island 02865 Telephone (401) 333-1400 0-8480 Eastern Edison Company 04-1123095 (A Massachusetts Corporation) 110 Mulberry Street Brockton, Massachusetts 02403 Telephone (508) 580-1213 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 17, 1997: Eastern Utilities Associates Common Shares, $5 par value - $370,402,446 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 17, 1997: 20,435,997 Blackstone Valley Electric Company Common Shares Outstanding at March 17, 1997: 184,062 Eastern Edison Company Common Shares Outstanding at March 17, 1997: 2,891,357 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, 1996, are incorporated by reference into Part II. Portions of the Eastern Utilities Associates Proxy Statement dated March 26, 1997 are incorporated by reference into Part III. EASTERN UTILITIES ASSOCIATES BLACKSTONE VALLEY ELECTRIC COMPANY EASTERN EDISON COMPANY 1996 Annual Report on Form 10-K Table of Contents Table of Contents. . . . . . . . . . . . . . . . . . . . . . . .I GLOSSARY OF DEFINED TERMS. . . . . . . . . . . . . . . . . . . IV PART I Item 1. BUSINESS . . . . . . . . . . . . . . . . . . . . . . .1 System Overview . . . . . . . . . . . . . . . . . . . . . .1 General - Core Electric Business. . . . . . . . . . . . . .1 Electric Utility Industry Restructuring . . . . . . . . . .5 Unbundled Services . . . . . . . . . . . . . . . . . .5 Stranded Costs . . . . . . . . . . . . . . . . . . . .5 Rhode Island Utility Restructuring Act of 1996 . . . .5 Massachusetts Restructuring Settlement . . . . . . . .6 Other. . . . . . . . . . . . . . . . . . . . . . . . .8 General - EUA Cogenex . . . . . . . . . . . . . . . . . . .8 Construction . . . . . . . . . . . . . . . . . . . . . . 11 Construction Program - EUA:. . . . . . . . . . . . . 11 Construction Program - Blackstone. . . . . . . . . . 11 Construction Program - Eastern Edison. . . . . . . . 12 Fuel for Generation . . . . . . . . . . . . . . . . . . . 12 Nuclear Power Issues . . . . . . . . . . . . . . . . . . 14 General . . . . . . . . . . . . . . . . . . . . . . 14 Decommissioning. . . . . . . . . . . . . . . . . . . 15 Yankee Atomic. . . . . . . . . . . . . . . . . . . . 16 Connecticut Yankee . . . . . . . . . . . . . . . . . 16 Recent NRC Actions . . . . . . . . . . . . . . . . . 16 Millstone III . . . . . . . . . . . . . . . . . 16 Maine Yankee. . . . . . . . . . . . . . . . . . 17 General . . . . . . . . . . . . . . . . . . . . 18 Public Utility Regulation . . . . . . . . . . . . . . . . 18 Rates . . . . . . . . . . . . . . . . . . . . . . . . . 20 FERC Proceedings . . . . . . . . . . . . . . . . . . 22 Massachusetts Proceedings. . . . . . . . . . . . . . 22 Rhode Island Proceedings . . . . . . . . . . . . . . 24 Environmental Regulation . . . . . . . . . . . . . . . . 27 General. . . . . . . . . . . . . . . . . . . . . . . 27 Electric and Magnetic Fields . . . . . . . . . . . . 28 Water Regulation . . . . . . . . . . . . . . . . . . 28 Air Regulation . . . . . . . . . . . . . . . . . . . 29 Environmental Regulation of Nuclear Power . . . . . . . . 31 Item 2. PROPERTIES . . . . . . . . . . . . . . . . . . . . . 32 Power Supply . . . . . . . . . . . . . . . . . . . . . . 32 Other Property. . . . . . . . . . . . . . . . . . . . . . 34 Item 3. LEGAL PROCEEDINGS. . . . . . . . . . . . . . . . . . 34 Rate Proceeding . . . . . . . . . . . . . . . . . . . . . 34 Environmental Proceedings . . . . . . . . . . . . . . . . 35 EUA WestCoast L.P.. . . . . . . . . . . . . . . . . . . . 38 Ridgewood . . . . . . . . . . . . . . . . . . . . . . . . 39 Other Proceedings . . . . . . . . . . . . . . . . . . . . 39 Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY-HOLDERS. 40 Executive Officers of Eastern Utilities Associates . . . 40 PART II Item 5. MARKET FOR EUA'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS. . . . . . . . . . . . . . . . . . . . . . . 41 Item 6. SELECTED FINANCIAL DATA. . . . . . . . . . . . . . . 42 Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS . . . . . . . . .42 Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. . . . . 42 Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES . . . . . . . .42 PART III Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS Eastern Utilities Associates . . . . . . . . . . . . . . .42 Blackstone and Eastern Edison. . . . . . . . . . . . . . .43 Item 11. EXECUTIVE COMPENSATION . . . . . . . . . . . . . . . 44 Eastern Utilities Associates . . . . . . . . . . . . . . .44 Blackstone and Eastern Edison. . . . . . . . . . . . . . .45 Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT . . . . . . . . . . . . . . . . . . . . . 45 Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS . . . 45 PART IV Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K . . . . . . . . . . . . . . . . . . . . . .46 (a)(1) Financial Statements . . . . . . . . . . . . . . .46 (a)(2) Financial Statement Schedules . . . . . . . . . . .46 (a)(3) Exhibits (*denotes filed herewith). . . . . . . . .46 (b) Reports on Form 8-K. . . . . . . . . . . . . . . . .60 Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . 61 Report of Independent Accountants . . . . . . . . . . . . . . 70 Consent of Independent Accountants . . . . . . . . . . . . . . 72 GLOSSARY OF DEFINED TERMS The following is a glossary of frequently used abbreviations and/or acronyms found throughout this report: The EUA System Companies Blackstone Blackstone Valley Electric Company Eastern Edison Eastern Edison Company EUA Eastern Utilities Associates EUA Cogenex EUA Cogenex Corporation EUA Day EUA Day Company, a division of EUA Cogenex EUA Nova EUA Nova, a division of EUA Cogenex EUA Energy EUA Energy Investment Corporation EUA Ocean State EUA Ocean State Corporation EUA Service EUA Service Corporation EUA Energy Services EUA Energy Services Corporation Montaup Montaup Electric Company Newport Newport Electric Corporation Registrants EUA, Blackstone and Eastern Edison Retail Subsidiaries Blackstone, Eastern Edison and Newport Non-Affiliated Companies Great Bay Power Great Bay Power Corporation (formerly EUA Power Corporation) Maine Yankee Maine Yankee Atomic Power Company OSP Ocean State Power Project Units 1 and 2 Yankee Atomic Yankee Atomic Electric Company Regulators/Regulations 1935 Act Public Utility Holding Company Act of 1935 CERCLA Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 Chapter 21E Massachusetts Oil and Hazardous Material Release Prevention and Response Act Clean Air Act Amendments Clean Air Act Amendments of 1990 DEQE Massachusetts Department of Environmental Quality Engineering GLOSSARY OF DEFINED TERMS (Cont'd) Regulators/Regulations (continued) DOE Department of Energy Energy Policy Act Energy Policy Act of 1992 EPA Federal Environmental Protection Agency FAS106 Statement No. 106 "Employer's Accounting for Post-Retirement Benefits Other Than Pensions" FERC Federal Energy Regulatory Commission IRS Internal Revenue Service MADEP Massachusetts Department of Environmental Protection MDPU Massachusetts Department of Public Utilities NESCAUM Northeast States for Coordinated Air Use Management NRC Nuclear Regulatory Commission NWPA Nuclear Waste Policy Act Price-Anderson Act The Price-Anderson Act, as amended by the Price-Anderson Amendments of 1988 PURPA Public Utility Regulatory Policies Act of 1978 RCRA Resource Conservation and Recovery Act of 1976 RIDEM Rhode Island Department of Environmental Management RIDPUC Rhode Island Division of Public Utilities and Carriers RIPUC Rhode Island Public Utilities Commission SEC Securities and Exchange Commission TEC-RI The Energy Counsel of Rhode Island TSCA Toxic Substances Control Act Other AFUDC Allowance for Funds Used During Construction BTU British Thermal Unit C&LM Conservation and Load Management DSM Demand Side Management EMF Electric and Magnetic Fields EWG Exempt Wholesale Generator IPP Independent Power Producer GLOSSARY OF DEFINED TERMS (Cont'd) Other (continued) kWh Kilowatthour MBTU Millions of British Thermal Units MOU Memorandum of Understanding mw Megawatt NEPOOL New England Power Pool PCB Polychlorinated Biphenyls PRP Potentially Responsible Party QF Qualifying cogeneration and small power production facilities pursuant to PURPA Seabrook Project Seabrook Nuclear Power Project located in Seabrook, New Hampshire PART I Item 1. BUSINESS System Overview Eastern Utilities Associates is a Massachusetts voluntary association organized and existing under a Declaration of Trust dated April 2, 1928, as amended, and is a registered holding company under the 1935 Act. Blackstone, a registered retail electric utility organized under the laws of the State of Rhode Island in 1912 operates in northern Rhode Island. Eastern Edison, a registered retail electric utility company, was organized under the laws of the Commonwealth of Massachusetts in 1883 and operates in southeastern Massachusetts. EUA owns directly all of the shares of common stock of Blackstone, Eastern Edison, and Newport, a retail electric utility which operates in south coastal Rhode Island. These subsidiaries are collectively referred to as the Retail Subsidiaries. Eastern Edison owns all of the permanent securities of Montaup, a generation and transmission company, which supplies electricity to Eastern Edison, Blackstone, Newport and two unaffiliated utilities for resale. EUA also owns directly all of the shares of common stock of EUA Cogenex, EUA Energy, EUA Ocean State, EUA Energy Services and EUA Service. EUA Service provides various accounting, financial, engineering, planning, data processing and other services to all EUA System companies. EUA Cogenex is an energy services company. EUA Energy invests in energy-related projects. EUA Ocean State owns a 29.9% interest in OSP's two gas-fired generating units. (See Item 2. PROPERTIES -- Power Supply.) EUA Energy Services owns an interest in a limited liability company which markets energy and energy related services. The holding company system of EUA, the Retail Subsidiaries, Montaup, EUA Service, EUA Cogenex, EUA Energy, EUA Ocean State and EUA Energy Services is referred to as the EUA System. The EUA System is organized into a business unit structure. The Core Electric Business consists of the Retail Subsidiaries and Montaup. The Energy Related Business includes EUA Cogenex, EUA Energy, EUA Ocean State and EUA Energy Services. The Corporate Business is made up of EUA and EUA Service. General - Core Electric Business As of December 31, 1996, the number of regular employees in the core electric and corporate business units was 1,032. Blackstone had 106 regular non-union employees. Eastern Edison and Montaup had 303 regular employees. Newport and EUA Service employed 59 and 564, respectively, at December 31, 1996. Labor bargaining unit contracts covering approximately 142 employees of Eastern Edison in the Fall River area and of Montaup, and 55 employees of Newport expire in June 1997, March 1998 and September 1998, respectively. Relations with employees are considered to be satisfactory. The Core Electric Business supplies retail electric service in 33 cities and towns in southeastern Massachusetts and Rhode Island. The largest communities served are the cities of Brockton and Fall River, Massachusetts. The retail electric service territory covers approximately 595 square miles and has an estimated population of approximately 734,000. At December 31, 1996, Core Electric Business served approximately 299,000 retail customers. Blackstone serves a territory of about 150 square miles in portions of northern Rhode Island with a population of approximately 207,000. At December 31, 1996, Blackstone furnished retail electric service to approximately 85,000 customers in the cities of Central Falls, Pawtucket and Woonsocket, and four surrounding towns. Eastern Edison supplies retail electric service in 22 cities and towns in southeastern Massachusetts. The largest communities served are the cities of Brockton and Fall River, Massachusetts. The retail electric service territory covers approximately 390 square miles and has an estimated population of approximately 459,000. At December 31, 1996, Eastern Edison served approximately 182,000 retail customers. Newport supplies retail electric service to approximately 33,000 customers in the cities of Jamestown, Middletown, Newport, and Portsmouth, Rhode Island. The retail electric service territory covers approximately 55 square miles and has an estimated population of approximately 69,000. For 1996, 1995 and 1994, the Core Electric Business accounted for approximately 89%, 86% and 87%, respectively, of total operating revenues of the EUA System. The remaining balance of operating revenues during these periods were primarily attributable to EUA Cogenex. Montaup currently supplies the Retail Subsidiaries with nearly 100% of each company's electric requirement under FERC approved all-requirements contracts. It is anticipated, subject to regulatory approval, that Montaup will replace the all-requirements contract with a contract termination agreement that would provide Montaup recovery of its stranded costs (see Electric Utility Industry Restructuring below). About 48% of the net generating capacity of the EUA System comes from a combination of the following sources: (i) wholly owned EUA System generating plants, primarily Montaup's 154 mw Somerset facility located in Somerset, Massachusetts; (ii) Montaup's net entitlement of 243 mw from the 586 mw Canal No. 2 unit, which is located in Sandwich, Massachusetts and is 50% owned by Montaup; and, (iii) entitlements from units in which Montaup has partial ownership interests (by joint ownership through tenancy-in-common or by stock ownership) that are 4.5% or less. The remaining 52% of the net generating capacity of the EUA System comes from units in which Montaup has long-term or short-term power contracts for shares ranging from 5.1% to 41.7% of the unit's capacity, including 28% of the OSP Units 1 and 2 in which EUA Ocean State has a 29.9% partnership interest, or entitlements from the Hydro-Quebec Project through NEPOOL. (See Item 2. PROPERTIES -- Power Supply for further details of the EUA System's sources of power supply). The Retail Subsidiaries and Montaup hold valid franchises, permits and other rights which are necessary to allow these companies to conduct electric business within the territories which they serve. Such franchises, permits and other rights contain no unduly burdensome restrictions or limitations upon duration. The EUA System's electric sales are seasonal to some extent due to electricity usage for heating and lighting in the winter and air conditioning in the summer. The EUA System is not dependent on a single customer or a few customers for its electric sales. There is no competition from other electric distribution utilities within the retail territories served by the Retail Subsidiaries at this time. See Electric Utility Industry Restructuring below for a discussion of emerging competition and unbundling issues. At the wholesale, or supply level, Montaup faces new sources of competition in part as a result of PURPA, the Energy Policy Act and other policies being implemented by the MDPU and considered by the RIPUC relating to the solicitation of competitive proposals for new generation sources. Non- utility wholesale generators, generally known as independent power producers or IPPs, are subject to FERC regulations under the Federal Power Act as well as various other federal, state, and local regulations. PURPA was intended, among other things, to promote national energy independence and diversification of energy supply and to improve the overall efficiency of energy usage. PURPA created a class of non-utility power generation facilities called qualifying facilities or QFs. PURPA allows QFs to sell power generated by the QFs to local utilities at specified rates based on each utility's avoided cost. In order to further promote competition in energy supply, the Energy Policy Act established another class of non-utility generators, generally referred to as EWGs, which are exempt from the 1935 Act. The Energy Policy Act also increased FERC's power to order transmission access, resulting in FERC's open access transmission order and Regional Transmission Group Policy. As a complement to the federal initiatives, the MDPU and the RIPUC have implemented regulations which require utilities to integrate least-cost planning with competitive proposals to meet requirements for new generation. Both states have also approved a Memorandum of Understanding among Montaup and the Retail Subsidiaries that establishes a framework which makes possible a coordinated, regional review of the resource planning and procurement process of the EUA System Companies. (see Public Utility Regulation below). On April 24, 1996, FERC issued orders on its March 24, 1995 Notice of Proposed Rulemaking (NOPR). FERC's purpose in proposing the new rules was to encourage competition in the bulk power market. FERC's April 24th actions include: - order No. 888, a final rule requiring open access transmission and requiring all public utilities that own, operate or control interstate transmission to file tariffs that offer others the same transmission services they provide themselves, under comparable terms and conditions. Utilities must take transmission service for their own wholesale transactions under the terms and conditions of the tariff; - establishing the right and a mechanism for recovery of prudently incurred stranded costs by public utilities and transmitting utilities; which arise as a result of wholesale open access; - order No. 889, a final rule requiring public utilities to implement standards of conduct and an Open Access Same-time Information System (OASIS). Utilities must obtain information about their transmission the same way as their competitors through the OASIS; - a Notice of Proposed Rulemaking (NOPR) requesting comment on replacing the single tariff contained in the final open access rule with a capacity reservation tariff that would reveal how much transmission is available at any given time. Open-access transmission tariffs for point-to-point and network service were filed with FERC by Montaup in February 1996 and became effective April 21, 1996, subject to refund, for a period of at least one year. The rates in the tariffs were the subject of a settlement agreement which was filed on June 14, 1996 and remains pending before the Commission. Montaup amended its filing in July 1996 to modify its terms and conditions in conformance with FERC's order. FERC has taken no action on these filings. These tariffs are in compliance with FERC's April 24th rulings. EUA remains committed to achieving a fair and equitable transition to a competitive electric utility marketplace. Montaup will face increased competition in the wholesale generating, or supply market, primarily based on price, from QFs and EWGs and in the future could be affected by such competition supplying generation to its customers. More recently, non-utility power marketers have become active, engaging in new and creative power transactions. Power marketers are likely to become more prevalent in the market as transmission access opens up and opportunities arise, due to price differentials, to move power inter-regionally. See Electric Utility Industry Restructuring, "Rhode Island Utility Restructuring Act of 1996" and "Massachusetts Restructuring Settlement" for a discussion of divestiture plans of Montaup. The EUA System companies are members of NEPOOL, which is open to any person or organization engaged in the electric utility business such as investor-owned, municipal, and cooperative utilities as well as non-utilities and others such as brokers and marketers. The systems making up NEPOOL own or purchase the output from virtually all the generation in New England. Since the EUA System operates an integrated transmission system which, in turn, is connected to the New England 345 kv grid at three locations, NEPOOL treats the EUA System as one consolidated participant. This is consistent with the EUA System's planning and resource management perspective. The objectives of NEPOOL are: (a) to assure that the bulk power supply of New England and any adjoining areas served by participants conforms to proper standards of reliability, and (b) to attain maximum practicable economy in the bulk power supply consistent with all proper standards of reliability and to provide for equitable sharing of the resulting benefits and costs. These objectives are accomplished through joint planning, central dispatching, coordinated construction, operation, and maintenance of electric generation and transmission facilities, cooperation in environmental matters, and through effective coordination with other power pools and utilities situated in the United States and Canada. The NEPOOL agreement imposes obligations concerning generating capacity reserve and the right to use major transmission lines, and provides for central dispatch of the generating capacity of NEPOOL's members with the objective of achieving reliable and economical use of the region's facilities. Pursuant to the NEPOOL agreement, interchange sales to NEPOOL are made at a price approximately equal to the fuel cost for generation without contribution to the support of fixed charges. The capacity responsibilities of Montaup and the Retail Subsidiaries under the NEPOOL agreement are based on an allocated share of a New England capacity requirement which is determined for each period on the basis of certain regional reliability criteria. Because of its participation in NEPOOL, the EUA System's operating revenues and costs are affected to some extent by the operations of other members. A comprehensive review of the NEPOOL agreement was initiated in 1994 and continued until late 1996. On December 31, 1996 a restated NEPOOL agreement was filed with the FERC. The new agreement implements key changes in the operation of NEPOOL. The major areas of change are in the formation of an Independent System Operator (ISO) and in the shifting from cost-based pricing to market-based pricing. As proposed in the new agreement, NEPOOL participants will be able to compete for sale and purchase of seven products: (1) installed capability, (2) operable capability, (3) energy, (4) 10-minute spinning reserve, (5) 10-minute non-spinning reserve, (6) 30-minute operating reserve, and (7) automatic generation control. If approved by the FERC, competition for all seven products could begin by July 1, 1997. Electric Utility Industry Restructuring: Unbundled Services: The electric industry is in a period of transition from a traditional rate regulated environment to a competitive marketplace. Initiatives supported by EUA in both Massachusetts and Rhode Island provide for the functional and corporate unbundling of traditional electric utility services - generation, transmission and distribution - into separate and distinct services. The generation, or supply function will be truly competitive with customers choosing their own electricity supplier at open market prices. The transmission and distribution functions will remain regulated services. The local distribution company will retain the responsibility of providing distribution services to the ultimate electricity consumer within its franchised service territory and the transmission company will be required to provide open access, non-discriminatory transmission services to generation or supply companies. For customers who choose not to choose, the local distribution company will arrange for supply at a non-discriminatory, "standard offer" price. Distribution companies will also be providers of last resort, required to arrange for supply, at prevailing market prices, for customers who are unable to obtain a supplier of electricity. Stranded Costs: "Stranded costs" represent historic costs of generation above their current economic value. In both Massachusetts and Rhode Island (see discussions below) "stranded costs" have been defined to include items such as above market net investments in generation assets, generation related regulatory assets, nuclear decommissioning and above market commitments under current power purchase contracts. It is anticipated that Montaup, the EUA System's generation company, will fully recover its "stranded costs" via a contract termination charge under a contract termination agreement which will replace the all-requirements contracts currently in force. Rhode Island Utility Restructuring Act of 1996: On August 7, 1996 the Governor of Rhode Island signed into law the Utility Restructuring Act of 1996 (URA). The URA provides for customer choice of electricity supplier commencing July 1, 1997 for large manufacturing customers, certain new commercial and industrial customers, and State of Rhode Island accounts. Load accounting for no more than 10% of an electric distribution company's total kWh sales is to be released to retail access under this provision. An additional 10% of kWh sales is to be released to retail access by permitting municipal and smaller manufacturers to choose an electricity supplier commencing January 1, 1998. By July 1, 1998 or sooner, all customers will have retail access. This legislation provides for full recovery of "stranded costs" billed to distribution companies - Blackstone and Newport in the case of EUA - via a non-bypassable transition charge to ultimate electricity consumers, initially set at 2.8 cents per kWh through December 31, 2000 and divestiture of at least 15% of owned non-nuclear generating units as a valuation basis for mitigation of stranded cost recovery. The net costs of above-market generation assets and regulatory assets will be recovered, with a return, through the fixed component of the transition charge from July 1, 1997 through December 31, 2009. The initial return on equity will be set at one percentage point plus the average return on BBB rated long term utility bonds issued during the six month period ended December 31, 1996. Upon completion of required divestiture, the return on equity will be that allowed to the wholesale power supplier's affiliated distribution company as of December 31, 1995, which is approximately 11.4% for both Blackstone and Newport. The variable component of the transition charge will recover, on a reconciling basis, among other things, nuclear decommissioning and above market purchased power commitments from July 1, 1997 through the life of the respective unit or contract. The URA also provides for, among other things, commitments to demand side management initiatives and renewables, low income customer protections and performance based regulation for electric distribution companies. Under performance based regulation, rates are set for a specified period - two years, under the URA - during which the utility is encouraged to manage its costs prudently to earn a premium profit while being penalized for not achieving specific agreed-upon regulated performance objectives. Utility returns, or earnings, would be subject to a guaranteed floor of 6% and a ceiling of approximately 12% for Blackstone and Newport. Utilities which manage well can keep some of their savings; those that manage poorly are penalized by lower earnings and/or pre-determined penalty charges. The implementation of the URA will require approvals from applicable regulatory agencies, including FERC, the RIPUC, and the SEC. EUA believes that the URA settles much of the uncertainty regarding "stranded cost" recovery related to serving the customers of Blackstone and Newport. In February 1997, Blackstone , Newport and Montaup reached a settlement with the RIDPUC and the Rhode Island Attorney General. The settlement, to be formally submitted to the RIPUC in March 1997, complies with the URA and is similar in many respects to the settlement negotiated in Massachusetts, described below, including an immediate 10% rate reduction and the filing of a plan to divest all of Montaup's generating assets. Massachusetts Restructuring Settlement: On December 23, 1996, Eastern Edison and Montaup Electric reached an agreement in principle with the Attorney General of Massachusetts and the Massachusetts Division of Energy Resources on a plan which would allow retail customers to choose their supplier of electricity in 1998 and provide Eastern Edison and Montaup full recovery of "stranded costs," which are prudently incurred embedded costs they would have been entitled to recover but cannot because of competitive market pressures. A formal plan is expected to be filed for approval with the MDPU in March of 1997. The agreement envisions that all of Eastern Edison's customers will have the ability to choose an alternative supplier of electricity beginning on January 1, 1998. Until a customer chooses an alternative supplier, that customer would receive "Standard Offer" service which would be priced to guarantee that customer at least a ten percent savings from today's electricity prices. Eastern Edison would be required to arrange for "Standard Offer" service and would purchase power for "Standard Offer" service from suppliers through a competitive bidding process. The agreement is also designed to achieve full divestiture of Montaup's generating assets via implementation of a plan, to be submitted to the MDPU by July 1, 1997, that would require (1) separation by Montaup of its generating and transmission businesses and (2) full market valuation and sale of all generating assets through an auction or equivalent process, to be conducted by an independent third party. Upon the commencement of retail choice in Massachusetts, Montaup's wholesale contract with Eastern Edison would be terminated. In return, the cost of Montaup's above market, embedded generation commitments to serve Eastern Edison's customers would be recovered, with a return, through a non- bypassable transition access charge to all Eastern Edison customers. The transition access charge would be reduced by the fair market value of Montaup's generating assets as determined by selling, spinning off, or otherwise disposing of such generating facilities. Embedded costs associated with generating plants and regulatory assets would be recovered, with a return, over a period of 12 years, with an initial return on equity of 8.92 percent. Purchased power contracts and nuclear decommissioning costs would be recovered as incurred over the life of those obligations, a period expected to extend beyond 12 years. The initial transition access charge would be set at 3.04 cents per kWh through December 31, 2000, and is expected to decline thereafter. As the transition access charge declines during the twelve-year transition period, Montaup would earn mitigation incentives in the form of additional cash revenues which would effectively increase its return on equity above the initial 8.92 percent. The agreement also establishes performance-based regulation for Eastern Edison. Under the agreement, Eastern Edison's distribution rates would be frozen until December 31, 2000. Subsequent to the commencement of retail choice, Eastern Edison's annual return on equity would be subject to a floor of 6 percent and a ceiling of 11.75 percent. If Eastern Edison's return on equity so calculated is below 6 percent, it would be authorized to increase its rates to provide sufficient revenues to increase Eastern Edison's return on equity to 6 percent. If Eastern Edison's calculated return is above 11 percent, it would be required to reduce its rates by an amount necessary to reduce its calculated return on equity between 11 and 12.5 percent by 50 percent and the earnings above 12.5 percent by 100 percent. No adjustment would be made if the calculated return on equity falls between 6 percent and 11 percent. In addition to MDPU approval of the formal plan, implementation of the plan is also subject to the approval of FERC. Any disposition of generation assets would also require the approval of the SEC under the 1935 Act. While removing much of the uncertainty about how EUA will be impacted by Electric Utility Restructuring, the agreements, if approved, are expected to have an estimated negative impact on EUA System earnings in 1998 of between 10% to 12%. Other: Historically, electric rates have been designed to recover a utility's full costs of providing electric service including recovery of investment in plant assets, known as cost-of-service rate making. Also, in a regulated environment, electric utilities are subject to certain accounting rules that are not applicable to other industries. These accounting rules allow regulated companies, in appropriate circumstances, to establish regulatory assets and liabilities, which defer the current financial impact of certain costs that are expected to be recovered in future rates. The SEC has raised issues concerning the continued applicability of these standards with certain other electric utilities in other states facing restructuring. EUA believes that its Core Electric operations continue to meet the criteria established in these accounting standards. However, the potential exists that the final outcome of state and federal agency determinations could result in EUA no longer meeting the criteria of certain accounting standards which could trigger the discontinuance of Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation" (FAS71). Should it be required to discontinue the application of FAS71, EUA would be required to take an immediate write down of the affected assets in accordance with FAS101, "Accounting for the Discontinuation of Application of FAS71." In addition, if legislative or regulatory changes and/or competition result in electric rates which do not fully recover the company's costs, a write-down of plant assets could be required pursuant to Financial Accounting Standard No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of" (FAS121) issued in March 1995. 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. Actual results could differ materially from these statements. Therefore, no assurances can be given that such forward-looking statements and estimates will be achieved. General - EUA Cogenex EUA Cogenex is a wholly owned subsidiary of EUA. EUA Cogenex is an energy services company that employs energy efficient technology and equipment intended to reduce the energy consumption and costs of its customers. Such technology and equipment include building automation systems, lighting modifications, boiler and chiller replacements and other mechanical measures such as motors and drives. EUA Cogenex may design, install, own, operate, maintain, and finance specific energy efficient applications for its customers. EUA Cogenex is compensated for these services primarily through energy services agreements in which EUA Cogenex and the customer who occupies or owns a facility agree upon a prescribed base year and a set of savings calculations. EUA Cogenex then receives payments based on a portion of the savings that result from the installation and maintenance of the energy efficient equipment in the facility. Some of EUA Cogenex revenues under these agreements are dependent upon the actual achievement of energy savings. In addition, EUA Cogenex participates in demand side management (DSM) programs sponsored by electric utilities as a means to decrease both base load and peak demand on the utilities' systems. In utility DSM programs, EUA Cogenex contracts with the utility and its commercial and industrial customers in order to decrease the overall demand on the utility system or to reduce peak demand, curtailing the need for costly capacity additions. EUA Cogenex contracts for utility DSM programs through a bidding process or participates in the utility's "Standard Offer Program." EUA Cogenex also may, from time to time, acquire existing DSM contracts or energy services agreements, or the benefits from those contracts from other energy services companies. EUA Cogenex's principal markets include institutional, commercial, industrial and government entities, and through its EUA Citizens Conservation Services subsidiary, public and private multi-family housing. In September 1995, EUA announced that EUA Cogenex was discontinuing its cogeneration operations because overall, the cogeneration portfolio had not performed up to expectations. EUA Cogenex's total net investment in its cogeneration portfolio was $29.2 million. The decision to discontinue its cogeneration operations resulted in a one-time, after-tax charge of approximately $10.5 million, or 52 cents per share, to 1995 earnings. Difficulties in turning project proposals into signed contracts, the virtual elimination of utility sponsored DSM programs and the termination of the AYP Capital and Westar joint ventures hampered EUA Cogenex's 1996 earnings. As a result, a write-off of certain start-up costs of abandoned joint ventures, and expenses related to certain project proposals along with a reduction in carrying value of certain on-going projects necessitated by current market conditions resulted in a $5.9 million pre-tax ($3.7 million after-tax or 18 cents per share) charge to earnings in the second quarter of 1996. In an effort to revitalize its sales activity, EUA Cogenex has replaced virtually all of its sales staff with individuals possessing more experience and proven sales capability in the energy efficiency market. EUA Cogenex also reduced its year-end 1995 employee level by 22% through a combination of attrition and a 1996 year-end workforce reduction. While EUA believes that the energy efficiency market still provides a viable business opportunity for EUA Cogenex, it will be important for EUA Cogenex to improve the performance of its sales activity. EUA Cogenex also operates a lighting services division, EUA Nova, and a controls division, EUA Day. EUA Cogenex restructured its Nova Division in 1996 because of changing market conditions. EUA Nova provides lighting products designed to achieve an efficiency gain through the integration of various lamp, ballast and light reflector products. EUA Day, is primarily engaged in the business of customization, installation and servicing of building temperature control systems, monitoring and verification systems and process control systems for the purpose of energy conservation. These systems are primarily designed for regulating lighting and heating, ventilation and air-conditioning, but can also simultaneously be used for security surveillance, building entry and exit, equipment monitoring and air quality monitoring. EUA Cogenex also provides consulting services to its customers in the form of training in the proper use and maintenance of the energy equipment. This service includes instruction in the use of existing equipment as well as newly installed equipment so that further energy savings can be realized. In addition, EUA Cogenex monitors installed projects on a 24-hour basis and dispatches third party contractors to make repairs and/or adjustments. In 1995, EUA Cogenex acquired certain energy services assets of Citizens Conservation Corporation with headquarters in Boston, Massachusetts in exchange for preferred stock of a newly formed subsidiary of EUA Cogenex, EUA Citizens Conservation Services, which will utilize those assets. EUA Citizens Conservation provides energy conservation services to the public and private multi-family housing sector. EUA Cogenex also acquired the Highland Energy Group, an energy services company in Boulder, Colorado in exchange for common shares of EUA. Highland provides energy conservation services in Colorado, Texas, Ohio, North Carolina and certain mid-western states. In early 1996, EUA Cogenex announced a proposed joint venture with Monenco-Agra of Canada to provide similar services in Canada. At December 31, 1996, EUA Cogenex employed 213 persons in its operations. EUA Cogenex's competition is comprised primarily of the manufacturers and distributors of the energy efficiency equipment which it installs, other utility-owned energy services companies, engineering consulting firms and from financial institutions who provide capital to finance energy efficiency projects. The potential deregulation of the electric utility industry may have an effect on EUA Cogenex. Electric industry deregulation may present new markets and opportunities in which EUA Cogenex may participate. However, some electric utilities have, or announced plans to establish, subsidiaries that will compete directly with EUA Cogenex. In addition, the move toward electric industry deregulation has also resulted in a reduction of electric utility sponsored DSM programs which has resulted in a reduction of EUA Cogenex's revenues. As of December 31, 1996, EUA Cogenex participated in five partnerships. It is the managing general partner in all of the partnerships and has limited partnership interest in certain of the partnerships. EUA Cogenex has provided virtually all of the capital to the partnerships and is generally entitled to a return of, and on, this capital before any significant partnership distribution is made to the other general partners. All partnerships and their customers are subject to the same selection and screening process to establish acceptable credit quality. The rates charged by EUA Cogenex to customers through its energy service agreements are not subject to the jurisdiction of any regulatory agency. The following table sets forth the amounts of revenues, pre-tax income, net earnings and identifiable assets attributable to the consolidated operations of EUA Cogenex: Year Ended December 31, 1996 1995 1994 (In Thousands) Operating Revenues $ 56,317 $ 79,499 $ 74,480 Pre-tax (Loss) Income $(10,186)(1) $(13,885)(2) $ 7,266 Net (Loss) Earnings $ (6,522)(1) $ (7,904)(2) $ 4,171 Total Assets $195,161 $199,115 $ 211,310 (1) Includes pre-tax charge of $5.9 million $3.7 million after-tax, related to the June 1996 write down of certain project costs. (2) Includes pre-tax charge of $18.1 million, $10.5 million after-tax, related to discontinuance of cogeneration operations. See Note I - Financial Information by Business Segment, of Consolidated Financial Statements contained in the EUA's Annual Report to Shareholders for the year ended December 31, 1996 (Exhibit 13-1.03 filed herewith). Construction Construction Program - EUA: The EUA System's cash construction expenditures for the year ended December 31, 1996 were approximately $62.7 million. Planned cash construction expenditures for 1997, 1998 and 1999 as set forth below, are estimated to total $207.6 million. EUA SYSTEM CONSTRUCTION PROGRAM (In Thousands) 1997 1998 1999 3-Yr. Total Generation $ 7,290 $ (a) $ (a) $ 7,290 Transmission 2,002 996 791 3,789 Distribution 14,362 15,143 15,598 45,103 General (177) 445 459 727 Total Utility Construction Requirements 23,477 16,584 16,848 56,909 EUA Cogenex Capital Requirements 34,637 41,500 49,800 125,937 EUA Energy Investment Capital Requirements 15,257 5,219 4,287 24,763 Total $ 73,371 $ 63,303 $ 70,935 $207,609 (a) As discussed under Electric Utility Industry Restructuring "Rhode Island Utility Restructuring Act of 1996" and "Massachusetts Restructuring Settlement," to the extent that Montaup disposes all its generation assets, no capital additions would be required. Construction Program - Blackstone: Blackstone's cash construction expenditures for the year ended December 31, 1996 were approximately $4.2 million, related primarily to its electric distribution system. Planned cash construction expenditures for 1997, 1998 and 1999, as set forth below, are estimated to total $13.1 million. BLACKSTONE CONSTRUCTION PROGRAM (In Thousands) 1997 1998 1999 3-Yr. Total Transmission $ 437 $ 230 $ 237 $ 904 Distribution 3,673 4,098 4,221 11,992 General 48 63 65 176 Total $ 4,158 $4,391 $4,523 $13,072 Construction Program - Eastern Edison: Eastern Edison's cash construction expenditures for the year ended December 31, 1996 were approximately $26.0 million. Cash construction expenditures of Eastern Edison and Montaup for 1997, 1998 and 1999 as set forth below, are estimated to total $36.0 million. EASTERN EDISON CONSTRUCTION PROGRAM (In Thousands)
1997 1998 1999 3-Yr. Total Eastern Eastern Eastern Eastern Edison Montaup Edison Montaup Edison Montaup Edison Montaup Combined Generation $ $7,284 $ $ $ $ $ $7,284 $7,284 Transmission 879 566 408 350 420 125 1,707 1,041 2,748 Distribution 8,792 9,070 9,343 27,205 27,205 General (687) (650) 58 60 (569) (650) (1,219) Total $8,984 $7,200 $ 9,536 $ 350 $ 9,823 $ 125 $28,343 $7,675 $36,018 As discussed under Electric Utility Industry Restructuring "Rhode Island Utility Restructuring Act of 1996" and "Massachusetts Restructuring Settlement," to the extent that Montaup disposes all its generation assets, no capital additions would be required.
Fuel for Generation The Retail Subsidiaries currently rely primarily on power purchased from Montaup to meet their electric energy requirements (See Electric Utility Industry Restructuring above). Power purchases are arranged on a system basis, by Montaup, under which power is made available to the EUA System and allocated to the Retail Subsidiaries in accordance with their peak requirements. The rates charged by Montaup for power sold to the Retail Subsidiaries are those on file with FERC and are substantially the same as those charged by Montaup for power sold to its unaffiliated customers. Changes in the cost to Montaup of power from units in which it has interests are reflected in the cost of power purchased by the Retail Subsidiaries. The Retail Subsidiaries recover their cost of fuel and purchased power through the operation of revenue adjustment clauses which are designed to provide timely recovery of such costs. For 1996, the EUA System's sources of energy, by fuel type, were as follows: 31% gas, 29% nuclear, 20% oil, 15% coal and 5% other. During 1996, Montaup had an average inventory of 56,944 tons of coal for its steam generating unit at the Somerset Station, the equivalent of 68 days' supply (based on average daily output at 80% capacity factor for the coal unit (see Item 2. PROPERTIES -- Power Supply)). The cost of coal averaged about $49.90 per ton in 1996 which is equivalent to oil at $12.16 per barrel. This was the same as 1995. Montaup coal is under contract, and coal prices have historically been very stable. Montaup also maintained an average inventory of Nos. 2 and 6 oil of 2,102 barrels and 45,070 barrels, respectively. These fuels are used for start-up and flame stabilization for Montaup's steam generating unit. The cost of Nos. 2 and 6 oil averaged $22.27 per barrel and $17.19 per barrel in 1996, respectively. Montaup also maintained an average inventory of jet oil of 3,573 barrels at an average cost per barrel of $25.83 during 1996 for its two peaking units at the Somerset Station. Montaup has a two year purchase order effective through December 1998 with a coal producer. Barge and rail agreements for coal transportation are also in place through 1998. The 1996 year-end coal inventory of approximately 82,000 tons is all 0.6% to 0.7% sulfur coal which is compliant with Clean Air Act requirements. Canal Electric Company (Canal), on behalf of itself, Montaup and others has contracts with a supplier for up to 100% of the fuel-oil requirements of Canal Unit Nos. 1 and 2 for the period ending December 31, 1997 with an option of extending the contracts through March 31, 1998. The current contracts permit up to 35% of fuel oil purchases in the spot market. Fuel prices are based on oil market posting at the time of delivery. For 1996, the cost of oil per barrel at Canal averaged $18.67. Additionally, Canal has a contract with a gas supplier for approximately 70% of Canal 2's daily gas requirements. Canal 2 completed its gas conversion and testing in September 1996. The unit is now able to burn gas, oil, or a blend of the two fuels. Economics, generation and supply will determine actual fuel type usage. Montaup's costs of fossil and nuclear fuels for the years 1994 through 1996, together with the weighted average cost of all fuels, are set forth below: Mills* per kWh 1996 1995 1994 Nuclear . . . . . . . . . 5.0 6.3 6.1 Gas . . . . . . . . . 14.4 14.3 14.1 Coal . . . . . . . . . 19.6 20.3 20.9 Oil . . . . . . . . . 37.7 30.2 27.1 All fuels . . . . . . . . . 16.7 16.7 14.5 *One Mill is 1/10 of one cent The rate schedules of Montaup and the Retail Subsidiaries are designed to pass on to customers the increases and decreases in fuel costs and the cost of purchased power, subject to review and approval by appropriate regulatory authorities (see Rates below). OSP has two gas supply contracts which expire December 14, 2009 and September 29, 2010, respectively, for its two 250 mw generators. The cost of gas for 1996 averaged $1.20 per MBTU or approximately 10.0 mills per kWh generated. 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 DOE for disposal of spent nuclear fuel in accordance with the 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. Montaup owns a 4.01% interest in Millstone III and a 2.9% interest in Seabrook I. Northeast Utilities, the operator of the units, indicates that Millstone III 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 fuel rates and will be collected through the contract termination charge. Nuclear Power Issues General: Nuclear generating facilities, including those in service in which Montaup participates, as shown in the table under Item 2. PROPERTIES -- Power Supply, are subject to extensive regulation by the NRC. The NRC is empowered to authorize the siting, construction and operation of nuclear reactors after consideration of public health, safety, environmental and anti-trust matters. The NRC has promulgated numerous requirements affecting safety systems, fire protection, emergency response planning and notification systems, and other aspects of nuclear plant construction, equipment and operation. These requirements have caused modifications to be made at some of the nuclear units in which Montaup has an interest. Montaup has been affected, to the extent of its proportionate share, by the costs of such modifications. Nuclear units in the United States have been subject to widespread criticism and opposition. Some nuclear projects have been cancelled following substantial construction delays and cost overruns as the result of licensing problems, unanticipated construction defects and other difficulties. Various groups have by litigation, legislation and participation in administrative proceedings sought to prohibit the completion and operation of nuclear units and the disposal of nuclear waste. In the event of cancellation or shutdown of any unit, NRC regulations require that it be decontaminated of any residual radioactivity sufficiently so that the property may be released for unrestricted use. The cost of such decommissioning, depending on the circumstances, could substantially exceed the owners' investment at the time of cancellation. Joint owners of nuclear projects are subject to the risk that one of their number may be unable or unwilling to finance its share of the project's costs, thus jeopardizing continuation of the project. Also, the continuing public controversy concerning nuclear power could affect the operating units in which Montaup has an interest. While management cannot predict the ultimate effect of such controversy, it is possible that it could result in the premature shutdown of one or more of the units. The Price-Anderson Act provides, among other things, that the liability for damages resulting from a nuclear incident would not exceed an amount which at present is about $8.7 billion. Under the Price-Anderson Act, prior to operation of a nuclear reactor, the licensee is required to insure against this exposure by purchasing the maximum amount of liability insurance available from private sources (currently $200 million) and to maintain the insurance available under a mandatory industry-wide retrospective rating program. Should an individual licensee's liability for an incident exceed $200 million, the difference between such liability and the overall maximum liability, currently about $8.7 billion, will be made up by the retrospective rating program. Under such a program, each owner of an operating nuclear facility may be assessed a retrospective premium of up to a limit of $79.3 million (which shall be adjusted for inflation at least every five years) for each reactor owned in the event of any one nuclear incident occurring at any reactor in the United States, with provision for payment of such assessment to be made over time as necessary to limit the payment in any one year to no more than $10 million per reactor owned. With respect to operating nuclear facilities of which it is a part owner or from which it contracts (on terms reflecting such liability) to purchase power, Montaup would be obligated to pay its proportionate share of any such assessment. Decommissioning: Both of the operating nuclear generating companies in which Montaup has an equity ownership interest (see Item 2. PROPERTIES -- Power Supply) have developed their estimates of the cost of decommissioning its unit and have received the approval of FERC to include charges for the estimated costs of decommissioning its unit in the cost of energy which it sells. From time to time, these companies re-estimate the cost of decommissioning and apply to FERC for increased rates in response to increased decommissioning costs. Maine Yankee has filed a decommissioning financing plan under a Maine statute which requires the establishment of a decommissioning trust fund. That statute also provides that if the trust has insufficient funds to decommission the plant, the licensee (Maine Yankee) is responsible for the deficiency and, if the licensee is unable to provide the entire amount, the "owners" of the licensee are jointly and severally responsible for the remainder. The definition of "owner" under the statute includes Montaup and may include companies affiliated with Montaup. The applicability and effect of this statute cannot be determined at this time. Montaup would seek to recover through its rates any payments that might be required (see "Yankee Atomic", and "Connecticut Yankee" below). Montaup is recovering through rates its share of estimated decommissioning costs for Millstone III and Seabrook I. Montaup's share of the current estimate of total costs to decommission Millstone III is $18.6 million in 1996 dollars, and Seabrook I is $13.1 million in 1996 dollars. These figures are based on studies performed for the lead owners of the plants. In addition, pursuant to contractual arrangements with other nuclear generating facilities in which Montaup has an equity ownership interest or life of the unit entitlement, Montaup pays into decommissioning reserves. Such expenses are currently recoverable through rates. Yankee Atomic: On February 26, 1992, Yankee Atomic announced that it would permanently cease power operation of Yankee Rowe and began preparing for an orderly decommissioning of the facility. Montaup has a 4.5% equity ownership in Yankee Atomic with a book value of approximately $1.1 million at December 31, 1996. Under the terms of its purchased power contract with the facility, Montaup must pay its proportionate share of unrecovered costs and expenses incurred after the plant is retired. In December 1992, Yankee Atomic received FERC authorization to recover essentially all unrecovered assets and all costs incurred after the February 26, 1992 shutdown decision until the plant is decommissioned. Montaup's share of all unrecovered assets and the total estimated costs to decommission the unit aggregated approximately $7.8 million at December 31, 1996. Connecticut Yankee: Connecticut Yankee, a 582-mw nuclear unit, was taken off-line in July 1996 because of issues related to certain containment air recirculation and service water systems. Montaup has a 4.5% equity ownership in Connecticut Yankee with a book value of $4.8 million at December 31, 1996. In October 1996, Montaup, as one of the joint owners, participated in an economic evaluation of Connecticut Yankee which recommended permanently closing the unit and replacing its output with less expensive energy sources. As a result of the analysis, work at the plant had slowed pending a final board decision. In December 1996, the Board of Directors voted to retire the generating station. Connecticut Yankee certified to the NRC that it had permanently closed power generation operations and removed fuel from the reactor. Connecticut Yankee has two years to submit its decommissioning plan to the NRC. The preliminary estimate of the sum of future payments for the permanent shutdown, decommissioning, and recovery of the remaining investment in Connecticut Yankee, is approximately $758 million. Montaup's share of the total estimated costs is $34.1 million. Recent NRC Actions: Millstone III Montaup has a 4.01% ownership interest in Millstone III, an 1154-mw nuclear unit that is jointly owned by a number of New England utilities, including subsidiaries of Northeast Utilities (Northeast). Northeast is the lead participant in Millstone III, and on March 30, 1996, Northeast determined it was necessary to shut down the unit following an engineering evaluation which determined that four safety-related valves would not be able to perform their design function during certain postulated events. The NRC has raised numerous issues with respect to Millstone III and certain of the other nuclear units in which Northeast and its subsidiaries, either individually or collectively, have the largest ownership shares, including Connecticut Yankee (see "Connecticut Yankee" above). In July 1996 Northeast reported that it has been responding to a series of requests from the NRC seeking assurance that the Millstone III unit will be operated in accordance with the terms of its operating license and other NRC requirements and regulations and dealing with a series of issues that Northeast has identified in the course of these reviews. Providing these assurances and addressing these issues will be components of an Operational Readiness Plan (ORP) to be developed for the Millstone III unit. The ORP for Millstone III was submitted to the NRC on July 2, 1996 and is presently being implemented. On October 18 1996, the NRC informed Northeast that it will establish a Special Projects Office to oversee inspection and licensing activities at Millstone. The Special Projects Office will be responsible for (1) licensing and inspection activities at Northeast's Connecticut plants, (2) oversight of an independent corrective action verification program; (3) oversight of Northeast's corrective actions related to safety issues involving employee concerns, and (4) inspections necessary to implement NRC oversight of the plants' restart activities. On October 24, 1996 the NRC issued another order directing that prior to restart of Millstone III, Northeast submit a plan for disposition of safety issues raised by employees and retain an independent third-party to oversee implementation of this plan. This third-party oversight will continue until the situation is corrected. There is no estimate of how long this will take. Northeast Management has indicated it cannot presently estimate the effect these efforts will have on the timing of restarts or what additional costs, if any, these developments may cause. While Millstone III is out of service, Montaup will incur incremental replacement power costs estimated at $0.4 million to $0.8 million per month. Montaup bills its replacement power costs through its fuel adjustment clause, a wholesale tariff jurisdictional to the FERC. However, there is no comparable clause in Montaup's FERC-approved rates which at this time would permit Montaup to recover its share of the incremental operation and maintenance costs incurred by Northeast. EUA cannot predict the ultimate outcome of the NRC inquiries or the impact which they may have on Montaup and the EUA system. Montaup is also evaluating its rights and obligations under the various agreements relating to the ownership and operation of Millstone III. Maine Yankee On June 7, 1996, the NRC commissioned an independent Safety Assessment Team to assess the conformance of the Maine Yankee Atomic Power Station to its design and licensing basis. Montaup holds a 4.0% ownership interest in the Maine Yankee Unit. On October 7, 1996, the NRC released an Independent Safety Assessment (ISA) report. In evaluating the Plant's conformance to its licensing basis, the report concluded that Maine Yankee was in general conformance with its licensing basis although significant items of nonconformance were identified stemming from two closely related root causes: (1) economic pressure to be a low-cost energy provider had limited available resources to address corrective actions and some improvements and (2) a questioning culture was lacking, which had resulted in a failure to identify or promptly correct significant problems in areas perceived by Maine Yankee to be of low safety significance. A letter to Maine Yankee from the Chair of the NRC, accompanying the ISA report directed Maine Yankee to provide to the NRC its plans for addressing the root causes of the deficiencies identified by the ISA. In December, 1996 the unit was shut down for inspections and repairs to resolve cable-separation and associated issues. While the plant has been out of service, Maine Yankee, having previously detected indications of minor leakage in a small number of the plant's 38,000 fuel rods, used the opportunity to inspect the Plant's 217 fuel assemblies. As a result of the inspection, Maine Yankee determined that several fuel assemblies that contained leaking rods should be replaced and has commenced that process. On January 29, 1997 the NRC announced that it had placed the unit on its "watch list." The operator expects the Plant to remain out of service until the fuel-assembly replacement and a thorough inspection of the Plant's electrical cabling are completed and associated issues resolved, and restarting the Plant is approved by the NRC. The operator cannot now predict how long it will take to complete those processes. In February 1997, Maine Yankee and Entergy Nuclear, Inc. signed a contract for Entergy to provide management services including plant operations at the Maine Yankee plant through September 1997. Maine Yankee and Entergy have been discussing the possibilities of a longer term contract. General Recent actions by the NRC, some of which are cited above, indicate that the NRC has become more critical and active in its oversight of nuclear power plants. EUA is unable to predict at this time, what, if any, ramifications these NRC actions will have on any of the other nuclear power plants in which Montaup has an ownership interest or power contract. Public Utility Regulation Eastern Edison and Montaup are subject to regulation by the MDPU with respect to the issuance of securities, the form of accounts, and in the case of Eastern Edison, rates to be charged, services to be provided, and other matters. Blackstone and Newport are subject to regulation in numerous respects by the RIPUC and the RIDPUC, including matters pertaining to financing, sales and transfers of utility properties, accounting, rates and service. In addition, by reason of its ownership of fractional interests in certain facilities located in other states, Montaup is subject to limited regulation in those states. See Electric Utility Industry Restructuring. IPPs, including OSP in which EUA Ocean State has a 29.9% ownership interest, do not benefit from the PURPA exemptions and are subject to FERC regulation under the Federal Power Act as well as various other federal, state and local regulations. The EUA System is subject to the jurisdiction of the SEC under the 1935 Act by virtue of which the SEC has certain powers of regulation, including jurisdiction over the issuance of securities, changes in the terms of outstanding securities, acquisition or sale of securities or utility assets or other interests in any business, intercompany loans and other intercompany transactions, payment of dividends under certain circumstances, and related matters. Eastern Edison is a holding company under the 1935 Act by reason of its ownership of securities of Montaup. As a subsidiary of EUA, a registered holding Company, Eastern Edison is exempted from registering as a holding company by complying with the applicable rules thereunder. The Retail Subsidiaries and Montaup are also subject to the jurisdiction of FERC under Parts II and III of the Federal Power Act. That jurisdiction includes, among other things, rates for sales for resale, interconnection of certain facilities, accounts, service, and property records. The MDPU and RIPUC have approved a Memorandum of Understanding (MOU) between Eastern Edison, Blackstone, Newport and Montaup. The MOU establishes a framework for a coordinated, regional review of the resource planning and procurement process of those companies. It is based on the assumption that resource planning and procurement by a regional electric company may be implemented more effectively under a coordinated, consensual review process involving the EUA retail companies and the state public utility commissions to which the EUA retail companies are subject. Pursuant to the terms of the MOU, at least every two years Montaup and Eastern Edison will file with the MDPU and Blackstone and Newport will file with the RIPUC an integrated resource plan concurrently. The MOU outlines a mechanism and a timetable by which the reviews by the two commissions will be coordinated and any inconsistencies among the decisions by the state commissions will be resolved. In conjunction with its approval of the MOU, the MDPU granted Eastern Edison and Montaup an exemption from the MDPU's Integrated Resource Management regulations, but required them to plan, solicit and procure additional resources according to newly promulgated regional Integrated Regional Planning procedures consistent with the MOU. The Integrated Resource Management Plan of Blackstone and Newport meet the criteria of the RIPUC. Implementation of the MOU is not expected to have a material effect on the EUA System. The move to restructure the industry to a more competitive model may, however, impact the role of the states in reviewing utilities' resource planning and procurement activities. Massachusetts is currently reviewing the need for its review of load forecasting and resource planning, recognizing that resource procurement is now a competitive function. As competition becomes more prevalent in the electric industry, it is anticipated that regulatory review will decrease accordingly. See Rates with respect to regulation of rates charged to customers. See Environmental Regulation. See Fuel for Generation with respect to the disposal of spent nuclear fuel. See Environmental Regulation of Nuclear Power and see Nuclear Power Issues with respect to regulation of nuclear facilities by the NRC. See also Electric Utility Industry Restructuring. Rates Rates charged by Montaup (which sells power only for resale) are subject to the jurisdiction of FERC. The rates for services rendered by the Retail Subsidiaries for the most part are subject to approval by and are on file with the MDPU in the case of Eastern Edison and with the RIPUC in the case of Blackstone and Newport. For the 12 months ended December 31, 1996, 62% of EUA's consolidated revenues were subject to the jurisdiction of FERC, 15% to that of the MDPU and 12% to that of the RIPUC. The remaining 11% of consolidated revenues are not subject to jurisdiction of utility commissions. For the twelve months ended December 31, 1996, 80.6% of Eastern Edison's consolidated revenues were subject to the jurisdiction of the FERC and 19.4% to MDPU. Additionally, rates charged by OSP are subject to the jurisdiction of FERC. All OSP (Unit 1 and Unit 2) power contracts have been approved by FERC. However, pursuant to the OSP unit power agreements, rate supplements are required to be filed annually subject to FERC approval. This process may result in rate increases or decreases to OSP power purchasers. Recent general rate increases (reduction) for Montaup and the Retail Subsidiaries are as follows (In Thousands):
Applied For Effective Return on Annual Annual Common Revenue Date Revenue Date Equity % Federal - Montaup M-14 $ (10,133) 3/21/94 $(13,992) 8/9/94 11.10 Massachusetts None Rhode Island - Blackstone RIPUC - 2045 - Phase III 353 11/1/94 353 1/1/95 - Phase IV 152 10/23/95 152 1/1/96 RIPUC - 2498 3,094 11/15/96 2,821 1/1/97 - Newport RIPUC - 2045 - Phase III 417 11/1/94 417 1/1/95 - Phase IV 179 10/23/95 179 1/1/96 RIPUC - 2498 1,437 11/15/96 1,425 1/1/97 ____________________ Notes: Per final order or settlement agreement. Settlement Agreement with all parties with an annual reduction of $13,992,000 with billing credits to Middleboro over the period January 1995 through October 1999 totaling $496,000. Rate used for AFUDC calculation purposes. Settlement contains no specific finding on allowed common equity return. RIPUC Docket No. 2045 was a generic docket for all Rhode Island utilities reviewing FAS106 expenses. The effective amount represents the revenue requirement for one-third of the tax deductible amount of the FAS106 expenses (see Rhode Island Proceedings below). As this was a single issue proceeding, the RIPUC made no revisions to the allowed return on common equity. The revenue requirement represents 14.3% of the total FAS106 incremental tax deductible amount to be recovered in each of the next seven years. This annual revenue requirement recovers, over seven years, the FAS106 incremental tax deductible costs which were deferred by the companies in Phases I&II and will be eliminated after the seven-year recovery. The revenue requirement represents the compliance with R.I.G.L., 39-1-27.4 to file performance based rates reflecting the change in the Consumer Price Index for the most recent 12 months ended September 30, 1996.
FERC Proceedings: On May 21, 1994 Montaup filed a rate application with FERC to reduce annual revenues by $10.1 million. This request was intended to match more closely Montaup's revenues with its decreasing cost of doing business resulting from, among other things, a reduced rate base, lower capital costs and successful cost control efforts. The application also included a request for recovery of all of Montaup's FAS106 expenses as provided in FERC's generic order of December 1992, including a five-year amortization of previously deferred FAS106 costs. Also incorporated in this filing was a request to make Newport an all requirements customer of Montaup. Settlement agreements were certified by FERC with all intervenors with an annual base rate reduction of approximately $14 million annually, (inclusive of the filed $10.1 million reduction) effective as of August 1994. On February 20, 1996, Montaup filed an application with FERC for network and point-to-point transmission service tariffs. FERC required this tariff application before granting a concurrent application of Duke/Louis Dreyfus Energy Services (New England) L.L.C. for permission to charge market based rates. On July 9, 1996 Montaup refiled the application to conform with FERC open access terms and conditions. On January 21, 1997 the application was refiled to conform with the NEPOOL open access tariff. FERC has not yet acted upon the filings. Massachusetts Proceedings: The MDPU has put all companies on notice that it expects them..."to consider mergers or acquisitions in order to further optimize least-cost planning efforts and better fulfill their obligations to serve." Thereafter, the MDPU instituted an investigation, which was concluded on August 3, 1994, for the purpose of establishing, among other things, guidelines and standards for acquisitions and mergers of utilities and evaluating proposals regarding the recovery of costs associated with such activities. It is not possible to predict what effects, if any, the MDPU proceeding will have on the EUA System. In December 1994, the MDPU approved a request made by Eastern Edison to recover through a reconciling adjustment factor a portion of "lost base revenues." Lost base revenue represents amounts the company would have collected if it had not offered demand-side management and conservation and load management programs to its customers. On September 20, 1994, the MDPU issued a notice of inquiry and order seeking comments on incentive regulation (MDPU 94-58). The inquiry was to focus on incentive regulation, sometimes referred to as performanced-based regulation, to replace in whole or in part its existing cost-of-service/rate- of-return regulatory framework. Comments were filed by Eastern Edison and other interested persons. On February 24, 1995, the MDPU issued an order relating to implementation of incentive regulation. In the order, the MDPU strongly encouraged all jurisdictional electric utilities to devise and propose incentive plans. The objective of incentive regulation is to "provide market- place benefits to consumers through (1) more efficient utility operations, (2) stronger utility incentives for better cost control, and (3) enhanced opportunities for lower rates." While no timetable was specified, the MDPU stated the largest utilities should commence the incentive plan design process as soon as possible. EUA cannot predict what effect, if any, the MDPU's order will have on the EUA System. However, Eastern Edison's December 23, 1996 settlement agreement with Massachusetts Department of Energy Resources and that State's Attorney General, expected to be formally submitted to the MDPU in March 1997, contains performance based regulation standards. (See Electric Utility Industry Restructuring under "Massachusetts Restructuring Settlement" above). On February 10, 1995, the MDPU issued a notice of inquiry and order on electric industry restructuring (MDPU 95-30). The investigation was established to determine: (1) how a restructuring of the Massachusetts electric industry would promote competition and economic efficiency while expanding opportunities that would benefit consumers, (2) whether and how to extend to customers the option of choosing their own electric suppliers; (3) how such a restructuring could be implemented; and (4) the appropriate regulatory mechanisms to apply to a restructured electric industry. After initial and second round comments were received, the MDPU held hearings and issued its order on August 16, 1995. The order facilitates increased competition by requiring investor-owned electric utilities to unbundle their rates, provide consumers with accurate price signals, and enable customer choice that allows consumers to purchase generation services separately from transmission and distribution services. The order provides for the recovery of net, non-mitigatable stranded costs that will result from the transition from a regulated to a competitive industry structure. The order sets forth the MDPU's overall goals for a restructured industry, the essential characteristics of a restructured industry, as well as principles to be considered in the transition to a restructured industry. Given the complexity of the issues, the MDPU supported the multiple requests from reviewers for a period during which participants can negotiate settlements. The MDPU stated that consensus and settlements are more likely than litigation to advance the restructuring process, and directed each company to undertake negotiations with all interested participants to develop a plan for moving toward competition in generation and retail customer choice, to decide the amount and develop a mechanism for stranded cost recovery, and establish unbundled rates. A collaborative group representing the full spectrum of MDPU 95-30 participants has been meeting in Massachusetts to discuss these issues. The MDPU noted that while the concepts of competition and customer choice are fundamental to restructuring, and the basic principles will apply to all restructuring proposals, specific company corporate structures, service territories, rate structures and stranded costs may require individual consideration. The MDPU established a specific schedule for restructuring proposals. Massachusetts Electric Company, Boston Edison Company, and Western Massachusetts Electric Company were required to file their settlements and proposals by February 16, 1996. The remaining electric utilities are required to file their settlements and proposals within three months of the issuance of MDPU orders related to the restructuring proposals of the former three companies. Companies are required to file the following information: (1) a plan for moving from the current regulated industry structure to a competitive generation market and to increased customer choice; (2) illustrative rates and supporting information that indicate unbundled charges for generation, distribution, transmission, and ancillary services; (3) an identifiable charge reflective of the level of stranded costs to be recovered with all necessary supporting information; and (4) a plan for incentive regulation in the transmission and distribution systems. Eastern Edison filed its restructuring plan on February 16, 1996 which was assigned MDPU Docket No. 96-24. A public hearing was held on March 6, 1996. See Electric Utility Industry Restructuring under "Massachusetts Restructuring Settlement" for a discussion of the December 23, 1996 settlement among Eastern Edison, Montaup, Massachusetts Department of Energy Resources and the Massachusetts Attorney General. A formal settlement plan under Docket No. 96-24 is expected to be filed with the MDPU in March 1997. On December 30, 1996 the MDPU issued its Model Rules in Docket # 96-100, the second phase of its investigation of the restructuring of the electric utility industry in Massachusetts and proposed legislation for consideration by the Massachusetts Legislature that would provide the MDPU with the mandate to implement these rules. The MDPU has indicated that its overall goal is to develop an efficient industry structure and regulatory framework that minimizes costs to consumers while maintaining safe and reliable electric service with minimum impact on the environment. Consistent with the overall goal, the Model Rules provide for, among other things: - customer choice of electricity supplier with local distribution companies guaranteeing default service including continuation of low income protections and discounts; - independent central regional transmission system operator; - non-discriminatory open access transmission; - functional separation of distribution, generation and transmission; - distribution services remain a regulated monopoly; - commitment to significant environmental improvement; - funding mechanism to provide financial support for renewable and emerging technologies and continuation of demand-side management programs; - reasonable opportunity for recovery of stranded costs; and - standards of conduct for distribution companies and their competitive affiliates. While Eastern Edison believes that its December 23, 1996 agreement with the Attorney General and the Division of Energy Resources is consistent with the requirements of these Model Rules, it is of the opinion that the MDPU has the authority to approve the agreement without the need of additional legislation or officially promulgating these Model Rules. See Electric Utility Industry Restructuring, under "Massachusetts Restructuring Settlement," with respect to settlement negotiations. Rhode Island Proceedings: On April 7, 1992, the RIPUC initiated generic Docket No. 2045 pertaining to the FAS106 issue for all Rhode Island utility companies. On June 26, 1992, Newport and Blackstone filed proposed rate increases to reflect the impact of FAS106 of approximately $1.3 million and $2.7 million, respectively. An order was issued on December 11, 1992 granting recovery of a tax deductible amount of FAS106 phased into rates over a three-year period with the initial one-third to be recovered no earlier than the first fiscal year beginning after December 15, 1992, and the deferrals of the first two years recovered in rates over the seven-year period following the three-year phase-in. On December 21, 1992, Newport and Blackstone filed compliance rates representing phase one of the three-year phase-in. The Phase I revenue requirement, representing one third of the incremental FAS106 tax deductible amount for Blackstone and Newport was calculated to be $353,000 and $417,000, respectively. Phase II compliance was filed November 1, 1993. The revenue requirement, representing two thirds of the incremental FAS106 tax deductible expense for Blackstone and Newport was calculated to be $706,000 and $834,000, respectively. Phase III compliance was filed November 1, 1994. The revenue requirement, representing the full phase- in of the incremental FAS106 tax deductible expense for Blackstone and Newport were calculated to be $1,059,000 and $1,251,000, respectively. Phase IV compliance was filed on October 23, 1995, recovering deferred amounts over 7 years, 14.3% each year starting January 1, 1996. The RIPUC also ordered that all amounts recovered be placed in trusts permitted by the IRS which will maximize tax deductibility. Also, on January 14, 1994, the RIPUC issued a written order establishing Docket No. 2167 for a Comprehensive Review of Newport's rate design. A prehearing conference was held on February 8, 1994 at which time a schedule for pre-filing testimony was established. On May 20, 1994, Newport filed its Cost of Service Study (COSS) analysis of the rates of return by customer class and an alternative rate design proposal. The RIDPUC filed its recommendations with regard to cost allocation and rate design on June 23, 1994. The United States Navy, Newport's largest customer, filed its recommendations on June 24, 1994. On July 29, 1994 the Company filed a Stipulation and Settlement Agreement (SSA) which had been executed by the RIDPUC and TEC-RI. The parties signing the SSA agreed on certain rate class revenue changes. While the settling parties did not agree with the COSS techniques utilized by Newport, they agreed to accept the SSA rather than litigating with respect to what might be deemed appropriate study allocators and techniques. The rate class revenue changes generally reduce, although they do not eliminate, inequities in the class rate of return. Newport agreed to perform a new COSS to be submitted no later than July 1, 1996. At an open meeting on October 28, 1994, the RIPUC found that the SSA is reasonable and in the best interests of the ratepayers. Rates established in compliance with the RIPUC's October 28, 1994 finding, were effective January 1, 1995. In December 1994, the United States Navy, filed a petition for a writ of certiorari with the Rhode Island Supreme Court to review the RIPUC's decision. A second motion to stay was filed by the Navy on December 21, 1995. On June 28, 1996 Newport filed its 1995 COSS and on July 8, 1996 the U.S. Navy filed a Motion for Expedited Hearing. The RIDPUC took the position that the RIPUC's order in Docket No. 2167 neither required nor set any timetable for additional rate changes. The RIDPUC also indicated that it took no position regarding either the merits of the COSS or the Navy's request for an expedited hearing. The RIDPUC, at the RIPUC's request reviewed the results of the COSS as well as the allocation methodologies employed. Additionally, the RIDPUC explored the propriety of the Navy's request in light of the filing of unbundled rates required to be made effective by the Restructuring Act of 1996. On February 3, 1997 the Navy filed a stipulation to withdraw the writ of certiori it had filed in December 1994. On June 27, 1994 TEC-RI petitioned the RIDPUC to investigate the propriety of "the current bundled electric rates," and what might be required to transition "... from a fully regulated to a more competitive retail electric industry". A RIDPUC hearing officer was appointed on July 24, 1994 and Docket No. D-94-9 was established. Blackstone and Newport were parties to the proceeding. Initial and reply comments were submitted to a comprehensive list of issues. Many of the comments addressed a broad restructuring of the electric utility industry. When the parties met on January 9, 1995, they decided that TEC-RI's proposal for a "cooperative collaborative process," including the RIDPUC as a party, rather than a litigated proceeding before the RIDPUC hearing officer, was appropriate. Hence, the Rhode Island Collaborative (Collaborative) was formed. On May 12, 1995, the Collaborative submitted a Report and Set of Interdependent Principles to the RIPUC. The 17 Interdependent Principles represented the Collaborative's underpinnings for any restructuring proposal. The Collaborative requested that the RIPUC establish a docket and conduct a hearing to explore the settlement principles with a view to issuing an order indicating whether the principles "provide a suitable basis for further detailed negotiation by the parties, or in what respects they require modification" and setting a deadline for the submission of a more detailed proposal for restructuring. The RIPUC responded to the Collaborative's request by creating Docket No. 2320, taking administrative notice of Docket No. D-94-9, and declaring that all parties to the Division docket would be treated as intervenors in this docket. The RIPUC conducted a technical conference on July 6, 1995 and a Public hearing on July 11, 1995. On July 19, 1995 three of the principles were modified to address concerns expressed by the RIPUC at the technical conference. On July 25, 1995, the Collaborative provided additional information on the principle concerning renewables, and requested that the RIPUC approve the principles in full. On August 16, 1995, the RIPUC accepted the principles as modified, deleting the principle concerning renewables and adding a principle concerning negotiation. The Collaborative was directed to proceed with negotiations to quantify specific issues involving competition and open access as well as the other issues presented in the principles. A Collaborative Progress Report was filed in February, 1996. Blackstone and Newport have been active participants in the ongoing collaborative meetings. As a result of legislative actions and the passing of the URA, Docket No. 2320 was formally closed and the collaborative was disbanded. In February 1997 the RIPUC initiated Docket No. 2509 to investigate utility company storm contingency funds. Both Blackstone and Newport are recovering through rates amounts for storm contingencies. A hearing was held on February 28, 1997. Management cannot predict the ultimate outcome of this investigation. The RIPUC opened Docket No. 2514 to investigate the restructuring plan filed by Blackstone and Newport on December 27, 1996 in compliance with the URA. Hearings are scheduled to be held during April 1997. On February 28, 1997, Blackstone, Newport and Montaup reached settlement with the RIDPUC and the Rhode Island Attorney General with regard to implementation of a restructuring plan for Blackstone, Newport and Montaup. In addition to complying with the URA, the settlement provides for an immediate 10% rate reduction and a commitment by Montaup to file a plan by July 1, 1997 to divest all of its generating assets. Management cannot predict the ultimate outcome of this investigation. See Electric utility Industry Restructuring under "Rhode Island Utility Restructuring Act of 1996" for a discussion of the URA and settlement agreement. Environmental Regulation General: The Retail Subsidiaries and Montaup 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 EPA, and certain state and local authorities, have jurisdiction over releases of pollutants, contaminants and hazardous substances into the environment and have broad authority in connection therewith, including the ability to require installation of pollution control devices and remedial actions. In 1994, an environmental audit program designed to ensure compliance with environmental laws and regulations and to identify and reduce liability was instituted for Montaup and the Retail Subsidiaries. Federal, Massachusetts and Rhode Island legislation requires consideration of reports evaluating environmental impact of large projects as a prerequisite to the granting of various permits and licenses with a view of limiting such impact. Federal, Massachusetts and Rhode Island air quality regulations also require that plans for construction or modification of fossil fuel generating facilities (including procedures for operation and maintenance) receive prior approval from the MADEP or RIDEM. In addition, in Massachusetts, certain electric generation and transmission facilities will be permitted to be built only if they are consistent with a long-range forecast filed by the utility concerned and approved by the Massachusetts Energy Facilities Siting Council. In Rhode Island, siting, construction and modification of major electric generating and transmission facilities must be approved by the Rhode Island Energy Facility Siting Board. Generating facilities in which Montaup and Newport have an interest, and are required to pay a share of the costs, are also subject, like other electric utilities, to regulation with regard to zoning, land use, and similar controls by various state and local authorities. The EPA and state and local authorities may, after appropriate proceedings, require modification of generating facilities for which construction permits or operating licenses have already been issued, or impose new conditions on such permits or licenses, and may require that the operation of a generating unit cease or that its level of operation be temporarily or permanently reduced. Such action may result in increases in capital costs and operating costs which may be substantial, in delays or cancellation of construction of planned facilities, or in modification or termination of operations of existing facilities. Other activities of the EUA System from time to time are subject to the jurisdiction of various other local, state and federal regulatory agencies. It is not possible to predict with certainty what effects the above described statutes and regulations will have on the EUA System. The EPA has issued regulations relating to the generation, transportation, storage and disposal of certain wastes under RCRA; in Massachusetts, the requirements are implemented and enforced by the MADEP, whereas in Rhode Island, RIDEM implements and enforces its own regulations under a state statute comparable to RCRA as well as pursuant to EPA authorization. There is an extensive body of federal and state statutes governing environmental matters, including CERCLA, as amended by the Superfund Amendments and Reauthorization Act of 1986; in Massachusetts, Chapter 21E, and, in Rhode Island, the "Industrial Property Site Remediation and Reuse Act" (Brownfields Legislation) 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. Under CERCLA, Chapter 21E, and the Rhode Island Brownfields Legislation, joint and several liability for cleanup costs may be imposed on, among others, the owners or operators of a facility where hazardous substances were disposed, the party who generated the substances, or any party who arranged for the disposition or transport of the substances. Due to the nature of the business of EUA's utility subsidiaries, certain materials are generated that may be classified as hazardous under CERCLA, Chapter 21E and Brownfields Legislation. As a rule, the subsidiaries employ licensed contractors to dispose of such materials. See Item 3. LEGAL PROCEEDINGS -- Environmental Proceedings. The EPA, pursuant to TSCA, regulates the use, storage, and disposal of PCBs and other dielectric fluids. Because the EUA System had owned and used some electrical transformers containing PCBs, it is subject to EPA regulation under TSCA. These PCB transformers have been either declassified or disposed of in accordance with TSCA requirements. EUA currently uses mineral oil transformers which may contain traces of PCB and which may be subject to regulations pursuant to TSCA. Electric and Magnetic Fields: 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. The 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 EMF, are continuing. On October 31, 1996, the National Academy of Sciences issued a literature review of all research to date, "Possible Health Effects of Exposure to Residential Electric and Magnetic Fields." Its most widely reported conclusion stated, "No clear, convincing evidence exists to show that residential exposures to EMF are a threat to human health." Some states have enacted regulations to limit the strength of EMF at the edge of transmission line rights-of-way. Rhode Island has enacted a statute which authorizes and directs the Rhode Island Energy Facility Siting Board to establish rules and/or regulations governing construction of high voltage transmission lines of 69 kv or more. In addition, Rhode Island requires that, in the context of reviewing an energy facility siting application, the applicant submit for review by the Board, when applicable, any current independent, scientific research pertaining to EMF exposure. Management cannot predict the impact if any, which legislation(s) or other developments concerning EMF may have on the EUA System. Water Regulation: The objective of the Federal Water Pollution Control Act is to restore and maintain the chemical, physical, and biological integrity of the nation's navigable waters. The elimination of pollutant discharges (including heat) into navigable waters is one goal aimed at achieving this objective. Another step mandated by the Federal Water Pollution Control Act was the creation of a rigorous permit program. All water discharge permits for plants in Massachusetts, including those for the Somerset and Canal plants, are issued jointly by the EPA and MADEP. These same agencies also regulate certain industrial stormwater discharges. Standards have been established to control the dredging and filling of wetlands under the Federal Water Pollution Control Act, the Massachusetts Wetland Protection Act, Massachusetts Rivers Protection Act and the Rhode Island Wetland Act. The EPA, the Army Corps of Engineers, RIDEM, the Rhode Island Coastal Resources Management Council and the MADEP are pursuing a non- degradation (no loss) policy for wetlands. Under the Massachusetts Water Management Act, the MADEP is responsible for promulgating regulations relating to water usage and conservation. Most of the generating units from which Montaup obtains power operate under permits which limit their effluent discharges into water and which require monitoring and, in some instances, biological studies and toxicity testing of the impact of the discharges. Such permits are issued for a period of not more than five years, at the expiration of which renewal must be sought. The permit for the Somerset plant was renewed on September 30, 1994 and expires on September 30, 1998. The Oil Pollution Act of 1990 was passed after several major oil spills occurred in waters of the United States. The primary intent of this legislation is to mandate strong contingency plans to prevent releases of oil and to require that sufficient resources are in place and ready to respond to any release. The Somerset plant has an approved plan which is in place and operational. EPA, United States Coast Guard, RIDEM, and MADEP have a number of other rules in place, such as EPA's Spill Prevention, Countermeasures and Control Plan regulations, which are designed to minimize the release of oil and other substances into navigable waters and the environment. Air Regulation: All fossil fuel plants from which Montaup obtains power operate under permits which limit their emissions into the air and require monitoring of the emissions. Air quality requirements adopted by state authorities in Massachusetts pursuant to the Clean Air Act impose limitations with respect to pollutants such as sulfur dioxide (SO2), oxides of nitrogen (NOx) and particulate matter. Montaup's Somerset Station is permitted to burn coal which results in SO2 emissions not in excess of 1.2 pounds per million BTU heat release potential (approximately 0.75% sulfur content coal). The Canal Station Unit 2 is permitted to burn fuel oil which results in SO2 emissions not in excess of 1.2 pounds per million BTU heat release potential (approximately 1% sulfur content fuel oil). The EPA has established clean air standards for certain pollutants, including standards limiting emissions from coal-fired and oil-fired generators. Congress passed amendments to the Clean Air Act in 1990 which created additional regulatory programs and generally updated and strengthened air pollution control laws. These amendments expand the regulatory role of the EPA regarding emissions from electric generating facilities. Title IV of the Clean Air Act Amendments addresses acid deposition abatement and establishes a two-phase utility power plant pollution control program to reduce emissions of SO2 and NOx. The first phase began in 1995 and affected approximately 261 large units in 21 eastern and midwestern states. Phase II, which begins in the year 2000, tightens the emission limits imposed on these larger plants and also sets restrictions on smaller, cleaner plants fired by coal, oil and gas. Montaup's Somerset Station is classified as a Phase II facility with a compliance deadline by the end of 1999. The control program establishes a national cap of 8.90 million tons per year for SO2 emissions. Beginning in the year 2000, the EPA will issue 8.90 million SO2 allowances to utilities annually. The SO2 allowance program will not affect Montaup's Somerset Station or Canal Unit 2 until January 1, 2000. Massachusetts MADEP regulations establish a statewide cap on SO2 emissions and required Montaup's facilities to meet an average emission rate of 1.2 pounds of SO2 per million BTU of fuel input by the end of 1994. Under federal standards, Montaup would not be required to meet this SO2 emission level until the year 2000 as a result of Title IV of the Clean Air Act. However, Massachusetts MADEP regulations require compliance five years earlier. As required by state regulations, Montaup submitted and received approval of a plan detailing how it would meet the 1995 SO2 standard. Montaup is now achieving compliance by substituting lower sulfur content fuels. Other provisions of the Clean Air Act Amendments will likely impact Montaup. Title I of the Act sets a strategy for states to move toward attaining national air quality standards, with the emphasis on meeting the ozone standard. Ozone relates directly to the nation's smog problem. NOx is one of the precursors of ozone formation. Title I requires additional controls on industrial sources of NOx including utility power plants. The Act creates the Northeast Ozone Transport Region, covering the area from Virginia to Maine, including Massachusetts and Rhode Island. Areas within the transport region will become subject to enhanced controls on NOx emissions. In April 1992, NESCAUM, an environmental advisory group for eight Northeast states including Massachusetts and Rhode Island issued recommendations for nitrogen oxide controls for existing utility boilers required to meet the ozone non-attainment requirements of the Clean Air Act Amendments. The NESCAUM recommendations are more restrictive than EPA's requirements. The MADEP and RIDEM have amended their regulations in accordance with the NESCAUM recommendations and require that Reasonably Available Control Technology (RACT) be implemented at all stationary sources potentially emitting 50 tons per year or more of NOx. Montaup has initiated compliance through, among other things, selective, noncatalytic reduction processes. MADEP has proposed regulations which would require additional NOx emission reductions beginning on May 1, 1999. Montaup is evaluating its compliance options under this proposed regulation. Title V of the Clean Air Act Amendments provides EPA with broad new permitting authority, with the goal of having states begin to issue federally enforceable operating permits in 1995 which will outline limits and conditions necessary to comply with all applicable air requirements. The Clean Air Act Amendments' permitting program will be phased in over a couple of years. Montaup submitted its initial Operating Permit Application under this program on May 5, 1995. On September 20, 1995, MADEP issued Montaup an Administrative Completeness Determination and Application Shield for its Operating Permit Application. This application is still under DEP review. Although individual sources will be required to pay fees to the various states which will administer the program, the impact of these requirements is not expected to have a material financial impact on the EUA System. On November 27, 1996, the EPA announced that, under the Clean Air Act, it was proposing to toughen the nation's ozone standards as well as the particulate matter standards. The states will be responsible for writing plans to bring themselves into compliance. States would have until the year 2000 to submit ozone plans and until the year 2002 to submit particulate plans. After that, the states will have a few more years to meet the established goals. At this time, management is unable to predict the financial impact this rule might have on the EUA system, once it is issued in its final form. Once the public comment period is completed, the EPA plans to promulgate final rules in June 1997. On December 23, 1996, Eastern Edison, Montaup, the Massachusetts Attorney General and Division of Energy Resources reached a settlement in principle regarding electric utility restructuring in the State of Massachusetts. The proposed settlement includes a plan for emissions reductions related to Montaup's Somerset Station Units 5 and 6, and to Montaup's 50% ownership share of Canal Electric's Unit #2. The basis for SO2 and NOx emission reductions in the proposed settlement is an allowance cap calculation. Within this allowance cap, the following commitments were made: - 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; - On January 1, 2000, Somerset Units 5 & 6 will comply with an annual SO2 emission rate of 0.30 lbs/mmBtu; - On January 1, 2000, Units 5 & 6 will comply with a NOx emission rate of 0.21 lbs/mmBtu for the seven months outside the ozone season, and 0.15 lbs/mmBtu during the five month ozone season (May through September). The cost Unit 6 must incur to comply with this NOx limit is capped at $405,000 per year until January 1, 2003. Unit 5, if reactivated, will comply with the above NOx limit with no cost cap; and - On January 1, 2010, Canal Electric's Unit #2 will comply with an SO2 emission rate of 0.30 lbs/mmBtu, and a NOx emission rate of 0.15 lbs/mmBtu, on an annual basis; this commitment was made only for Montaup's 50% ownership share of Canal 2. The formal settlement is expected to be submitted to the MDPU in March 1997. Environmental Regulation of Nuclear Power The NRC has promulgated a variety of standards to protect the public from radiological pollution caused by the normal operation of nuclear generating facilities. For example, the NRC requires licensed facilities to develop plans to respond to unexpected developments. In some environmental areas the NRC and the EPA have overlapping jurisdiction. Thus, NRC regulations are subject to all conditions imposed by the EPA and a variety of federal environmental statutes, including obtaining permits for the discharge of pollutants (including heat) into the nation's navigable waters. In addition, the EPA has established standards, and is in the process of reviewing existing standards, for certain toxic air pollutants, including radionuclides, under the Clean Air Act Amendments which apply to NRC- licensed facilities. In fact, in December of 1996, the EPA issued a final rule rescinding previously published limitations on radionuclide emissions to ambient air, as applied to NRC or NRC Agreement state licensed facilities other than commercial nuclear power reactors. The EPA has also promulgated environmental radiation protection standards for nuclear power plants. These standards regulate the doses of radiation received by the general public. The NWPA provides for development by the federal government of facilities for the disposal or permanent storage of civilian nuclear waste. For further details about NWPA, see Fuel for Generation above. The NRC has also promulgated regulations regarding the disposal of nuclear waste materials designed to protect the public from radiological dangers. Environmental regulation of nuclear facilities in which the EUA System has an interest or from which they purchase power may result in significant increases in capital and operating costs, in delays or cancellation of construction of planned improvements, or in modification or termination of existing facilities. Item 2. PROPERTIES Power Supply Montaup currently supplies the EUA System with nearly 100% of its electric requirements. Newport became an all-requirements customer of Montaup on May 21, 1994. At the same time, Montaup assumed all of Newport's power contracts and began leasing all of Newport's generation facilities and a portion of Newport's transmission facilities. In 1996, the EUA System's wholly owned generating units referred to in the following table consisted of Montaup's jet- fueled peaking units (Somerset Jet 1 and Jet 2) and Somerset 6 which was converted from oil to coal burning in 1983, Blackstone's Pawtucket Hydro, which was repowered in 1985 and Newport's diesel peaking units (Eldred in Jamestown and Jepson in Portsmouth) which supply the EUA System with 8 mw and 8.25 mw, respectively. With the exception of Somerset's Jet 1 and Jet 2, Montaup has not significantly increased its wholly owned generating units since 1959. The EUA System has found it more economically beneficial to join with other utilities in the joint ownership of large generating units and in long-term purchase contracts, and to supplement these sources with short-term purchases as required. EUA believes that spreading the EUA System's sources of electricity among a number of plants should improve the reliability of its power supply and limit the financial exposure relating to construction and potentially prolonged outages of a generating unit. Current forecasts indicate that the combination of company owned generation, current long-term purchased power contracts, expected short-term power opportunities, and the System's C&LM programs, should meet EUA System capacity requirements. See Electric Utility Industry Restructuring under "Rhode Island Utility Restructuring Act of 1996" and "Massachusetts Restructuring Settlement" for a discussion of plans to divest all of Montaup's generating assets. The 1996 peak EUA System demand was approximately 854 mw experienced on August 6, 1996.
EUA SYSTEM CAPABILITY GENERATING UNITS IN SERVICE AS OF DECEMBER 31, 1996 GROSS WINTER MAX GROSS NET IN SYSTEM CLAIMED SYSTEM UNIT SYSTEM SERVICE SHARE CAPABILITY SHARE SALES SHARE DATE UNIT NAME FUEL TYPE OWNER/OPERATOR % MW MW MW MW 100% OWNERSHIP: 1959 SOMERSET 6 COAL MONTAUP ELECTRIC CO. 100.00 110.00 110.00 0.00 110.00 1970 SOMERSET J1 JET OIL MONTAUP ELECTRIC CO. 100.00 22.00 22.00 0.00 22.00 1971 SOMERSET J2 JET OIL MONTAUP ELECTRIC CO. 100.00 21.20 21.20 0.00 21.20 1985 PAWTUCKET HYDRO HYDRO BLACKSTONE VALLEY ELEC. 100.00 1.24 1.24 0.00 1.24 1961 JEPSON DIESEL NEWPORT ELECTRIC CORP. 100.00 8.80 8.80 0.00 8.80 1978 ELDRED DIESEL NEWPORT ELECTRIC CORP. 100.00 8.25 8.25 0.00 8.25 SUBTOTAL: 171.49 0.00 171.49 JOINT OWNERSHIP: 1976 CANAL 2 NO. 6 OIL CANAL ELECTRIC COMPANY 50.00 586.00 293.00 60.03 232.97 1978 WYMAN 4 (YAR 4) NO. 6 OIL CENTRAL MAINE POWER CO. 2.63 620.00 16.30 0.00 16.30 1986 MILLSTONE 3 NUCLEAR NORTHEAST UTILITIES 4.01 1145.70 45.93 0.00 45.93 1990 SEABROOK NUCLEAR NORTH ATLANTIC ENERGY CORP 2.90 1162.00 33.70 0.00 33.70 SUBTOTAL: 388.93 60.03 328.90 EQUITY OWNERSHIP: 1972 MAINE YANKEE NUCLEAR MAINE YANKEE ATOMIC POWER 3.59 879.00 31.57 0.00 31.57 1972 VERMONT YANKEE NUCLEAR VT. YANKEE NUCLEAR POWER 2.25 531.00 11.95 0.00 11.95 SUBTOTAL: 43.52 0.00 43.52 PURCHASED POWER: 1968 CANAL 1 NO. 6 OIL CANAL ELECTRIC COMPANY 25.00 562.00 140.50 0.00 140.50 1972 PILGRIM 1 NUCLEAR BOSTON EDISON COMPANY 11.00 670.11 73.71 0.00 73.71 1977 POTTER 2 GAS/OIL BRAINTREE ELEC. LIGHT DEPT 41.67 96.00 40.00 0.00 40.00 1975 CLEARY 9 GAS/OIL TAUNTON MUNIC. LIGHTING 22.73 110.00 25.00 0.00 25.00 1984 MCNEIL WOOD VERMONT ELECTRIC POWER 15.24 53.00 8.08 0.00 8.08 1972 BERLIN A&B JET OIL GREEN MOUNTAIN POWER 22.77 57.10 13.00 0.00 13.00 1974 BEAR SWAMP GT1 HYDRO NEW ENGLAND POWER 5.09 294.50 15.00 0.00 15.00 1974 BEAR SWAMP GT2 HYDRO NEW ENGLAND POWER 5.10 294.00 15.00 0.00 15.00 1990 OSP 1 GAS OCEAN STATE POWER 28.00 287.00 80.36 0.00 80.36 1991 OSP 2 GAS OCEAN STATE POWER 28.00 287.00 80.36 0.00 80.36 1991 NEA GAS NORTHEAST ENERGY ASSOC. 8.62 333.43 28.74 0.00 28.74 1982/1986 STONY BROOK 2A&2B NO. 2 OIL MA MUNIC. WHOLESALE ELEC. 5.88 170.00 10.00 0.00 10.00 1970 NU JETS JET OIL NORTHEAST UTILITIES 25.61 97.60 25.00 0.00 25.00 SUBTOTAL: 554.75 0.00 554.75 HYDRO QUEBEC ENTITLEMENT: 1991 HYDRO QUEBEC I&II HYDRO HQ / NEPOOL 4.06 1215.00 49.31 0.00 49.31 SUBTOTAL: 49.31 0.00 49.31 TOTAL GROSS SYSTEM CAPABILITY (MW) -------------------- 1,208.00 LESS: UNIT CONTRACT SALES (MW) --------------- 60.03 TOTAL NET SYSTEM CAPABILITY (MW) ------------- 1,147.97
Montaup's participation in generating units of which it is not the sole owner takes various forms including stock (equity) ownership, joint ownership and purchase contracts. In most cases (other than short-term purchased power contracts) the purchaser is required to pay its share (i.e., the same percentage as the percentage of its entitlement to the output) of all of the costs of the generating unit (whether or not the unit is operating) including fixed costs, operating costs, costs of additional construction or modification, costs associated with condemnation, shutdown, retirement, or decommissioning of the unit, and certain transmission charges. Under its contracts with Maine Yankee, Connecticut Yankee Atomic Power Company, Vermont Yankee Nuclear Power Corporation and Yankee Atomic and, under its agreements relating to Phase II of the interconnection with Hydro-Quebec, Montaup may be called upon to provide additional capital and/or other types of direct or indirect financial support. (See Item 1. BUSINESS -- Nuclear Power Issues.) Other Property The EUA System owns approximately 4,600 miles of transmission and distribution lines and approximately 85 substations located in the cities and towns served. Blackstone owns approximately 1,000 miles of transmission and distribution lines and approximately 23 substations located in the cities and towns served. Blackstone also owns 100% of a 1.2-mw hydroelectric generating plant located in Pawtucket, Rhode Island. See Note E of Notes to Financial Statements in Blackstone's 1996 Annual Report (Exhibit 13-1.01 filed herewith) regarding encumbrances. Eastern Edison and Montaup own approximately 3,200 miles of transmission and distribution lines and approximately 48 substations located in the cities and towns served. See Note F of Notes to Consolidated Financial Statements in Eastern Edison's 1996 Annual Report (Exhibit 13-1.08 filed herewith) regarding encumbrances. Newport owns approximately 400 miles of transmission and distribution lines and approximately 14 substations located in the cities and towns served. See Note E to Notes to Consolidated Financial Statements contained in EUA's Annual Report to Shareholders for the year ended December 31, 1996, (Exhibit 13-1.03 filed herewith) regarding encumbrances. In addition to the above, the Retail Subsidiaries, Montaup, and EUA Service also own several buildings which house distribution, maintenance or general office personnel. See Note E of Notes to Consolidated Financial Statements contained in EUA's Annual Report to Shareholders for the year ended December 31, 1996, (Exhibit 13-1.03 filed herewith) regarding encumbrances. Item 3. LEGAL PROCEEDINGS Rate Proceeding See descriptions of proceedings under Item 1, BUSINESS -- Rates. Environmental Proceedings 1. In March 1985, Blackstone was notified by the DEQE, which is now the MADEP, that it had been identified, along with other parties, as a potentially responsible party under Massachusetts law for a condition of soil and ground water contamination in Lowell, Massachusetts. The site in question was occupied by a scrap metal reclamation facility which received transformers and other electrical equipment from utility companies and others from the early 1960s until 1984. Among the contaminants apparently released at the site were PCBs. The potentially responsible parties (PRPs), including Blackstone, performed site studies and proposed a remedial action plan, which was approved by the DEQE several years ago. Since that time, the PRPs have negotiated over access, taxes and similar issues with the site owner and other parties. The remedial option selected but not yet completed is a process of solidification; however, a risk assessment that may now be required could lead the PRPs to choose capping as the remedial option. The cost of implementing either remedy could vary from $250,000 for capping to $600,000 for solidification. Blackstone is alleged to be the fifth ranked generator out of approximately twenty potentially responsible parties. However, Blackstone's estimated 2% share allocation is considerably less than the shares of the four largest contributors at the site. As a result, Blackstone expects to be offered a de minimis party buyout settlement from the major members of the site PRPs. 2. On July 14, 1987, the Commonwealth of Massachusetts (the Commonwealth) on behalf of the MADEP filed a cost recovery action pursuant to CERCLA and Mass. Gen. Laws Chapter 21E against Blackstone in the United States District Court for the District of Massachusetts (District Court). The Complaint seeks $2.2 million in costs incurred by MADEP in the cleanup of an alleged coal gasification waste site at Mendon Road in Attleboro, Massachusetts. In October 1987, without admitting liability, Blackstone entered into an administrative Consent Order with MADEP regarding the Mendon Road site and another alleged coal gasification site discovered by the MADEP approximately 1/4 mile away known as the Lawn/Knoll site in Attleboro. Blackstone agreed to perform preliminary assessments at both sites in order to determine what remediation, if any, was necessary at the site. In 1988, Blackstone submitted Phase II testing results for the Lawn/Knoll site to the MADEP for review and approval. On April 24, 1996, MADEP ordered Blackstone to conduct additional site assessment work at the Lawn Street site. Blackstone retained the services of Atlantic Environmental Services to conduct the site assessment pursuant to the Massachusetts Contingency Plan and on August 15, 1996 Blackstone signed an amended Administrative Consent Order Tier IB permit. It is expected that Atlantic will begin the site assessment work in the Spring of 1997. On May 26, 1993, the MADEP requested Blackstone to submit additional Phase I testing for the Mendon Road site which was completed and sent to the MADEP on December 20, 1993. Meanwhile, Blackstone has contested the MADEP's cost recovery action, arguing, inter alia, that the waste removed from the Mendon Road site, ferric ferrocyanide (FFC), was not "hazardous" within the meaning of CERCLA or Mass. Gen. Laws Chapter 21E and the MADEP's cleanup actions were inconsistent with the National Contingency Plan (NCP). On November 25, 1991, the District Court held that the waste was "hazardous" within the meaning of both statutes and on December 20, 1992, the District Court held Blackstone and a co- defendant, the Courtois Sand & Gravel Co. (Courtois) liable for an undetermined amount of cleanup costs. The District Court remanded the case to the MADEP to supplement the administrative record with Blackstone's oral and written comments concerning the cleanup. On March 19, 1993, Blackstone made an oral presentation to the MADEP and on April 19, 1993, Blackstone submitted written comments. On December 13, 1994, the District Court issued a judgment against Blackstone finding Blackstone liable to the Commonwealth for the full amount of response costs incurred by the Commonwealth in the cleanup of the Mendon Road site. The judgment also found Blackstone liable for interest and litigation expenses calculated to the date of judgment. The total liability at December 31, 1994 was approximately $5.9 million, including approximately $3.6 million in interest which has accumulated since 1985. 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. Blackstone filed a Notice of Appeal of the District Court's judgment and filed its brief with the United States Court of Appeals for the First Circuit (Circuit Court) on February 24, 1995. On October 6, 1995, the Circuit Court vacated the District Court's $5.9 million judgement. Rather than remand the case to the District Court for a trial on the issue of whether ferric ferrocyanide (FFC) is a hazardous substance, the Circuit Court exercised its primary jurisdictional powers to send the matter to the EPA for an administrative determination on the issue. If the EPA determines that FFC is not a hazardous substance, given the present posture of the case, Blackstone may not be liable to reimburse the Commonwealth for the Mendon Road cleanup costs. On January 9, 1997, Blackstone met with representatives of EPA and the Commonwealth to discuss the procedure EPA would follow in resolving the FFC issue. In January 1997, Blackstone submitted written comments to be followed by the Commonwealth's written reply. EPA will then determine whether FFC is hazardous substance. Further court proceedings are likely. On January 28, 1994, Blackstone filed a Complaint in the Massachusetts 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. Blackstone's Complaint also seeks a declaratory judgment that Stone & Webster and Valley owned and/or operated a coal gasification plant on Tidewater Street in Pawtucket (the Tidewater Plant) where the coal gasification waste allegedly was generated, and that they individually or collectively arranged for the disposal of such waste at Mendon Road. The District Court has denied motions to dismiss the complaint filed by Stone & Webster and Valley in 1994. This proceeding was stayed in December 1995 pending final EPA determination as to whether FFC is a hazardous substance. On March 22, 1996, Blackstone and Valley filed a Complaint in the Rhode Island District Court seeking contribution from Stone & Webster for the cleanup of the Tidewater site mentioned below. Blackstone has notified certain liability insurers and has filed claims with respect to the Mendon Road site. Blackstone is actively pursuing coverage from other carriers for the Mendon Road, Tidewater, Lawn/Knoll, Cumberland, and Woonsocket Sites. 3. On October 28, 1986, RIDEM notified Blackstone that there may have been a release of hazardous material at the Tidewater Plant site in Pawtucket, Rhode Island. The site was placed on EPA's CERCLA list in 1987. The site includes the Tidewater Plant owned by Valley Gas Company (approximately 10 acres), the No. 1 Station owned by Blackstone (approximately 10 acres), and land formerly owned by Blackstone that was sold in 1968 to the City of Pawtucket (approximately 10 acres). RIDEM told Blackstone that the site contained hazardous wastes and petroleum-contaminated soils due to tanks formerly located at the site. In December, 1990, after obtaining approval from RIDEM, Blackstone removed approximately 1,000 tons of soil from the site. On September 3, 1991, RIDEM initiated a site investigation which constitutes the second step in a site screening and assessment process established by the EPA to determine whether the site should be listed as a Superfund site. On February 3, 1993, RIDEM notified Blackstone that it required further assessment and evaluation of site conditions to determine if the site qualifies for review pursuant to the Hazardous Ranking System. On September 12, 1995, RIDEM notified Blackstone and Valley of their responsibility regarding the release of hazardous substances at the Tidewater Plant site. RIDEM ordered Blackstone and Valley to conduct an environmental study of the Tidewater Plant site and adjoining lots. On the adjacent lots are the Francis J. Varieur Elementary School and the Max Read Field athletic facility and ball fields. Blackstone and Valley have entered into an agreement to share the expenses of conducting the study and/or retaining an environmental consulting firm to conduct a Remedial Investigation. A work plan was submitted to RIDEM in April 1996 and it was approved on June 14, 1996. Field work was completed in September 1996. RIDEM is currently reviewing the draft Remedial Investigation Report. It is expected that RIDEM will order further investigation and remedial clean up. On September 12, 1995, RIDEM demanded payment of $296,000 which represents the amount of money plus interest RIDEM expended to clean up oxide box waste at the Cumberland, Rhode Island site. Following extended discussions and negotiations with legal counsel on behalf of RIDEM, Blackstone was able to reach an agreement with RIDEM to escrow approximately $296,000 in an interest- bearing account pending the outcome of EPA's remand proceedings to determine whether FFC is a hazardous substance. This money has been placed in an interest-bearing escrow account by Blackstone pending the outcome of EPA's proceedings. If Blackstone convinces EPA that FFC is not a hazardous substance, Blackstone will be able to recover the escrowed funds on the basis that RIDEM's clean up of the site in 1986 was not required by law. If EPA determines that FFC is a hazardous substance, Blackstone will pursue its legal remedies in district court in Massachusetts to convince the court that FFC is not a hazardous substance. On January 10, 1997, Blackstone, Valley, and a representative of RIDEM met at Valley's Woonsocket property, which is the site of a former manufactured gas plant owned by Blackstone's and Valley's predecessor, Blackstone Valley Gas & Electric company and its predecessor, the Woonsocket Gas Company. It is anticipated the RIDEM will order Blackstone and Valley to conduct a site assessment of the site in 1997. 4. Montaup and EUA Service received a Notice of Responsibility on July 27, 1987, from the MADEP for suspected hazardous material at a site owned by Montaup on Hortonville Road in Swansea, Massachusetts. Montaup has completed investigative and remedial actions in accordance with new Massachusetts Contingency Plan regulations. The total cost of the cleanup was less than $150,000. 5. During March-April 1990, Eastern Edison conducted a limited environmental investigation (Phase I study) of a portion of its Dupont Substation in Brockton, Massachusetts. During the investigation, Eastern Edison notified the MADEP that it had encountered oils and PCBs. On May 3, 1990, the MADEP notified Eastern Edison of its liability for releases of oil and/or hazardous materials at the site, and requested a copy of the Phase I study. Following its review of the Phase I study on January 23, 1991, the MADEP issued a Notice of Responsibility to Eastern Edison requiring a Phase II - - - Comprehensive Site Investigation. A scope of work for the Phase II study was submitted on April 12, 1991. In August 1994 a transition statement issued by MADEP reclassifying the site from a Tier IA site to a Tier IB site was signed by Eastern Edison and submitted to MADEP. That reclassification enabled the site to be investigated and cleaned up under the guidance of a licensed site professional without MADEP approval for each action taken. Cleanup activities were completed in 1996 in accordance with DEP regulations and an Activity and Use Limitation was filed for the site. The total cost of the cleanup was approximately $550,000. 6. In November 1996, oily deposits containing PCB were found in the Canal Electric gas pipeline lateral and certain in-plant equipment. This contamination was a result of a malfunction of a shut-off valve in the meter station outside of Canal plant's jurisdiction. Cleanup and improvement costs are estimated to be between $500,000 and $1 million. Pending final cost allocation and reimbursement, Montaup's share of the costs is expected to be minimal. The cleanup is scheduled for completion in the first quarter of 1997. Blackstone, Eastern Edison, Montaup and EUA Service are unable to predict the outcome of any of the foregoing environmental matters or to estimate the potential costs which may ultimately result. It is the policy of these companies in such cases to provide notice to liability insurers and to make claims. However, it is not possible at this time to predict whether liability, if any, will be assumed by, or can be enforced against, the insurance carriers in these matters. Under CERCLA, each responsible party can be held "jointly and severally" liable for clean-up costs. EUA or a subsidiary could thus be held fully liable for environmental damages for which they were only partially responsible. However, EUA might then be entitled to recover costs from other PRPs. As of December 31, 1996, the EUA System has incurred costs of approximately $5.7 million (excluding the Mendon Road judgment) in connection with the foregoing environmental matters. EUA estimates that additional expenditures (excluding the Mendon Road judgment) may be incurred through 1998 of up to $2.8 million, substantially all of which relate to Blackstone. As a general matter, the EUA System will seek to recover costs relating to environmental proceedings in their rates. Blackstone is recovering in rates certain of its incurred costs over a five-year period. Montaup is currently recovering certain of its incurred costs in its rates. Estimated amounts after 1998 are not now determinable since site studies which are the basis of these estimates have not been completed. As a result of the recoverability in current rates and the uncertainty regarding both its estimated liability, as well as 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. EUA WestCoast L.P. In June 1993, EUA WestCoast L.P., a partnership in which EUA Cogenex is the managing partner, filed a lawsuit against the contractors responsible for the design and construction of a 1.5 mw cogeneration facility, as well as the surety which issued a performance bond guaranteeing construction. Certain defendants in that action have filed cross-complaints against EUA WestCoast and EUA Cogenex, seeking, among other things, approximately $300,000 for payments withheld by EUA WestCoast due to the contractor's deficient performance, contribution and indemnity. A contractor has also filed a cross-complaint against the host. Additionally, the host has filed a cross-complaint against EUA Cogenex and the other parties in the litigation, seeking approximately $7 million in damages arising principally from lost economic advantage. EUA WestCoast filed its own cross complaint against the host affirmatively seeking damages. The above litigation was settled in the fourth quarter of 1996. The settlement called for, among other things, a payment to EUA Cogenex of $2.8 million and a general release by all parties to the lawsuit. The settlement was enforced by the courts and payment was received in December 1996. Ridgewood In September 1995, EUA FRC II Energy Associates, Micro Utility Partners of America, L.P., and EUA Westcoast, L.P., each of which is a partnership of which EUA Cogenex is the managing partner (the Partnerships) and EUA Cogenex entered into an assignment agreement with Ridgewood/Mass. Corp. (f/k/a Ridgewood Cogen Corporation) (Ridgewood) whereby Ridgewood acquired the benefits and obligation to certain cogeneration projects from EUA Cogenex and the Partnerships. In 1996, the Partnerships and EUA Cogenex filed a suit in the United States District Court for the district of Massachusetts against Ridgewood and others seeking payment of approximately $518,000, resulting from Ridgewood's failure and refusal to pay for services provided on their behalf under a certain Transition Period Agreement between and among the parties. On December 2, 1996, Ridgewood filed a demand for arbitration in Boston, Massachusetts with regard to such claim and with regard to an alleged breach of representations and warranties by EUA Cogenex and the Partnerships under the assignment agreement. Ridgewood seeks a total of approximately $4.3 million. The federal court action has been dismissed without prejudice pending the arbitration. In the arbitration, EUA Cogenex and the Partnerships have filed a counterclaim in which they also seek a determination that certain provisions of the assignment agreement are binding and enforceable according to their terms. The amount in controversy with respect to the counterclaims has not yet been determined. Management cannot determine at this time the ultimate outcome of these proceedings. Other Proceedings On December 15, 1995, Eastern Edison exercised its right to terminate a Power Purchase Agreement (PPA) entered into with the Meridian Middleboro Limited Partnership (MMLP) and a related entity on September 20, 1993. In February and May of 1996, MMLP made demands for over $25 million under the termination provision of the PPA. On June 17, 1996, Eastern Edison responded to MMLP's demand stating that only approximately $170,000 was due under the termination provision. On July 18, 1996, Eastern Edison filed a declaratory judgement action in Suffolk Superior Court in Boston, Massachusetts against MMLP seeking a declaration of the rights of the parties under the PPA. MMLP's response to the complaint, filed on August 8, 1996, included counter claims in excess of $20 million and a request for treble damages. In response to the counter claim, Eastern Edison paid MMLP approximately $192,000 as the amount Eastern Edison considered to have been owed to MMLP. The Company is vigorously defending itself from the counter claims. The Company cannot determine the outcome of this proceeding at this time. On January 10, 1997, the Internal Revenue Service (IRS) issued a report in connection with its examination of the consolidated income tax returns of EUA for 1992 and 1993. The report includes 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 relating to the redemption of EUA Power's Common and Preferred Stock in 1993. The IRS has taken the position that the redemption of the Preferred Stock resulted in a capital loss transaction and not a deduction in determining ELA. The Company disagrees with the IRS's position and filed a protest in March 1997. EUA believes that it will ultimately prevail in this matter. However, if the ultimate resolution of this matter is a favorable decision for the IRS and EUA does not have sufficient capital gain transactions to offset the capital loss then EUA could be required to record a charge that could have a material impact on financial results in the year of the charge but would not materially impact the financial position of the company. In early 1997, ten plaintiffs brought suit 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 is $25 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, and EUA is consulting with those insurers to determine the availability and extent of coverage. EUA cannot predict the ultimate outcome of this matter at this time. Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY-HOLDERS None. EXECUTIVE OFFICERS OF EASTERN UTILITIES ASSOCIATES The names, ages and positions of all of the executive officers of EUA as of March 17, 1997, are listed below along with their business experience during the past five years. Officers are elected annually by the Trustees at the following meeting of Trustees after the annual meeting of shareholders. The 1997 Annual Meeting of Shareholders is scheduled to be held on May 19, 1997. There are no family relationships among these officers, nor any arrangement or understanding between any officer and any other person pursuant to which the officer was selected. The executive officers also serve as officers/or directors of various subsidiary companies. Name, Age and Position Business Experience During Past 5 Years Richard M. Burns, 59 Comptroller since 1976; Assistant Secretary since Comptroller 1978; and Assistant Treasurer since April 1986. Chief Accounting Officer of EUA. John D. Carney, 52 Executive Vice President since April 1995; Executive Vice President President of Eastern Edison Company since January 1990; President of Blackstone since April 1995. Responsible for the day-to-day activities of The EUA System's retail electric operations. Clifford J. Hebert, Jr., 49 Treasurer since April 1986; Secretary since May, Treasurer and 1995. Responsible for financial, treasury and Secretary corporate affairs of the EUA System . Donald G. Pardus, 56 Chairman since July 1990; Chief Executive Chairman of the Board, Officer since April 1989. Responsible for Chief Executive Officer the overall management of the EUA System. and Trustee Robert G. Powderly, 49 Executive Vice President since April 1992; Executive Vice President President of Newport Electric Corporation from March 1990 to April 1992. Responsible for purchasing, customer information services, information systems, human resources, marketing and rate activities of the EUA System. John R. Stevens, 56 President since July 1990; Chief Operating President, Chief Operating Officer since January 1990; Senior Executive Vice Officer and Trustee President from January 1990 to July, 1990. Responsible for retail operations and new ventures of the EUA System. There have been no events under any bankruptcy act, no criminal proceedings and no judgments or injunctions material to the evaluation of the ability and integrity of any director or executive officer during the past five years. PART II Item 5. MARKET FOR EUA'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS The information set forth under the caption "QUARTERLY FINANCIAL AND COMMON SHARE INFORMATION" included in EUA's Annual Report to Shareholders for the year ended December 31, 1996 (Exhibit 13-1.03 filed herewith) is incorporated herein by reference. The information required by this item for Blackstone and Eastern Edison is incorporated by reference to information contained under the like captioned sections of Blackstone's and Eastern Edison's 1996 Annual Reports (Exhibit 13- 1.01 and 13-1.08, respectively, filed herewith). As of February 1, 1997 there were 11,978 EUA common shareholders of record. The closing price of EUA's Common Shares as reported by the Wall Street Journal on March 17, 1997 was $18.125. Item 6. SELECTED FINANCIAL DATA The information set forth under the caption "SELECTED CONSOLIDATED FINANCIAL DATA" included in EUA's Annual Report to Shareholders and Eastern Edison's Annual Report for the year ended December 31, 1996, (Exhibit 13-1.03 and 13-1.08, respectively, filed herewith) and the information set forth under the caption "SELECTED FINANCIAL DATA" included in the Annual Report for the year ended December 31, 1996 for Blackstone (Exhibits 13-1.01 filed herewith) are incorporated herein by reference. Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The information required by this item is incorporated herein by reference to pages 11 through 24 in the 1996 EUA Annual Report to Shareholders, pages 3 through 7 in the 1996 Blackstone Annual Report and pages 3 through 10 in the 1996 Eastern Edison Annual Report (Exhibits 13-1.03, 13-1.01 and 13-1.08 for EUA, Blackstone and Eastern Edison , respectively, filed herewith). Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The information required by this item is incorporated herein by reference to pages 26 through 41 in the 1996 EUA Annual Report to Shareholders, page 2 and pages 10 through 27 in the 1996 Blackstone Annual Report and, page 2 and pages 13 through 33 in the 1996 Eastern Edison Annual Report (Exhibits 13-1.03, 13-1.01 and 13-1.08 for EUA, Blackstone and Eastern Edison, respectively, filed herewith). Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES None. PART III Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS Eastern Utilities Associates The information concerning trustees and executive officers set forth under the caption "ELECTION OF TRUSTEES AND OWNERSHIP OF COMMON SHARES" in EUA's definitive Proxy Statement to be mailed to shareholders in connection with the shareholders' annual meeting to be held on May 19, 1997, and filed with the SEC is incorporated herein by reference. See also "EXECUTIVE OFFICERS OF EASTERN UTILITIES ASSOCIATES" following Item 4 herein. Blackstone and Eastern Edison The names, ages and positions of all of the directors and executive officers of Blackstone and Eastern Edison as of March 17, 1997 are listed below with their business experience during the past five years. The directors of Blackstone and the directors, Treasurer and Clerk of Eastern Edison are each elected to serve until the next annual stockholders' meeting. All other officers are elected to serve until the next meeting of directors following the annual stockholders' meeting. There is no family relationship between any of the directors or officers of Blackstone and Eastern Edison. Messrs. Pardus and Stevens are Trustees of EUA. Certain officers of Blackstone and Eastern Edison are, or at various times in the past have been, officers and/or directors of the System Companies with which Blackstone and Eastern Edison have entered into contracts and had other business relations. Name, Age and Position Business Experience During Past 5 Years Richard M. Burns, 59* Vice President, Assistant Treasurer and Assistant Vice President Clerk/Assistant Secretary of Blackstone and Eastern Edison since April 1986. John D. Carney, 52* President and Director of Blackstone since April Director and President 1995; President and Director of Eastern Edison since January 1990. David H. Gulvin, 62 Senior Vice President of Blackstone and Eastern Senior Vice President Edison since April 1995; President of Blackstone and Director from November 1989 to April 1995; Director of Blackstone since November 1989. Director of Eastern Edison since July 1995. Responsible for corporate communications, consumer services, marketing and rate activities. Barbara A. Hassan, 47 Vice President of Blackstone since April 1995; Vice President Vice President of Eastern Edison since January 1990. Responsible for the operation and maintenance of the transmission and distribution facilities. Clifford J. Hebert, Jr., 49* Treasurer since April 1986 and Secretary/Clerk Treasurer since April 1995 of both Blackstone and Eastern and Secretary/Clerk Edison. Michael J. Hirsh, 42 Vice President of Blackstone since July 1991; Vice President Vice President of Eastern Edison since April 1995; Prior to that he was either a Director or Manager of the Engineering or Resource Planning Departments of EUA Service for more than five years. Responsible for all engineering and technical services. Kevin A. Kirby, 46 Vice President of Blackstone and Eastern Edison Vice President since April, 1995; prior to that he was a Director of the Integrated Resource Management department of EUA Service for five years; responsible for the resource planning, power supply and contract administration activities of the EUA System. Donald G. Pardus, 56* Chairman of the Board since July 1989 and Director and Director since 1979 of both Blackstone and Chairman of the Board Eastern Edison. Robert G. Powderly, 49* Executive Vice President and Director since March Director and Executive 1992 of both Blackstone and Eastern Edison. Vice President John R. Stevens, 56* Vice Chairman of the Board since July 1989 and Director and Vice Director since July 1987 of both Blackstone and Chairman of the Board Eastern Edison. * Please refer to the material supplied under the caption "EXECUTIVE OFFICERS OF EASTERN UTILITIES ASSOCIATES" following Item 4 herein for other information regarding this officer. Item 11. EXECUTIVE COMPENSATION Eastern Utilities Associates The information concerning executive compensation set forth under the caption "COMPENSATION AND OTHER TRANSACTIONS" in EUA's definitive Proxy Statement to be mailed to shareholders in connection with the shareholders' annual meeting to be held on May 19, 1997 and filed with the SEC is incorporated herein by reference with the exception of the Report of the Compensation and Nominating Committee on Compensation of Executive Officers and accompanying Corporate Performance Graph that appears therein and which are specifically not incorporated herein by reference. Blackstone and Eastern Edison The Chief Executive Officer and the four other most highly compensated executive officers of Blackstone and Eastern Edison hold the same or similar positions with EUA and are not paid directly by either Blackstone or Eastern Edison. The information required by this item is incorporated herein by reference to the material under the caption "COMPENSATION AND OTHER TRANSACTIONS" in the definitive Proxy Statement of EUA, dated March 26, 1997, with the exception of the Report of the Compensation and Nominating Committee on Compensation of Executive Officers and accompanying Corporate Performance Graph that appears therein and which are specifically not incorporated herein by reference. Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT (a) Security ownership of certain beneficial owners of Blackstone and Eastern Edison.
Amount (number of Name and Address of shares) and Nature of Percent of Title of Class Beneficial Owner Beneficial Ownership Class Common Stock Eastern Utilities Associates 2,891,357 of Eastern Edison* 100% One Liberty Square 184,062 of Blackstone* 100% Boston, Massachusetts
_______________ *All shares, which are the only voting securities of Eastern Edison and Blackstone, are registered in the name of the beneficial owner. (b) Security ownership of certain beneficial owners of EUA and management of EUA, Blackstone and Eastern Edison. The statements concerning security ownership of certain beneficial owners and management set forth under the caption "ELECTION OF TRUSTEES AND OWNERSHIP OF COMMON SHARES" in EUA's definitive Proxy Statement to be mailed to shareholders in connection with the shareholders' annual meeting to be held on May 19, 1997 and filed with the SEC are incorporated herein by reference. Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS None. PART IV Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (a)(1) Financial Statements The response to this portion of Item 14 is set forth under Item 8. (a)(2) Financial Statement Schedules The following additional consolidated financial statement schedules filed herewith for EUA and Blackstone should be considered in conjunction with the financial statements in the EUA's Annual Report to Shareholders and Blackstone's Annual Report for the year ended December 31, 1996 (Exhibit 13- 1.03 and 13-1.01, respectively, filed herewith): 1. Financial Statement Schedules: EUA Schedule II - Valuation and Qualifying Accounts for the three years ended December 31, 1996. Blackstone Schedule II - Valuation and Qualifying Accounts for the three years ended December 31, 1996. (a)(3) Exhibits (*denotes filed herewith). Articles of Incorporation and By-Laws: -EUA- 3-1.03 - Declaration of Trust of EUA, dated April 2, 1928, as amended (Exhibit A-3, File No. 70-3188; Exhibit 1 to EUA's 8-K Reports for April in each of the years 1957, 1962, 1966, 1968, 1972, and 1973, File No. 1-5366; Exhibit A-1 (a), Amendment No. 2 to Form U-1, File No. 70-5997; Exhibit 4-3, Registration No. 2-72589; Exhibit 1 to Certificate of Notification, File No. 70-6713; Exhibit 1 to Certificate of Notification, File No. 70-7084; Exhibit 3-2, Form 10-K of EUA or 1987, File No. 1-5366). - Eastern Edison - 3-1.08 - Form of Restated and Amended Articles of Organization (filed as Exhibit B-1 to Form U5S of EUA for 1993). Instruments Defining the Rights of Shareholders, Including Indentures: - Eastern Edison - 4-1.08 - Indenture of First Mortgage and Deed of Trust dated as of September 1, 1948 of Eastern Edison (Exhibit 4-1, Registration No. 2-77468), and twenty-six supplements thereto (Exhibit A, File No. 70-3015; Exhibit A-3, File No. 70-3371; Exhibit C to Certificate of Notification, File No. 70-3371; Exhibit D to Certificate of Notification, File No. 3619; Exhibit D to Certificate of Notification, File No. 70-3798; Exhibit F to Certificate of Notification, File No. 70-4164; Exhibit D to Certificate of Notification, File No. 70-4748; Exhibit C to Certificate of Notification, File No. 70-5195; Exhibit F to Certificate of Notification, File No. 70-5379; Exhibit C to Certificate of Notification, File No. 70-5719; Exhibit 5-24 Registration No. 2- 65785; Exhibit F to Certificate of Notification, File No. 70-6463; Exhibit C to Certificate of Notification, File No. 70-6608; Exhibit C to Certificate of Notification, File No. 70-6737; Exhibit F to Certificate of Notification, File No. 70-6851; Exhibit 4-31, Form 10-K of EUA for 1984, File No. 1-5366; Exhibit F to Certificate of Notification, File No. 70-7254; Exhibit C to Certificate of Notification, File No. 70-7373; Exhibit C to Certificate of Notification, File No. 70-7373; Exhibit C to Certificate of Notification, File No. 70-7373; Exhibit F to Certificate of Notification, File No. 20-7511; Exhibit 4-34, Form 10-K of Eastern Edison for 1990, File No. 0-8480; Exhibit 4-24, Form 10-K of Eastern Edison for 1992, File No. 0-8480; Exhibit 4-35, Form 10-K of Eastern Edison for 1990, File No. 0-8480; Exhibit 4-36, Form 10-K of Eastern Edison for 1990, File No. 0- 8480; Exhibit C-33 to Form U5S of EUA for 1993; Exhibit C-34 to Form U5S of EUA for 1993; Exhibit 4-29.08, Form 10-K of Eastern Edison for 1994, File No. 0-8480). - Montaup - 4-1.05 - Form of 8% Debenture Bonds due 2000 of Montaup (Exhibit 4-10, Registration No. 2-41488). 4-2.05 - Form of 8-1/4% Debenture Bonds due 2003 of Montaup (Exhibit B-3, Form U5S of EUA for year 1973). 4-3.05 - Form of 14% Debenture Bonds due 2005 of Montaup (Exhibit 4-11, Registration No. 2-55990). 4-4.05 - Form of 10% Debenture Bonds due 2008 of Montaup (Exhibit 5-3, Registration No. 2-65785). 4-5.05 - Form of 16-1/2% Debenture Bonds due 2010 of Montaup (Exhibit 4-11, Form 10-K of EUA for 1980, File No. 1-5366). 4-6.05 - Form of 12-3/8% Debenture Bonds due 2013 of Montaup (Exhibit 4-13, Form 10-K of EUA for 1983, File No. 1-5366). 4-7.05 - Form of 10-1/8% Debentures due 2008 of Montaup (Exhibit 4, Form 10-Q of Eastern Edison for quarter ended September 30, 1983, File No. 0-8480). 4-8.05 - Form of 9% Debenture Bonds due 2020 of Montaup (Exhibit 4-10, Form 10-K of Eastern Edison for 1990, File No. 0-8480). 4-9.05 - Form of 9 3/8% Debenture Bonds due 2020 of Montaup (Exhibit 4-11, Form 10-K of Eastern Edison for 1990, File No. 0-8480). - Blackstone - 4-1.01 - First Mortgage Indenture and Deed of Trust dated as of December 1, 1980 of Blackstone (Exhibit A, Form 8-K of EUA dated January 14, 1981, File No. 1-5366) and two supplements thereto (Exhibit 4-33, Form 10-K of EUA for 1989, File No. 1-5366; Exhibit 4-3, Form 10-K of BVE for 1990, File No. 0-2602). 4-4.01 - Loan Agreement between Rhode Island Industrial Facilities Corporation and Blackstone dated as of December 1, 1984 (Exhibit 10-72, Form 10-K of EUA for 1984, File No. 1-5366). - EUA Service - 4-1.07 - Note Purchase Agreement dated as of January 13, 1988 of Service (Exhibit 4-38, Form 10-K of EUA for 1987, File No. 1-5366). - EUA Cogenex - 4-1.10 - Note Agreement dated as of June 28, 1990 of EUA Cogenex with the Prudential Insurance Company of America (Exhibit 4-46, Form 10-K of EUA for 1990, File No. 1-5366). 4-2.10 - Note Agreement dated as of October 29, 1991 between EUA Cogenex and Prudential Insurance Company of America (Exhibit 4-55, Form 10-K of EUA for 1991, File No. 1-5366). 4-3.10 - Note Purchase Agreement dated as of September 29, 1992 of EUA Cogenex and the Prudential Life Insurance Company of America (Exhibit 4-44, Form 10-K of EUA for 1992, File No. 1-5366). 4-4.10 - Indenture dated September 1, 1993 between EUA Cogenex and the Bank of New York as Trustee (Exhibit 4-4.10, Form 10-K of EUA for 1993, File No. 1-5366). - Newport - 4-1.14 - Indenture of First Mortgage dated as of June 1, 1954 of Newport, as supplemented on August 1, 1959, April 1, 1962, October 1, 1964, April 1, 1967, September 1, 1969, September 1, 1970, June 1, 1978, October 1, 1978, May 1, 1986, December 1, 1987 and November 1, 1989 (Exhibit 4-49, Form 10-K of EUA for 1990, File No. 1-5366). 4-2.14 - United States Government Small Business Administration Loan to Newport entitled, "Base Closing Economic Injury Loan", signed May 30, 1975 and amended on October 6, 1983 (Exhibit 4-50, Form 10-K of EUA for 1990, File No. 1-5366). 4-3.14 - Indenture of Second Mortgage dated as of September 1, 1982 of Newport, as supplemented on December 1, 1988 (Exhibit 4-51, Form 10-K of EUA for 1990, File No. 1-5366). 4-4.14 - Loan Agreement between the Rhode Island Port Authority and Economic Development Corporation and Newport Electric Corporation dated as of January 6, 1994 (Exhibit 4-4.14, Form 10-K of EUA for 1993, File No. 1-5366). 4-5.14 - Trust Indenture between the Rhode Island Authority and Economic Development Corporation and Newport Electric Corporation dated as of January 1, 1994 (Exhibit 4-5.14, Form 10-K of EUA for 1993, File No. 1-5366). 4-6.14 - Letter of Credit and Reimbursement Agreement dated January 6, 1994 (Exhibit 4-6.14, Form 10-K of EUA for 1993, File No. 1-5366). - EUA Ocean State - 4-1.12 - Note Purchase Agreement dated as of January 16, 1992 between EUA Ocean State Corporation and John Hancock Mutual Life Insurance Company (Exhibit 4-56, Form 10-K of EUA for 1991, File No. 1- 5366). Material Contracts: - EUA - 10-1.03 - Employees' Retirement Plan of Eastern Utilities Associates and its Subsidiary Companies Trust Agreement as amended and restated, effective July 1, 1981 (Exhibit 10-1, Registration No. 2-80205). 10-2.03 - Eastern Utilities Associates Employees' Savings Plan Trust Agreement (Exhibit 10-3, Form 10-K of EUA for 1992, File No. 1- 5366). 10-3.03 - Eastern Utilities Associates Employees' Savings Plan as amended and restated effective January 1, 1989 and December 21, 1994 (Exhibit 10-4, Form 10-K of EUA for 1992, File No. 1-5366; Exhibit 10-17.03 Form 10-K of EUA for 1995, File No. 1-5366). 10-4.03 - Stock Purchase Agreement dated as of December 10, 1986, among Eastern Utilities Associates, Citizens Corporation and Citizens Energy Corporation (Exhibit 10-104, Form 10-K of EUA for 1986, File No. 1-5366). 10-5.03 - Precedent Agreement dated as of November 29, 1989 between EUA and NECO Enterprises, Inc. (Exhibit B-4, Form U-1, File No. 70-7677). 10-6.03 - Amendment to and Restatement of Stock Purchase Agreement dated as of February 1, 1990 between EUA, NECO Enterprises, Inc., Newport Electric Corporation and a special-purpose subsidiary of EUA for the acquisition by EUA of the stock of Newport Electric Corporation (Exhibit B-3, Form U-1, File No. 70-7677). 10-7.03 - Letter of Assurance in connection with the Credit Agreement between Vermont Electric Transmission Company, Inc. and Bank of America National Trust and Savings Association dated July 19, 1983 (Exhibit 10-111, Form 10-K of EUA for 1990, File No. 1-5366). 10-8.03 - Amended and Restated Equity Maintenance Agreement dated as of September 29, 1992 among EUA and The Prudential Insurance Company of America and Pruco Life Insurance Company (Exhibit 10-9, EUA 10- K for 1992, File No. 1-5366). 10-9.03 - Guaranty, dated June 28, 1990 made by EUA in favor of The Prudential Life Insurance Company of America (Exhibit 10-10, EUA 10-K for 1992, File No. 1-5366). 10-10.03 - Guaranty, dated January 16, 1992 made by EUA in favor of John Hancock Mutual Life Insurance Company (Exhibit 4-125, Form 10-K of EUA for 1991, File No. 1-5366). 10-11.03 - Form of Service Contract between EUA Service Corporation and each of the other companies (including EUA) in the EUA System (Exhibit 13-1.03, Registration No. 2-55990). 10-12.03 - Form of EUA Restricted Stock Plan effective July 17, 1989 (Exhibit 10-13, EUA Form 10-K for 1992, File No. 1-5366). 10-13.03 - Eastern Utilities Associates Employees' Share Ownership Plan Trust Agreement (Exhibit 5, Form 10-K of EUA for 1977, File No. 1-5366). 10-14.03 - Employees' Retirement Plan of Eastern Utilities Associates and Its Affiliated Companies as amended and restated effective January 1, 1989, and December 21, 1994 (exhibit 10-14.03, Form 10-K of EUA for 1995, File No. 1-5 366; Exhibit 10-16.03, Form 10-K of EUA for 1995, File No. 1-5366). - Eastern Edison - 10-1.08 - Trust Agreement dated as of July 1, 1993 between Massachusetts Industrial Finance Agency and Shawmut Bank, N.A. (filed as Exhibit 10-1.08 to Eastern Edison's Form 10-K for 1993, File No. 0-8480). 10-2.08 - Loan Agreement dated as of July 1, 1993 between Massachusetts Industrial Finance Agency and Eastern Edison (filed as Exhibit 10- 2.08 to Eastern Edison's Form 10-K for 1993, File No. 0-8480). 10-3.08 - Power Purchase Agreement entered into as of September 20, 1993 by and between Meridian Middleboro Limited Partnership and Eastern Edison Company (filed as Exhibit 10-3.08 to Eastern Edison's Form 10-K for 1993, File No. 0-8480). 10-4.08 - Inducement Letter dated July 14, 1993 from Eastern Edison to the Massachusetts Industrial Finance Agency and Goldman, Sachs & Company and Citicorp Securities Markets, Inc. (filed as Exhibit 10-4.08 to Eastern Edison's Form 10-K for 1993, File No. 0-8480). - Montaup - 10-1.05 - Montaup Contract, as amended (Exhibit 4-B, Registration No. 2- 14119; Exhibit 13-A1, Registration No. 2-14718; Exhibit 4-B-2, Registration No. 2-26509; Exhibit 4-B-3, Registration No. 2- 33061; Exhibits 13-3 and 13-4, Registration No. 2-48966; Exhibit B-2, Form U5S of EUA for year 1974 and Exhibit 5-40, Registration No. 2-62862). 10-2.05 - Power Contract (composite copy) between Connecticut Yankee Atomic Power Company and Montaup dated July 1, 1964 as amended and supplemented March 1, 1978, August 22, 1980, and October 15, 1982 (Exhibit B-1, File No. 70-4245; Exhibit 20, Form 10-K of EUA for 1977, File No. 1-5366; Exhibit 10-52, Form 10-K for EUA for 1981, File No. 1-5366; Exhibit 10-67, Form 10-K for EUA for 1983, File No. 1-5366). 10-3.05 - Capital Funds Agreement (composite copy) between Connecticut Yankee Atomic Power Company and Montaup dated September 1, 1964 (Exhibit B-2, File No. 70-4245). 10-4.05 - Stockholder Agreement (composite copy) among Connecticut Yankee Atomic Power Company's Sponsors, including Montaup, dated July 1, 1964 (Exhibit B-4, File No. 70-4245). 10-5.05 - Contract for sale of power to Montaup by Canal Electric Company dated December 1, 1965 (Exhibit 2D, File No. 0-688). 10-6.05 - Capital Funds Agreement (composite copy) between Vermont Yankee Nuclear Power Corporation and Montaup dated as of February 1, 1968, and Amendment thereto dated as at March 12, 1968 (Exhibit B- 2, File No. 70-4611; Exhibit B-3, File No. 70-4611). 10-7.05 - Form of Power Contract between Vermont Yankee Nuclear Power Corporation and Montaup dated as of February 1, 1968, as amended June 1, 1972, April 15, 1983, April 24, 1985, June 1, 1985, May 6, 1988 (2), June 15, 1989 and December 1, 1989 (Exhibit B-4, File No. 70-4591; Exhibit 13-21, Registration No. 2-46612; Exhibit 10- 63, Form 10-K of EUA for 1983, File No. 1-5366; Exhibit 10-74, Form 10-K of EUA for 1985, File No. 1-5366; Exhibit 10-78, Form 10-K of EUA for 1986, File No. 1-5366; Exhibits 10-97 and 10-98, Form 10-K of EUA for 1988, File No. 1-5366; Exhibit 10-95, Form 10-K of EUA for 1989, File No. 1-5366; Exhibit 10-80, Form 10-K of Eastern Edison for 1990, File No. 0-8480). 10-8.05 - Sponsor Agreement (composite copy) among Vermont Yankee Nuclear Power Corporation's Sponsors, including Montaup, dated as of August 1, 1968 (Exhibit 4-0, Registration No. 2-33061). 10-9.05 - Capital Funds Agreement (composite copy) between Maine Yankee and Montaup dated May 20, 1968 and as amended August 1, 1985 (Exhibit B-2, File No. 70-4658; Exhibit 10-78, Form 10-K of EUA for 1985, File No. 1-5366). 10-10.05 - Power Contract (composite copy) between Maine Yankee Atomic and Montaup dated May 20, 1968, as amended December 19, 1983 and January 1, 1984 (Exhibit B-3, File No. 70-4658; Exhibit 10-64, Form 10-K of EUA for 1983, File No. 1-5366; Exhibit 10-66, Form 10-K of EUA for 1984, File No. 1-5366). 10-11.05 - Stockholder Agreement (composite copy) among Maine Yankee Sponsors, including Montaup, dated May 20, 1968 (Exhibit B-4, File 70-4658). 10-12.05 - Agreement (composite copy) among Vermont Yankee Nuclear Power Corporation's Sponsors, including Montaup, dated as of April 30, 1969 (Exhibit B-7, File No. 70-4435). 10-13.05 - Form of Agreement among Maine Yankee Atomic Power Company's Sponsors dated as of May 20, 1969 (Exhibit B-5, File No. 70-4658). 10-14.05 - Form of New England Power Pool Agreement dated as of September 1, 1971, as amended as of July 1, 1972, March 1, 1973, April 2, 1973, March 15, 1974, June 1, 1975, September 1, 1975, December 31, 1976, January 31, 1977, July 1, 1977, August 1, 1977, August 15, 1978, January 31, 1980, February 1, 1980, September 1, 1981, December 1, 1981, June 1, 1982, June 15, 1983, October 1, 1983, August 1, 1985, August 15, 1985, January 1, 1986, September 1, 1986, March 1, 1988, May 1, 1988, March 15, 1989, October 1, 1990, September 15, 1992, and May 1, 1993, (Exhibit 13-45, Registration No. 2-41488; Exhibit 13-38, Registration No. 2- 46612; Exhibits 13-39 and 13-40, Registration No. 2-48966; Exhibit B-3, Form U5S of EUA for year 1974; Exhibit 13-35(a), Registration No. 2-54449; Exhibit 13-35, Registration No. 2-55990, Exhibits 5-69 and 5-70, Registration Exhibit 13-35(a), Registration No. 2-54449; Exhibit 13-35, Registration No. 2- 55990, Exhibits 5-69 and 5-70, Registration No. 2-58625; Exhibit 6, Form 10-K of EUA for 1977, File No. 1-5366; Exhibit 1, Form 10-K of EUA for 1979, File No. 1-5366; Exhibit No. 10-67, Registration No. 2-80205; Exhibit 10-65, Form 10-K of EUA for 1983, File No. 1-5366; Exhibit 10-66, Form 10-K of EUA for 1983, File No. 1-5366; Exhibits 10-75, 10-76, and 10-77, Form 10-K of EUA for 1985, File No. 1-5366; Exhibit 10-79, Form 10-K of EUA for 1986, File No. 1-5366; Exhibits 10-99 and 10-100, Form 10-K of EUA for 1988, File No. 1-5366; Exhibit 10-96, Form 10-K of EUA for 1989, File No. 1-5366; Exhibit 10-81, Form 10-K of Eastern Edison for 1990, File No. 0-8480; Exhibit 10-38.05, Form 10-K of EUA for 1995, File No. 1-5366; Exhibit 10-39.05, Form 10-K of EUA for 1995, File No. 1-5366; Exhibit 10-40.05, Form 10-K of EUA for 1995, File No. 1-5366). 10-15.05 - Unit Participation Agreement between Maine Electric Power Company, Inc. and New Brunswick Electric Power Commission dated November 15, 1971 (Exhibit 13-43.1, Registration No. 2-44377). 10-16.05 - Assignment Agreement dated March 20, 1972 between Maine Electric Power Company, Inc. and New Brunswick Electric Power Commission (Exhibit 13-43.3, Registration No. 2-44377). 10-17.05 - Agreement between Montaup and Boston Edison Company dated August 1, 1972 and as amended January 1, 1985 for purchase of power from Pilgrim No. 1 nuclear unit at Plymouth, Massachusetts (Exhibit 13- 41, Registration No. 2-46612; Exhibit 10-67, Form 10-K of EUA for 1984, File No. 1-5366). 10-18.05 - Agreement dated as of May 1, 1973 for Joint Ownership, Construction and Operation of New Hampshire Nuclear Units among Public Service Company of New Hampshire and other utilities including Montaup, as amended as of May 24, 1974, June 21, 1974, September 25, 1974, October 25, 1974, January 31, 1975, as supplemented by Letter Agreement dated April 27, 1978 and amended as of April 18, 1979 (two amendments), April 25, 1979, June 8, 1979, October 11, 1979, December 15, 1979, June 16, 1980, December 31, 1980, June 1, 1982, April 27, 1984, June 15, 1984, March 8, 1985, March 14, 1986, May 1, 1986, September 19, 1986, November 5, 1987, January 13, 1989 and November 1, 1990. (Exhibit 13-57, Registration No. 2-48966; Exhibit B-6, Form U5S of EUA for year 1974; Exhibit 5-130, Registration No. 2-62862; Exhibit 5-70, Registration No. 2-65785; Exhibit 2, Form 10-K of EUA for 1979, File No. 1-5366; Exhibit 5-34, Registration No. 2-69052; Exhibit 20-1, Form 10-K of EUA for 1980, File No. 1-5366; Exhibit 10-69, Registration No. 2-80205; Exhibit 2, Form 10-Q of EUA for the Quarter Ended March 31, 1984, File No. 1-5366; Exhibit 3, Form 10-Q of EUA for the Quarter Ended June 30, 1984, File No. 1-5366; Exhibit 10-70, Form 10-K of EUA for 1985, File No. 1-5366; Exhibits 10-80 and 10-81, Form 10-K of EUA for 1986, File No. 1-5366; Exhibits 10-95 and 10-96, Form 10-K of EUA for 1987, File No. 1-5366; Exhibit 10-101, Form 10-K of EUA for 1988, File No. 1-5366; Exhibit 10-82, Form 10-K of Eastern Edison for 1990, File No. 0-8480). 10-19.05 - Sharing Agreement dated as of September 1, 1973 among The Connecticut Light and Power Company and other utilities, including Montaup, concerning participation in a nuclear generating unit located in Connecticut (Millstone Unit No. 3), as amended and supplemented by Amendatory Agreement dated May 11, 1984 as amended as of April 1, 1986 (Exhibit B-17, Form U5S of EUA for year 1973; Exhibit B-8, as amended as of April 11, 1986, Form U5S of EUA for year 1974; Exhibit B-30, Form U5S of EUA for year 1976; Exhibit 10-68, Form 10-K of EUA for 1984, File No. 1-5366; Exhibit 10-82, Form 10-K of EUA for 1986, File No. 1-5366). 10-20.05 - Agreement for Joint Ownership, Construction and Operation of William F. Wyman Unit No. 4 dated November 1, 1974 as amended June 30, 1975, August 16, 1976 and December 31, 1978 among Central Maine Power Company and other utilities including Montaup (Exhibit B-9, Form U5S of EUA for year 1974; Exhibit 13-58, Registration No. 2-55990; Exhibit 5-95, Registration No. 2-58625; Exhibit 5-40, Registration No. 2-69052). 10-21.05 - Agreement for Joint Ownership dated as of October 27, 1970 between Canal Electric Company and Montaup (Exhibit 13-71, Registration No. 2-55990). 10-22.05 - Agreement for use of Common Facilities by Canal Units I and II and for Allocation of Related Costs dated as of October 27, 1970 between Canal Electric Company and Montaup (Exhibit 13-72, Registration No. 2-55990). 10-23.05 - Guarantee Agreement (composite copy) dated as of November 13, 1981 between The Connecticut Bank and Trust Company, as Trustee, and Montaup relating to debentures of Connecticut Yankee Atomic Power Company (Exhibit 10-61, Form 10-K of EUA for 1981, File No. 1-5366). 10-24.05 - Agreement for Seabrook Project Disbursing Agent, dated as of May 23, 1984, as amended March 8, 1985, May 20, 1985, June 18, 1985, January 1, 1986, November, 1987, August 1, 1989, and restated as of November 1, 1990, among the participants in the Seabrook nuclear generating project, including Montaup and Yankee Atomic Electric Company (Exhibit 2, Form 10-Q of EUA for the Quarter Ended June 30, 1984, File No. 1-5366; Exhibit 10-69, Form 10-K of EUA for 1985, File No. 1-5366; Exhibits 10-86, 10-87 and 10-88, Form 10-K of EUA for 1986, File No. 1-5366; Exhibit 10-97, Form 10-K of EUA for 1987, File No. 1-5366; Exhibit 10-105, Form 10-K of EUA for 1989, File No. 1-5366; Exhibit 10-84, Form 10-K of Eastern Edison for 1990, File No. 0-8480). 10-25.05 - Guarantee Agreement dated as of August 1, 1985 among The Connecticut Bank and Trust Company, Connecticut Yankee Atomic Power Company and Montaup Electric Company relating to Revolving Credit Loans of Connecticut Yankee (Exhibit 10-85, Form 10-K of EUA for 1985, File No. 1-5366). 10-26.05 - Equity Funding Agreement for New England Hydro-Transmission Corporation dated as of June 1, 1985, between New England Hydro- Transmission Corporation and several New England electric utilities, including Montaup as amended as of May 1, 1986 and September 1, 1987 (Exhibits 10-96 and 10-97, Form 10-K of EUA for 1986, File No. 1-5366; Exhibit 10-116, Form 10-K of EUA for 1987, File No. 1-5366). 10-27.05 - Equity Funding Agreement for New England Hydro-Transmission Electric Company, Inc. dated as of June 1, 1985, between New England Hydro-Transmission Electric Company, Inc. and several New England electric utilities, including Montaup as amended as of May 1, 1986 and September 1, 1987 (Exhibits 10-98 and 10-99, Form 10-K of EUA for 1986, File No. 1-5366; Exhibit 10-117, Form 10-K of EUA for 1987, File No. 1-5366). 10-28.05 - Unit Power Agreement for the Sale of Unit Capacity and Energy from Ocean State Power Project to Montaup Electric Company dated as of May 14, 1986 as amended as of August 27, 1986, September 27, 1988, October 21, 1988, July 21, 1989, February 7, 1990 and December 21, 1990 (Exhibits 10-101 and 10-102, Form 10-K of EUA for 1986, File No. 1-5366; Exhibits 10-106 and 10-107, Form 10-K of EUA for 1988, File No. 1-5366; Exhibit 10-106, Form 10-K of EUA for 1989, File No. 1-5366; Exhibits 10-86 and 10-87, Form 10-K of Eastern Edison for 1990, File No. 0-8480). 10-29.05 - Power Purchase Agreement dated as of October 17, 1986, between Northeast Energy Associates and Montaup as amended as of June 28, 1989 (Exhibit 10-103, Form 10-K of EUA for 1986, File No. 1-5366; Exhibit 10-103, Form 10-K of EUA for 1989, File No. 1-5366). 10-30.05 - Settlement Agreement dated as of January 13, 1989 among Montaup, EUA Power, certain past and present owners of the Seabrook Project and Yankee Atomic Electric Company (Exhibit 10-110, Form 10-K of EUA for 1988, File No. 1-5366). 10-31.05 - Unit Power Agreement for the Sale of Second Unit Capacity and Energy from Ocean State Power Project to Montaup Electric Company dated as of September 28, 1988 as amended by an amendment dated July 21, 1989, and February 7, 1990 and a Supplemental Agreement dated July 21, 1989 (Exhibit 10-104, Form 10-K of EUA for 1989, File No. 1-5366; Exhibit No. 10-88, Form 10-K of Eastern Edison for 1990, File No. 0-8480). 10-32.05 - Purchase Power Contract between Newport and Montaup dated July 23, 1963, as revised on March 23, 1983 (Exhibit 10-108, Form 10-K of EUA for 1990, File No. 1-5366). 10-33.05 - Purchase Power Contract between Newport and Montaup for Contract Demand Service effective May 1, 1983, as amended on July 1, 1983, December 28, 1983 and November 1, 1984 (Exhibit 10-89, Form 10-K of Eastern Edison for 1990, File No. 0-8480 and Exhibit 10-109, Form 10-K of EUA for 1990, File No. 1-5366). 10-34.05 - Power Contract (composite copy) between Yankee Atomic Electric Company and Montaup dated June 30, 1959 as revised April 1, 1975, as further amended October 1, 1980, April 1, 1985, May 6, 1988, June 26, 1989, July 1, 1989 and February 1, 1992 (Exhibit 10-6, Registration No. 2-72655; Exhibit 10-73, Form 10-K of EUA for 1985, File No. 1.5366; Exhibit 10-96, Form 10-K of EUA for 1988, File No. 1-5366; Exhibits 10-93 and 10-94, Form 10-K of EUA for 1989, File No. 1-5366; Exhibit 10-46 Form 10-K of Eastern Edison for 1992, File No. 0-8480). 10-35.05 - Memorandum of understanding by and between Canal Electric Company and Montaup Electric Company dated September 23, 1993 (Exhibit 10- 39.05, Eastern Edison 10-K for 1993, File No. 0-8480). 10-36.05 - Ancillary Agreement by and between Algonquin Gas Transmission Company, Canal Electric Company and Montaup Electric Company dated October 8, 1993. (Exhibit 10-40.05 of Eastern Edison 10-K for 1993, File No. 0-8480). *10-37.05 - Amendment to 10-2.05 dated December 4, 1996. *10-38.05 - Thirty-third Amendment to 10-14.05 dated December 31, 1996. *10-39.05 - Seventh Amendment to 10-28.05 dated February 12, 1996. *10-40.05 - Eighth Amendment to 10-28.05 dated February 12, 1996. *10-41.05 - Third Amendment to 10-31.05 dated February 12, 1996. *10-42.05 - Fourth Amendment to 10-31.05 dated February 12, 1996. - Blackstone - 10-1.01 - Trust Indenture between Rhode Island Industrial Facilities Corporation and the Rhode Island Hospital Trust Company dated as of December 1, 1984 (Exhibit 10-73, Form 10-K of EUA for 1984, File No. 1-5366). 10-2.01 - Remarketing Agreement between Rhode Island Hospital Trust Company, Citibank and Blackstone dated as of December 19, 1984 (Exhibit 10-74, Form 10-K of EUA for 1984, File No. 1-5366). 10-3.01 - Letter of Credit and Reimbursement Agreement between Blackstone Valley Electric Company and The Bank of New York dated as of January 21, 1993 (Exhibit 10-10, Form 10-K of Blackstone for 1992, File No. 0-2602). 10-4.01 - Interconnection Agreement by and between Blackstone and Ocean State Power dated November 1, 1988, as amended and restated effective August 16, 1989 by and among Blackstone, Ocean State Power I and Ocean State Power II (Exhibit 10-100, Form 10-K of EUA for 1989, File No. 1-5366). 10-5.01 - Power Purchase Agreement between Blackstone and Blackstone Hydro, Inc. dated as of January 8, 1989 and assignment to Montaup (Exhibits 10-101 and 10-102, Form 10-K of EUA for 1989, File No. 1-5366). - Newport - 10-1.14 - Phase I Vermont Transmission Line Support Agreement dated as of December 1, 1981 and as amended as of June 1, 1982, November 1, 1982 and January 1, 1986 between Vermont Electric Transmission Company, Inc. and several New England utilities, including Montaup (Exhibit 10-65, Form 10-K of EUA for 1981, File No. 1- 5366; Exhibit 10-72, Registration No. 2-80205; Exhibit 10-64, Form 10-K of EUA for 1982, File No. 1-5366; Exhibit 10-84. Form 10-K of EUA for 1986, File No. 1-5366). 10-2.14 - Letter amendment dated August 4, 1983 reallocating the participating shares originally assigned to the Chicopee Municipal Lighting Plant and the Taunton Municipal Lighting Plant under the Phase I Vermont Transmission Line Support Agreement between Vermont Electric Transmission Company, Inc. and several New England electric utilities, including Newport, dated December 1, 1981, as amended on June 1, 1982 and November 1, 1982 (Exhibit 10-110, Form 10-K of EUA for 1990, File No. 1-5366). 10-3.14 - Phase I Terminal Facility Support Agreement dated December 1, 1981 and as amended as of June 1, 1982, November 1, 1982 and January 1, 1986 between New England Electric Transmission Corporation and several New England utilities, including Montaup (Exhibit 10-68, Form 10-K of EUA for 1981, File No. 1-5366; Exhibit 10-74, Registration No. 1-5366; Exhibit 10-68. Form 10-K of EUA for 1986, File No. 1-5366). 10-4.14 - Letter amendment dated July 29, 1983 reallocating the participating shares originally assigned to the Chicopee Municipal Lighting Plant and the Taunton Municipal Lighting Plant under the Phase I Terminal Facility Support Agreement between New England Transmission Corporation and several New England electric utilities, including Newport, dated December 1, 1981, as amended on June 1, 1982 and November 1, 1982 (Exhibit 10-112, Form 10-K of EUA for 1990, File No. 1-5366). 10-5.14 - Purchase Power Contract between Newport and City of Burlington Electric Department (life of the unit contract) for purchase of 15.24% of net capability of station output from Joseph C. McNeil Electric Generating Station located in Burlington, Vermont dated December 19, 1984 (Exhibit 10-115, Form 10-K of EUA for 1990, File No. 1-5366). 10-6.14 - Firm Energy Contract between Hydro-Quebec and several New England electric utilities, including Newport, dated as of October 14, 1985 (Exhibit 10-116, Form 10-K of EUA for 1990, File No. 1-5366). 10-7.14 - Unit Power Agreement for the Sale of Unit Capacity and Energy from Ocean State Power Project to Newport Electric Corporation dated May 14, 1986, as amended on August 20, 1986, July 12, 1988, September 23, 1988, October 21, 1988, July 21, 1989, February 7, 1990 and December 21, 1990 (Exhibit 10-117, Form 10-K for 1990, File No. 1-5366). 10-8.14 - Unit Power Agreement for the Sale of Second Unit Capacity and Energy from Ocean State Power Project to Newport Electric Corporation dated July 12, 1988 as amended and supplemented September 23, 1988, July 21, 1989 and February 7, 1990 (Exhibit 10-118, Form 10-K for 1990, File No. 1-5366). 10-9.14 - Agreement for Joint Ownership, Construction and Operation of William F. Wyman Unit No. 4 dated November 1, 1974 as amended June 30, 1975, August 16, 1976 and December 31, 1978 among Central Maine Power Company and other utilities including Newport (Exhibit B-9, Form U5S of EUA for year 1974; Exhibit 13-58, Registration No. 2-55990; Exhibit 5-95, Registration No. 2-58625; Exhibit 5-40, Registration No. 2-69052). - EUA Ocean State - 10-1.12 - Ocean State Power Amended and Restated General Partnership Agreement among EUA Ocean State, Ocean State Power Company, TCPL Power Ltd., Narragansett Energy Resources Company and NECO Power, Inc. (collectively, the "OSP Partners") dated as of December 2, 1988, as amended March 27, 1989, December 31, 1990, November 12, 1992 and February 23, 1993 (Exhibit 10-107, Form 10-K of EUA for 1989; File No. 1-5366, Exhibits 10-3.12, 10-4.12 and 10-5.12, Form 10-K of EUA for 1994, File No. 1-5366). 10-2.12 - Ocean State Power II Amended and Restated General Partnership Agreement among EUA Ocean State, JMC Ocean State Corporation, Makowski Power, Inc., TCPL Power Ltd., Narragansett Energy Resources Company and Newport Electric Power Corporation (collectively, the "OSP II Partners") dated as of September 29, 1989 (Exhibit 10-110, Form 10-K of EUA for 1989, File No. 1-5366). Annual Reports to Shareholders: *13-1.03 - Annual Report to Shareholders of EUA for 1996, portions of which are incorporated by reference in this Annual Report on Form 10-K. Only the portions expressly so incorporated under PART II, Items 5, 6, 7 and 8 are to be deemed filed herewith. *13-1.01 - Annual Report to Shareholders of Blackstone for 1996, portions of which are incorporated by reference in this Annual Report on Form 10-K. Only the portions expressly so incorporated under PART II, Items 5, 6, 7 and 8 are to be deemed filed herewith. *13-1.08 - Annual Report to Shareholders of Eastern Edison for 1996, portions of which are incorporated by reference in this Annual Report on Form 10-K. Only the portions expressly so incorporated under PART II, Items 5, 6, 7 and 8 are to be deemed filed herewith. Subsidiaries of EUA: 21-1.03 - Direct subsidiaries of Eastern Utilities Associates and the state of organization of each are: Blackstone Valley Electric Company (Rhode Island), Eastern Edison Company (Massachusetts), EUA Cogenex Corporation (Massachusetts), EUA Service Corporation (Massachusetts), EUA Ocean State Corporation (Rhode Island), EUA Energy Investment Corporation (Massachusetts), Newport Electric Corporation (Rhode Island) and EUA Energy Services, Inc. (Massachusetts). Montaup Electric Company (Massachusetts) is a subsidiary of Eastern Edison Company. Each of the above subsidiaries does business under its indicated corporate name. Consent of Experts and Counsel: *23-1.03 - Consent of Independent Accountants. (b) Reports on Form 8-K. On January 6, 1997, EUA filed a Current Report on Form 8-K with respect to Item 5 (Other Events). On January 6, 1997, Eastern Edison filed a Current Report on Form 8-K with respect to Item 5 (Other Events). [This page left blank intentionally] SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. Signature Title Date EASTERN UTILITIES ASSOCIATES By /s/ Richard M. Burns Comptroller March 17, 1997 Richard M. Burns (Principal Accounting Officer) Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. /s/Donald G. Pardus Chairman and Chief Executive Officer Donald G. Pardus (Principal Executive Officer) and Trustee /s/John Stevens President and Chief Operating Officer John R. Stevens (Principal Financial Officer) and Trustee /s/ Richard M. Burns Comptroller Richard M. Burns (Principal Accounting Officer) Russell A. Boss Trustee /s/Paul J. Choquette, Jr. Trustee Paul J. Choquette, Jr. March 17, 1997 /s/Peter S. Damon Trustee Peter S. Damon /s/Peter B. Freeman Trustee Peter B. Freeman /s/Larry A. Liebenow Trustee Larry A. Liebenow /s/Jacek Makowski Trustee Jacek Makowski Wesley W. Marple, Jr. Trustee Wesley W. Marple, Jr. /s/Margaret M. Stapleton Trustee Margaret M. Stapleton /s/W. Nicholas Thorndike Trustee W. Nicholas Thorndike [This page left blank intentionally] SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. Signature Title Date BLACKSTONE VALLEY ELECTRIC COMPANY By/s/ Richard M. Burns Vice President March 17, 1997 Richard M. Burns (Principal Accounting Officer) Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. /s/Donald G. Pardus Chairman of the Board and Donald G. Pardus Director (Principal Executive Officer) /s/John R. Stevens Vice Chairman and Director John R. Stevens (Principal Financial Officer) /s/Richard M. Burns Vice President Richard M. Burns (Principal Accounting Officer) /s/John D. Carney President and Director John D. Carney /s/David H. Gulvin Senior Vice President David H. Gulvin and Director March 17, 1997 /s/Robert G. Powderly Executive Vice President and Robert G. Powderly Director [This page left blank intentionally] SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. Signature Title Date EASTERN EDISON COMPANY March 17, 1997 By/s/Richard M. Burns Vice President Richard M. Burns (Principal Accounting Officer) Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. /s/Donald G. Pardus Chairman of the Board and Director Donald G. Pardus (Principal Executive Officer) /s/John R. Stevens Vice Chairman and Director John R. Stevens (Principal Financial Officer) March 17, 1997 /s/Richard M. Burns Vice President Richard M. Burns (Principal Accounting Officer) /s/John D. Carney President and Director John D. Carney /s/David H. Gulvin Senior Vice President David H. Gulvin and Director /s/Robert G. Powderly Executive Vice President and Robert G. Powderly Director [This page left blank intentionally] EASTERN UTILITIES ASSOCIATES AND SUBSIDIARY COMPANIES Item 14(a)(2). Financial Statement Schedules Schedule II Eastern Utilities Associates and Subsidiary Companies Valuation and Qualifying Accounts (In Thousands)
Column A Column B Column C Column D Column E Additions (1) (2) Balance at Charged to Charged Balance at Beginning Costs and to Other Deductions- End of Description of Period Expenses Accounts Describe Period For the Year Ended December 31, 1996: Allowance for Doubtful Accounts $690 $1,754 $292 $1,760 $976 For the Year Ended December 31, 1995: Allowance for Doubtful Accounts $629 $1,217 $287 $1,443 $690 For the Year Ended December 31, 1994: Allowance for Doubtful Accounts $613 $1,141 $277 $1,402 $629 Recoveries of accounts previously written off. Principally Accounts Receivable written off.
Schedule II Blackstone Valley Electric Company Valuation and Qualifying Accounts (In Thousands) Column A Column B Column C Column D Column E Additions (1) (2) Balance at Charged to Charged Balance at Beginning Costs and to Other Deductions- End of Description of Period Expenses Accounts Describe Period For the Year Ended December 31, 1996: Allowance for Doubtful Accounts $127 $800 $232 $1,008 $151 For the Year Ended December 31, 1995: Allowance for Doubtful Accounts $125 $585 $217 $800 $127 For the Year Ended December 31, 1994: Allowance for Doubtful Accounts $158 $710 $213 $956 $125 Recoveries of accounts previously written off. Principally Accounts Receivable written off.
[This page left blank intentionally] Report of Independent Accountants To the Trustees and Shareholders of Eastern Utilities Associates: Our report on the consolidated financial statements of Eastern Utilities Associates and subsidiaries has been incorporated by reference in this Form 10-K from page 40 of the 1996 Annual Report to Shareholders of Eastern Utilities Associates. In connection with our audits of such consolidated financial statements, we have also audited the related consolidated financial statement schedule listed in Item 14 (a)(2) of this Form 10-K. In our opinion, the consolidated financial statement schedule referred to above, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information required to be included therein. /s/Coopers & Lybrand L.L.P. Boston, Massachusetts March 5, 1997 Report of Independent Accountants To the Directors and Shareholder of Blackstone Valley Electric Company: Our report on the financial statements of Blackstone Valley Electric Company has been incorporated by reference in this Form 10-K from page 27 of the 1996 Annual Report of Blackstone Valley Electric Company. In connection with our audits of such financial statements, we have also audited the related financial statement schedule listed in Item 14 (a)(2) of this Form 10-K. In our opinion, the financial statement schedule referred to above, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information required to be included therein. /s/Coopers & Lybrand L.L.P. Boston, Massachusetts March 5, 1997 [This page left blank intentionally] EX-10 2 EXHIBIT 10-37.05 This Agreement, dated as of the 4th day of December, 1996, is entered into by and between Connecticut Yankee Atomic Power Company ("Connecticut Yankee" or "Seller") and Montaup Electric Company ("Purchaser"). For good and valuable consideration, the receipt of which is hereby acknowledged, it is agreed as follows: 1. Basic Understandings Connecticut Yankee was organized in 1952 to provide for the supply of power to its sponsoring utility companies, including the Purchaser (collectively the "Purchasers"). It constructed a nuclear electric generating unit, having a net capability of approximately 582 megawatts electric (the "Unit") at a site in Haddam Neck, Connecticut. Connecticut Yankee was issued a full- term, Facility Operating License for the Unit by the Nuclear Regulatory Commission (which, together with any successor agencies, is hereafter called the "NRC"), which license is now stated to expire on June 29, 2007. The Unit has been in commercial operation since January 1, 1968. The Unit was conceived to supply economic power on a cost of service formula basis to the Purchasers. Connecticut Yankee and the Purchaser are parties to a power Contract dated as of July 1, 1964 ("Initial Power Contract"). Pursuant to the Initial Power Contract and other similar contracts (collectively, the "Initial Power Contracts") between Connecticut Yankee and the other Purchasers, Connecticut Yankee contracted to supply to the Purchasers all of the capacity and electric energy available from the Unit for a term of thirty (30) years following January l, 1968. Connecticut Yankee and the Purchaser are also parties to an Additional Power Contract, dated as of April 30, 1984 ("Additional Power Contract"). The Additional Power Contract and other similar contracts (collectively, the "Additional Power Contracts") between Connecticut Yankee and the other Purchasers provide for an operative term stated to commence on January 1, 1998 (when the Initial Power Contracts terminate) and extending until a date (the "End of Term Date") which is 30 days after the later of the date on which the last of the financial obligations of Connecticut Yankee has been extinguished or the date on which Connecticut Yankee is finally relieved of any obligations under the last of the licenses (operating or possessory) which it holds, or hereafter receives, from the NRC with respect to the Unit. The Additional Power Contracts also provide, in the event of their earlier cancellation, for the survival of the decommissioning cost obligation and for the applicable provisions thereof to remain in effect to permit final billings of costs incurred prior to such cancellation. Pursuant to the Power Contract and the Additional Power Contract, the Purchaser is entitled and obligated to take its entitlement percentage of the capacity and net electrical output of the Unit during the service life of the Unit and obligated to pay therefor monthly its entitlement percentage of Connecticut Yankee's cost of service, including decommissioning costs, whether or not the Unit is operated. Connecticut Yankee and the Purchaser are also parties to a 1987 Supplementary Power Contract, dated as of April l, 1987 ("1987 Supplementary Power Contract"). The 1987 Supplementary Power Contract and other similar contracts (collectively, the "1987 Supplementary Power Contracts") between Connecticut Yankee and the other Purchasers restate and supersede earlier Supplementary Power Contracts and Agreements Amending Supplementary Power Contracts between Connecticut Yankee and the Purchasers. Pursuant to the 1987 Supplementary Power Contracts, the Purchasers make monthly certain supplementary payments to Connecticut Yankee during the terms of the Initial Power Contracts and Additional Power Contracts. On December 4, 1996, the board of directors of Connecticut Yankee, after conducting a thorough review of the economics of continued operation of the Unit for the remainder of the term of the Facility Operating License for the Unit in light of other alternatives available to Connecticut Yankee and the Purchasers, determined that the Unit should be permanently shut down effective December 4, 1996. The Purchaser concurs in that decision. As a consequence of the shutdown decision, Connecticut Yankee and the Purchaser propose at this time to amend the 1987 Supplementary Power Contract and the Additional Power Contract in various respects in order to clarify and confirm provisions for the recovery under said contracts of the full costs previously incurred by Connecticut Yankee in providing power from the Unit during its useful life and of all costs of decommissioning the Unit, including the costs of maintaining the Unit in a safe condition following the shutdown and prior to its decontamination and dismantlement. Connecticut Yankee and each of the other Purchasers are entering into agreements which are identical to this Agreement except for necessary changes in the names of the parties. 2. Parties' Contractual Commitments Connecticut Yankee reconfirms its existing contractual obligations to protect the Unit, to maintain in effect certain insurance and to prepare for and implement the decommissioning of the Unit in accordance with applicable laws and regulations. Consistent with public safety, Connecticut Yankee shall use its best efforts to accomplish the shutdown of the Unit, the protection and any necessary maintenance of the Unit after shutdown and the decommissioning of the Unit in a cost-effective manner and shall use its best efforts to ensure that any required storage and disposal of the nuclear fuel remaining in the reactor at shutdown and all spent nuclear fuel or other radioactive materials resulting from operating of the Unit are accomplished consistent with public health and safety considerations and at the lowest practicable cost. The Purchaser reconfirms its obligations under its Initial Power Contract, Additional Power Contract and 1987 Supplementary Power Contract to pay its entitlement percentage of Connecticut Yankee's costs as deferred payment in connection with the capacity and net electrical output of the Unit previously delivered by Connecticut Yankee and agrees that the decision to shut down the Unit described in Section 1 hereof does not give rise to any cancellation right under Section 9 of the Initial Power Contract or Section 10 of the Additional Power Contract. Except as expressly modified by this Agreement, the provisions of the Additional Power Contract and the 1987 Supplementary Power Contract remain in full force and effect, recognizing that the mutually accepted decision to shut down the Unit renders moot those provisions which by their terms relate solely to continuing operation of the Unit. 3. Amendment of Payment Provisions of Additional Power Contract and 1987 Supplementary Power Contract A. Section 2 of the Additional Power Contract is hereby amended by deleting the first two paragraphs thereof and by inserting in lieu thereof the following: This contract shall become effective upon receipt by the Purchaser of notice that Connecticut Yankee has entered into Additional Power Contracts, as contemplated by Section 1 above, with each of the other Purchasers. The operative term of this contract shall commence on such date as may be authorized by the FERC and shall terminate on the date (the "End of Term Date") which is the later to occur of (i) 30 days after the date on which the last of the financial obligations of Connecticut Yankee which constitute elements of the payment calculated pursuant to Section 7 of this contract has been extinguished by Connecticut Yankee, or (ii) 30 days after the date on which Connecticut Yankee is finally relieved of all obligations under the last of any licenses (operating and/or possessory) which it now holds from, or which may hereafter be issued to it by, the NRC with respect to the Unit under applicable provisions of the Atomic Energy Act of 1954, as amended from time to time (the "Act"). B. The second paragraph of Section 4 of the Additional Power Contract is amended by deleting the phrase "Second Supplementary Power Contracts" wherever it appears and inserting in lieu thereof the phrase "1987 Supplementary Power Contracts". C. The first paragraph of Section 7 of the Additional Power Contract is amended to read as follows: With respect to each month commencing on or after the commencement of the operative term of this contract, whether or not this contract continues fully or partially in effect, the Purchaser will pay Connecticut Yankee as deferred payment for the capacity and output of the Unit provided to the Purchaser by Connecticut Yankee prior to the permanent shutdown of the Unit on December 4, 1996, to the extent not otherwise paid in accordance with the Power Contract, but without duplication: D. The eighth paragraph of Section 7 of the Additional Power Contract is amended by changing the period at the end to a comma and inserting: , but including for purposes of this contract: (i) with respect to each month until the commencement of decommissioning of the Unit, the Purchaser's entitlement percentage of all expenses related to the storage or disposal of nuclear fuel or other radioactive materials, and all expenses related to protection and maintenance of the Unit during such period, including to the extent applicable all of the various sorts of expenses included in the definition of "Decommissioning Expenses", to the extent incurred during the period prior to the commencement of decommissioning; (ii) with respect to each month until expenses associated with disposal of pre-April 7, 1983 spent nuclear fuel have been fully covered by amounts which have been collected from Purchasers and paid to a segregated fund as contemplated by Section 8 of the 1987 Supplementary Power Contract, dated as of April 1, 1987, between Connecticut Yankee and the Purchaser, as amended (the "1987 Contract"), the Purchaser's entitlement percentage of previously uncollected expenses associated with disposal of such prior spent nuclear fuel, as determined in accordance with Section 10 of the 1987 Contract; and (iii) with respect to each month until End of License Term, the Purchaser's entitlement percentage of monthly amortization of (a) the amount of any unamortized deferred expenses, as permitted from time to time by the Federal Energy Regulatory Commission or its successor agency, plus (b) the remaining unamortized amount of Connecticut Yankee's investment in plant, nuclear fuel and materials and supplies and other assets. Such amortization shall be accrued at a rate sufficient to amortize fully such unamortized deferred expenses and Connecticut Yankee's investments in plant, nuclear fuel and materials and supplies or other assets over a period extending to June 29, 2007, provided, that if during any calendar month ending on or before December 3, 2000 either of the following events shall occur: (a) Connecticut Yankee shall become insolvent or (b) Connecticut Yankee shall be unable, from available cash or other sources, to meet when due during such month its obligations to pay principal, interest, premium (if any) or other fees with respect to any of its indebtedness of money borrowed, then Connecticut Yankee may adjust upward the accrual for amortization of the unrecovered investment for such month to an amount not exceeding the applicable maximum level specified in Appendix A hereto, provided that concurrently therewith the net Unit investment shall be reduced by an amount equal to the amount of such adjustment. As used herein, "End of License Term" means June 29, 2007 or such later date as may be fixed, by amendment to the NRC Facility Operating License for the Unit, as the end of the term of the Facility Operating License. E. The definitions in Section 7 of the Additional Power Contract and in Section 3 of the 1987 Supplementary Power Contract of "Total Decommissioning Costs" and "Decommissioning Expenses" are hereby amended to read as follows: "Total Decommissioning Costs" for any month shall mean the sum of (x) an amount equal to all accruals in such month to any reserve, as from time to time established by Connecticut Yankee and approved by its board of directors, to provide for the ultimate payment of the Decommissioning Expenses of the Unit, plus (y), during the Decommissioning Period, the Decommissioning Expenses for the month, to the extent such Decommissioning Expenses are not paid with funds from such reserve, plus (z) Decommissioning Tax Liability for such month. It is understood (i) that funds received pursuant to clause (x) may be held by Connecticut Yankee or by an independent trust or other separate fund, as determined by said board of directors, (ii) that, upon compliance with applicable regulatory requirements, the amount, custody and/or timing of such accruals may from time to time during the term hereof be modified by said board of directors in its discretion or to comply with applicable statutory or regulatory requirements or to reflect changes in the amount, custody or timing of anticipated Decommissioning Expenses, and (iii) that the use of the term "to decommission" herein encompasses compliance with all requirements of the NRC for permanent cessation of operation of a nuclear facility and any other activities reasonably related thereto, including provision for the interim storage of spent nuclear fuel. "Decommissioning Expenses" shall include all expenses of decommissioning the Unit, and all expenses relating to ownership and protection of the Unit during the Decommissioning Period, and shall also include the following: (1) All costs and expenses of any NRC-approved method of removing the Unit from service, including without limitation: dismantling, moth balling and entombment of the Unit; removing nuclear fuel and other radioactive material to temporary and/or permanent storage sites; construction, operation, maintenance and dismantling of a spent fuel storage facility; decontaminating, restoring and supervising the site; and any costs and expenses incurred in connection with proceedings before governmental authorities relating to any authorization to decommission the Unit or remove the Unit from service; (2) All costs of labor and services, whether directly or indirectly incurred, including without limitation, services of foremen, inspectors, supervisors, surveyors, engineers, security personnel, counsel and accountants, performed or rendered in connection with the decommissioning of the Unit and the removal of the Unit from service, and all costs of materials, supplies, machinery, construction equipment and apparatus acquired or used (including rental charges for machinery, equipment or apparatus hired) for or in connection with the decommissioning of the Unit and the removal of the Unit from service, and all administrative costs, including services of counsel and financial advisers of any applicable independent trust or other separate fund; it being understood that any amount, exclusive of proceeds of insurance, realized by Connecticut Yankee as salvage on any machinery, construction equipment and apparatus, the cost of which was charged to Decommissioning Expense, shall be treated as a reduction of the amounts otherwise chargeable on account of the costs of decommissioning of the Unit; and (3) All overhead costs applicable to the Unit during the Decommissioning Period, or accrued during such period, including without limiting the generality of the foregoing, taxes (other than taxes on or in respect of income), charges, license fees, excises and assessments, casualties, health care costs, pension benefits and other employee benefits, surety bond premiums and insurance premiums. F. Section 7 of the Additional Power Contract and Section 3 of the 1987 Supplementary Power Contract are each hereby amended by adding the following new paragraph after the definition of "Decommissioning Tax Liability": "Decommissioning Period" shall mean the period commencing with the notification by Connecticut Yankee to the NRC of a decision of the board of directors of Connecticut Yankee to cease permanently the operation of the Unit for the purpose of producing electric energy and ending with the date when Connecticut Yankee has completed the decommissioning of the Unit and the restoration of the site and has been relieved of all its obligations under the last of any licenses issued to it by the NRC. G. The first sentence of Section 8 of the Additional Power Contract is hereby amended to read as follows: Connecticut Yankee will bill the Purchaser, no later than ten (10) days after the end of any month, for all amounts payable by the Purchaser with respect to such particular month pursuant to Section 7 hereof. H. Section 8 of the Additional Power Contract and Section 4 of the 1987 Supplementary Power Contract are each amended to delete the name "The Connecticut Bank and Trust Company, National Association" and substitute "Fleet National Bank." I. Section 5 of the 1987 Supplementary Power Contract is amended to read as follows: 5. Decommissioning Fund: Connecticut Yankee agrees to pay to, or cause to be paid to, the Connecticut Yankee Trust or any successor trust approved by the board of directors of Connecticut Yankee all funds collected pursuant to Section 3 under clause (x) of the definition of "Total Decommissioning Costs". J. Section 10 of the Additional Power Contract is amended to read as follows: 10. Cancellation of Contract. If either (i) the Unit is damaged to the extent of being completely or substantially completely destroyed, or (ii) The Unit is taken by exercise of the right of eminent domain or a similar right or power, then and in any such case, the Purchaser may cancel the provisions of this contract, except that in all cases other than those described in clause (ii) above, the Purchaser shall be obligated to continue to make the payments of Total Decommissioning Costs and the other payments required by Section 7 and the provisions of that Section and the related provisions of this contract shall remain in full force and effect until the End of Term Date, it being recognized that the costs which Purchaser is required to pay pursuant to Section 7 represent deferred payments in connection with power heretofore delivered by Connecticut Yankee hereunder. Such cancellation shall be effected by written notice given by the Purchaser to Connecticut Yankee. In the event of such cancellation, all continuing obligations of the parties hereunder as to subsequently incurred costs of Connecticut Yankee other than the obligations of the Purchaser to continue to make the payments required by Section 7 shall cease forthwith. Notwithstanding the foregoing, the applicable provisions of this contract shall continue in effect after the cancellation hereof to the extent necessary to permit final billings and adjustments hereunder with respect to obligations incurred through the date of cancellation and the collection thereof. Any dispute as to the Purchaser's right to cancel this contract pursuant to the foregoing provisions shall be referred to arbitration in accordance with the provisions of Section 13. Notwithstanding anything in this contract elsewhere contained, the Purchaser may cancel this contract or be relieved of its obligations to make payments hereunder only as provided in the next receding paragraph of this Section 10. Further, if for reasons beyond Connecticut Yankee's reasonable control, deliveries are not made as contemplated by this contract, Connecticut Yankee shall have no liability to the Purchaser on account of such non- delivery. K. Section 2 of the 1987 Supplementary Power Agreement is amended to change the date in the definitions of "operating expenses" and "M" from "May 26, 2004" to "June 29, 2007". 5. Effective Date This Agreement shall become effective upon receipt by the Purchaser of notice that Connecticut Yankee has entered into 1996 Amendatory Agreements, as contemplated by Section 1 hereof, with each of the other Purchasers. 6. Interpretation The interpretation and performance of this Agreement shall be in accordance with and controlled by the laws of the State of Connecticut. 7. Addresses Except as the parties may otherwise agree, any notice, request, bill or other communication from one party to the other relating to this Agreement, or the rights, obligations or performance of the parties hereunder, shall be in writing and shall be effective upon delivery to the other party. Any such communication shall be considered as duly delivered when mailed to the respective post office address of the other party shown following the signatures of such other party hereto, or such other post office address as may be designated by written notice given in the manner as provided in this Section. 8. Corporate Obligations This Agreement is the corporate act and obligation of the parties hereto. 9. Counterparts This Agreement may be executed in any number of counterparts and each executed counterpart shall have the same force and effect as an original instrument and as if all the parties to all of the counterparts had signed the same instrument. Any signature page of this Agreement may be detached from any counterpart without impairing the legal effect of any signatures thereon, and may be attached to another counterpart of this Agreement identical in form hereto but having attached to it one or more signature pages. IN WITNESS WHEREOF, the parties have executed this Amendatory Agreement by their respective duly authorized officers as of the day and year first named above. CONNECTICUT YANKEE ATOMIC POWER COMPANY By: /s/ John B. Keane John B. Keane Its Vice President and Treasurer Address: 107 Selden Street Berlin, CT 06037 MONTAUP ELECTRIC COMPANY By: /s/ Donald G. Pardus Donald G. Pardus Its Chairman Address: One Liberty Square 13th Floor Boston, MA 02107 Appendix A to 1996 Amendatory Agreement Maximum Depreciation Schedule If the event occurs during the twelve months ending: Maximum Amortization Accrual: December 31, 1997 $100,000,000.00 December 31, 1998 $ 80,000,000.00 December 31, 1999 $ 40,000,000.00 December 31, 2000 $ 20,000,000.00 EX-10 3 EXHIBIT 10-38.05 THIRTY-THIRD AGREEMENT AMENDING NEW ENGLAND POWER POOL AGREEMENT THIS THIRTY-THIRD AGREEMENT, dated as of the 1st day of December, 1996, is entered into by the signatory Participants for the amendment and restatement by them of the New England Power Pool Agreement dated as of September, 1, 1971 (the "NEPOOL Agreement"), as previously amended by thirty (30) amendments, the most recent of which was dated as of September 1, 1995. WHEREAS, the signatory Participants propose to restate the NEPOOL Agreement to provide for a restructured New England Power Pool and to include as part of such restated pool agreement a NEPOOL Open Access Transmission Tariff (the "Tariff"); NOW THEREFORE, the signatory Participants hereby agree as follows: SECTION I AMENDMENT AND RESTATEMENT OF NEPOOL AGREEMENT The NEPOOL Agreement as in effect on December 1, 1996 (the "Prior NEPOOL Agreement") is amended and restated, as of the effective dates provided in Section II, to read as provided in Exhibit A hereto (the "Restated NEPOOL Agreement"). SECTION II EFFECTIVENESS OF THE THIRTY-THIRD AGREEMENT This Thirty-Third Agreement, and the amendment and restatement provided for above, shall become effective as follows: (1) Parts One, Two, Four and Five, of the Restated NEPOOL Agreement and all of the provisions of the Tariff shall become effective, and Sections 1 to 8, inclusive, 10, 11, 13, 14.2, 14.3, 14.4 and 16 of the Prior NEPOOL Agreement shall cease to b e in effect, on March 1, 1997 or on such other date as the Federal Energy Regulatory Commission ("Commission") shall provide that such portion of the Restated NEPOOL Agreement shall become effective (the "First Effective Date"); and (2) the remaining portions of the Restated NEPOOL Agreement shall become effective, and Sections 9, 12, 14.1, 14.5, 14.6, 14.7, 14.8 and 15 of the Prior NEPOOL Agreement together with the related exhibits and supplements to the Prior NEPOOL Agreement shall cease to be in effect, on July 1, 1997 or such other date on or before January 1, 1998 as the NEPOOL Management Committee may fix, after it has determined that the necessary detailed criteria, rules and standards and computer programs to implement such remaining portions of the Restated NEPOOL Agreement are in place, or on such other date or dates as the Federal Energy Regulatory Commission may fix, on its own or pursuant to the request of the Management Committee, (the "Second Effective Date"). SECTION III INTENT OF AGREEMENT This Thirty-Third Agreement is intended by the signatories hereto to effect a comprehensive amendment and restatement of the NEPOOL Agreement and to provide a regional open access transmission arrangement in accordance with the Restated NEPOOL Agreement and the Tariff, which is Attachment B to the Restated NEPOOL Agreement. Subject to the understandings expressed in the balance of this Section and in Section IV, the signatories agree to support the acceptance of the Thirty-Third Agreement by the Commission. Subject to the understandings expressed in Section IV of this Agreement, in entering into this Thirty-Third Agreement the signatories expressly condition their commitment on acceptance of this Thirty-Third Agreement, including the Restated NEPOOL Agreement and the Tariff, by the Commission and any other regulatory body having jurisdiction without significant conditions or modifications. If significant conditions are imposed or significant modifications are required, the signatories reserve the right to renegotiate the Thirty-Third Agreement as a whole or to terminate it. SECTION IV ALTERNATIVE AMENDMENTS The signatories have been unable to reach final agreement on two aspects of the transmission arrangements for a restructured NEPOOL which would be in effect after the five-year Transition Period provided for in the Tariff, as follows: (a) the continued treatment of "grandfathered contracts" as Excepted Transactions; and (b) the continuance and treatment of Participant Regional Network Service rates which differ from an average Regional Network Service rate. It is agreed that any Participant which signs this Agreement shall be entitled to take any position before the Commission that it deems best with respect to either of these two aspects of the transmission arrangements. However, Participants signing this Agreement are requested to consider the proposed treatment of these aspects of the transmission arrangements in the following Alternate A and Alternate B and to indicate, if they are willing, in the optional supplemental agreement on the signature page to this Agreement their position on these alternates. The alternates are as follows: Alternate A is as follows: 1. The introductory portion of paragraph (3) of Section 25 of the Tariff shall be amended to read as follows: (3) for the period from the effective date of the Tariff until the termination of the transmission agreement or the end of the Transition Period, whichever occurs first: 2. The description of the "Participant RNS Rate" in Schedule 9 to the Tariff shall be amended by modifying the proviso at the end of the second sentence of paragraph (4) of the Schedule to read as follows: provided that in no event shall its pre-1997 Participant RNS Rate be less than 70% of the pre-1997 Pool PTF Rate until the end of Year Five, and thereafter shall be equal to the pre-1997 Pool PTF Rate for Year Six and thereafter. and by amending the proviso at the end of the third sentence of paragraph (4) of the Schedule to read as follows: provided that in no event shall its pre-1997 Participant RNS Rate be greater than 130% of the pre-1997 Pool PTF Rate until the end of Year Five, and thereafter shall be equal to the pre-1997 Pool PTF Rate for Year Six and thereafter. Alternate B is as follows: 1. The introductory portion of paragraph (3) of Section 25 of the Tariff shall be amended to read as follows: (3) for the period from the effective date of this Tariff until the termination of the transmission agreement: 2. The description of the "Participant RNS Rate" in Schedule 9 to the Tariff shall be amended by modifying the proviso at the end of the second sentence of paragraph (4) of the Schedule to read as follows: provided that in no event shall its pre-1997 Participant RNS Rate be less than 70% of the pre-1997 Pool PTF Rate until the end of Year Five, and thereafter shall be no less than 50% of the pre-1997 Pool PTF Rate for Year Six through Year Ten, and shall be equal to the pre-1997 Pool PTF Rate for Year Eleven and thereafter. and by amending the proviso at the end of the third sentence of paragraph (4) of the Schedule to read as follows: provided that in no event shall its pre-1997 Participant RNS Rate be greater than 130% of the pre-1997 Pool PTF Rate until the end of Year Five and thereafter shall be no greater than 127% of the pre-1997 Pool PTF Rate for Year Six, 123% of the pre-1997 Pool PTF Rate for Year Seven, 118% of the pre-1997 Pool PTF Rate for Year Eight, 112% of the pre-1997 Pool PTF Rate for Year Nine, 105% of the pre-1997 Pool PTF Rate for Year Ten, and shall be equal to the pre-1997 Pool PTF Rate for Year Eleven a and thereafter. SECTION V USAGE OF DEFINED TERMS The usage in this Thirty-Third Agreement of terms which are defined in the Prior NEPOOL Agreement shall be deemed to be in accordance with the definitions thereof in the Prior NEPOOL Agreement. SECTION VI COUNTERPARTS This Thirty-Third Agreement may be executed in any number of counterparts and each executed counterpart shall have the same force and effect as an original instrument and as if all the parties to all the counterparts had signed the same instrument. Any signature page of this Thirty-Third Agreement may be detached from any counterpart of this Thirty-Third Agreement without impairing the legal effect of any signatures thereof, and may be attached to another counterpart of this Thirty-Third Agreement identical in form thereto but having attached to it one or more signature pages. IN WITNESS WHEREOF, each of the signatories has caused a counterpart signature page to be executed by its duly authorized representative, as of the 1st day of December, 1996. COUNTERPART SIGNATURE PAGE TO THIRTY-THIRD AGREEMENT AMENDING NEW ENGLAND POWER POOL AGREEMENT DATED AS OF DECEMBER 1, 1996 The NEPOOL Agreement, being dated as of September 1, 1971, and being previously amended by thirty (30) amendments the most recent of which was dated as of September 1, 1995. EASTERN UTILITIES ASSOCIATES COMPANIES Blackstone Valley Electric Company Eastern Edison Company Montaup Electric Company Newport Electric Company (Participants) By: /s/ Kevin A. Kirby Name: Kevin A. Kirby Title: Vice President Address: 750 West Center Street West Bridgewater, MA 02379-0543 SUPPLEMENTAL AGREEMENT WITH RESPECT TO ALTERNATES A & B The undersigned agrees that either Alternate A or Alternate B as described in Section IV of the foregoing Agreement will be acceptable to it if chosen and accepted by the Commission without significant modifications. Accordingly, the undersigned further agrees that in the event either Alternate A or Alternate B, as described in Section IV of the foregoing Agreement, is chosen and accepted without significant modifications by the Commission, the Tariff shall be deemed to be automatically amended , effective 30 days after the issuance of the Commission's order, to incorporate the accepted Alternate. EASTERN UTILITIES ASSOCIATES COMPANIES Blackstone Valley Electric Company Eastern Edison Company Montaup Electric Company Newport Electric Company (Participants) By: Name: Title: Address: 750 West Center Street West Bridgewater, MA 02379-0543 EX-10 4 EXHIBIT 10-39.05 SEVENTH AMENDMENT TO UNIT POWER AGREEMENT FOR THE SALE OF UNIT CAPACITY AND ENERGY FROM OCEAN STATE POWER TO MONTAUP ELECTRIC COMPANY This Seventh Amendment is entered into this 12th day of February, 1996, by and between Ocean State Power, a Rhode Island general partnership with its principal office in Burrillville, Rhode Island ("Seller"), and Montaup Electric Company, a Massachusetts corporation with its principal office in Boston, Massachusetts ("Buyer"). WHEREAS, Seller and Buyer have entered into a Unit Power Agreement for the Sale of Unit Capacity and Energy from Seller's combined-cycle generation plant located in Burrillville, Rhode Island, dated as of May 14, 1986 (as amended prior to the date hereof, the "Unit Power Agreement"); and WHEREAS, Seller and Buyer propose to amend further the Unit Power Agreement as set forth below. NOW THEREFORE, in consideration of the mutual undertakings and agreements contained in the Unit Power Agreement and in this Seventh Amendment, Seller and Buyer hereby agree to amend the Unit Power Agreement as follows: 1. Definitions. Unless otherwise defined herein, all capitalized terms shall have the respective meanings ascribed to them in the Unit Power Agreement as amended hereby, unless otherwise provided. 2. Amendment. The following new paragraph shall be inserted at the end of Article 7.4: Buyer and Seller agree that if (i) Seller computes the monthly allowance for income taxes pursuant to Article 7.3(b)(2) of this Agreement on the basis of an effective income tax rate (other than for federal income taxes) that differs from the applicable income tax rate as determined by a Competent Taxing Authority, or (ii) Seller's charges for state excise taxes pursuant to Article 7.3(a)(4) of this Agreement differ from the actual liability of Seller or partners in Seller as determined by a Competent Taxing Authority, then Seller shall true-up any such difference, and shall either refund to Buyer or collect from Buyer the Buyer's Share of the difference between the amount previously billed and the amount of (a) the monthly allowance under Article 7.3(b)(2) computed on the basis of such applicable income tax rate, (b) the charges for taxes under Article 7.3(a)(4) based on such actual tax liability of Seller or partners in Seller, and (c) interest and penalties, if any, assessed (or credited in the case of overpayments) by a Competent Taxing Authority with respect to such taxes. Notwithstanding anything to the contrary in this Article 7.4, Seller shall true-up any such tax allowance or charges with respect to any Contract Year at any time during the term of this Agreement or after the termination of this Agreement, irrespective of whether Seller previously had rendered recomputed bills pursuant to Article 7.4; provided, however, that Seller shall render a statement for such true-up not later than three months following a final and non-appealable determination with respect to any such tax liabilities. Seller (or partners in Seller as the case may be) agrees to take reasonable actions to contest or challenge any assessment of taxes subject to true-up pursuant to this paragraph, and the Operating Committee shall determine what reasonable actions should be taken in this regard. For purposes of this Article 7.4, "Competent Taxing Authority" shall mean any state taxing authority having jurisdiction over Seller or partners in Seller with respect to corporate income and corporate excise taxes, and "applicable income tax rate" shall mean the effective rate of corporate income tax found to be applicable to Seller or partners in Seller with respect to income of Seller. 3. Effectiveness. It shall be a condition precedent to the effectiveness of this Seventh Amendment that Seller shall have obtained the consent of the Majority Noteholders (as defined in the Note and Guaranty Agreement, dated October 19, 1992) with respect to this Amendment. IN WITNESS WHEREOF, Seller and Buyer have executed this Seventh Amendment to the Unit Power Agreement for the Sale of Unit Capacity and Energy from Ocean State Power to Montaup Electric Company, as of the date written above. OCEAN STATE POWER, a General Partnership By: JMC Ocean State Corporation, a General Partner By: Michael McCleish Title: Vice President MONTAUP ELECTRIC COMPANY By: /s/ Kevin A. Kirby Kevin A. Kirby Vice President EX-10 5 EXHIBIT 10-40.05 EIGHTH AMENDMENT TO UNIT POWER AGREEMENT FOR THE SALE OF UNIT CAPACITY AND ENERGY FROM OCEAN STATE POWER TO NEWPORT ELECTRIC CORPORATION This Eighth Amendment is entered into this 12th day of February, 1996, by and between Ocean State Power, a Rhode Island general partnership with its principal office in Burrillville, Rhode Island ("Seller"), and Montaup Electric Company, a Massachusetts corporation with its principal office in Boston, Massachusetts ("Buyer"). WHEREAS, Seller and Newport Electric Corporation ("Newport") entered into a Unit Power Agreement for the Sale of Unit Capacity and Energy from Seller's combined-cycle generating plant located in Burrillville, Rhode Island, dated as of May 14, 1986 (as amended prior to the date hereof, the "Unit Power Agreement"); and WHEREAS, under a Consent, Assignment and Assumption Agreement dated March 13, 1994, Newport, with Seller's consent, assigned its rights and obligations under the Unit Power Agreement to Buyer and Buyer assumed those obligations; and WHEREAS, Seller and Buyer propose to amend further the Unit Power Agreement as set forth below. NOW THEREFORE, in consideration of the mutual undertakings and agreements contained in the Unit Power Agreement and in this Eighth Amendment, Seller and Buyer hereby agree to amend the Unit Power Agreement as follows: 1. Definitions. Unless otherwise defined herein, all capitalized terms shall have the respective meanings ascribed to them in the Unit Power Agreement, as amended hereby, unless otherwise provided. 2. Amendment. The following new paragraph shall be inserted at the end of Article 7.4: Buyer and Seller agree that if (i) Seller computes the monthly allowance for income taxes pursuant to Article 7.3(b)(2) of this Agreement on the basis of an effective income tax rate (other than for federal income taxes) that differs from the applicable income tax rate as determined by a Competent Taxing Authority, or (ii) Seller's charges for state excise taxes pursuant to Article 7.3(a)(4) of this Agreement differ from the actual liability of Seller or partners in Seller as determined by a Competent Taxing Authority, then Seller shall true-up any such difference, and shall either refund to Buyer or collect from Buyer the Buyer's Share of the difference between the amount previously billed and the amount of (a) the monthly allowance under Article 7.3(b)( 7) computed on the basis of such applicable income tax rate, (b) the charges for taxes under Article 7.3(a)(4) based on such actual tax liability of Seller or partners in Seller, and (c) interest and penalties, if any, assessed (or credited in the case of overpayments) by a Competent Taxing Authority with respect to such taxes. Notwithstanding anything to the contrary in this Article 7.4, Seller shall true-up any such tax allowance or charges with respect to any Contract Year at any time during the term of this Agreement or after the termination of this Agreement, irrespective of whether Seller previously had rendered recomputed bills pursuant to Article 7.4; provided, however, that Seller shall render a statement for such true-up not later than three months following a final and non-appealable determination with respect to any such tax liabilities. Seller (or partners in Seller as the case may be) agrees to take reasonable actions to contest or challenge any assessment of taxes subject to true-up pursuant to this paragraph, and the Operating Committee shall determine what reasonable actions should be taken in this regard. For purposes of this Article 7.4, "Competent Taxing Authority" shall mean any state taxing authority having jurisdiction over Seller or partners in Seller with respect to corporate income and corporate excise taxes, and "applicable income tax rate" shall mean the effective rate of corporate income tax found to be applicable to Seller or partners in Seller with respect to income of Seller. 3. Effectiveness. It shall be a condition precedent to the effectiveness of this Eighth Amendment that Seller shall have obtained the consent of the Majority Noteholders (as defined in the Note and Guaranty Agreement, dated October 19, 1992) with respect to this Amendment. IN WITNESS WHEREOF, Seller and Buyer have executed this Eighth Amendment to the Unit Power Agreement for the Sale of Unit Capacity and Energy from Ocean State Power to Newport Electric Corporation, as of the date written above. OCEAN STATE POWER, a General Partnership By: JMC Ocean State Corporation, a General Partner By: Michael McCleish Title: Vice President MONTAUP ELECTRIC COMPANY By: /s/ Kevin A. Kirby Kevin A. Kirby Vice President EX-10 6 EXHIBIT 10-41.05 THIRD AMENDMENT TO UNIT POWER AGREEMENT FOR THE SALE OF UNIT CAPACITY AND ENERGY FROM OCEAN STATE POWER II TO MONTAUP ELECTRIC COMPANY This Third Amendment is entered into this 12th day of February, 1996, by and between Ocean State Power II, a Rhode Island general partnership with its principal office in Burrillville, Rhode Island ("Seller"), and Montaup Electric Company, a Massachusetts corporation with its principal office in Boston, Massachusetts ("Buyer"). WHEREAS, Seller and Buyer have entered into a Unit Power Agreement for the Sale of Unit Capacity and Energy from Seller's combined-cycle generating plant located in Burrillville, Rhode Island, dated as of September 28, 1988 (as amended prior to the date hereof, the "Unit Power Agreement"); and WHEREAS, Seller and Buyer propose to amend further the Unit Power Agreement as set forth below. NOW THEREFORE, in consideration of the mutual undertakings and agreements contained in the Unit Power Agreement and in this Third Amendment, Seller and Buyer hereby agree to amend the Unit Power Agreement as follows: 1. Definitions. Unless otherwise defined herein, all capitalized terms shall have the respective meanings ascribed to them in the Unit Power Agreement, as amended hereby, unless otherwise provided. 2. Amendment. The following new paragraph shall be inserted at the end of Article 7.4: Buyer and Seller agree that if (i) Seller computes the monthly allowance for income taxes pursuant to Article 7.3(b)(2) of this Agreement on the basis of an effective income tax rate (other than for federal income taxes) that differs from the applicable income tax rate as determined by a Competent Taxing Authority, or (ii) Seller's charges for state excise taxes pursuant to Article 7.3(a)(4) of this Agreement differ from the actual liability of Seller or partners in Seller as determined by a Competent Taxing Authority, then Seller shall true-up any such difference, and shall either refund to Buyer or collect from Buyer the Buyer's Share of the difference between the amount previously billed and the amount of (a) the monthly allowance under Article 7.3(b)(2) computed on the basis of such applicable income tax rate, (b) the charges for taxes under Article 7.3(a)(4) based on such actual tax liability of Seller or partners in Seller, and (c) interest and penalties, if any, assessed (or credited in the case of overpayments) by a Competent Taxing Authority with respect to such taxes. Notwithstanding anything to the contrary in this Article 7.4, Seller shall true-up any such tax allowance or charges with respect to any Contract Year at any time during the term of this Agreement or after the termination of this Agreement, irrespective of whether Seller previously had rendered recomputed bills pursuant to Article 7.4; provided, however, that Seller shall render a statement for such true-up not later than three months following a final and non-appealable determination with respect to any such tax liabilities. Seller (or partners in Seller as the case may be) agrees to take reasonable actions to contest or challenge any assessment of taxes subject to true-up pursuant to this paragraph, and the Operating Committee shall determine what reasonable actions should be taken in this regard. For purposes of this Article 7.4, "Competent Taxing Authority" shall mean any state taxing authority having jurisdiction over Seller or partners in Seller with respect to corporate income and corporate excise taxes, and "applicable income tax rate" shall mean the effective rate of corporate income tax found to be applicable to Seller or partners in Seller with respect to income of Seller. 3. Effectiveness. It shall be a condition precedent to the effectiveness of this Third Amendment that Seller shall have obtained the consent of the Majority Noteholders (as defined in the Note and Guaranty Agreement, dated October l9, 1992) with respect to this Amendment. IN WITNESS WHEREOF, Seller and Buyer have executed this Third Amendment to the Unit Power Agreement for the Sale of Unit Capacity and Energy from Ocean State Power II to Montaup Electric Company, as of the date written above. OCEAN STATE POWER II, a General Partnership By: JMC Ocean State Corporation, a General Partner By: /s/ Michael McCleish Title: Vice President MONTAUP ELECTRIC COMPANY By: /s/ Kevin A. Kirby Kevin A. Kirby Vice President EX-10 7 EXHIBIT 10-42.05 FOURTH AMENDMENT TO UNIT POWER AGREEMENT FOR THE SALE OF UNIT CAPACITY AND ENERGY FROM OCEAN STATE POWER II TO NEWPORT ELECTRIC CORPORATION This Fourth Amendment is entered into this 12th day of February, 1996, by and between Ocean State Power II, a Rhode Island general partnership with its principal office in Burrillville, Rhode Island ("Seller"), and Montaup Electric Company, a Massachusetts corporation with its principal office in Boston, Massachusetts ("Buyer"). WHEREAS, Seller and Newport Electric Corporation ("Newport") entered into a Unit Power Agreement for the Sale of Unit Capacity and Energy from Seller's combined-cycle generating plant located in Burrillville, Rhode Island, dated as of July 12, 1988 (as amended prior to the date hereof, the "Unit Power Agreement"); and WHEREAS, under a Consent, Assignment and Assumption Agreement dated March 1, 1994, Newport, with Seller's consent, assigned its rights and obligations under the Unit Power Agreement to Buyer and Buyer assumed those Obligations; and WHEREAS, Seller and Buyer propose to amend further the Unit Power Agreement as set forth below. NOW THEREFORE, in consideration of the mutual undertakings and agreements contained in the Unit Power Agreement and in this Fourth Amendment, Seller and Buyer hereby agree to amend the Unit Power Agreement as follows: 1. Definitions. Unless otherwise defined herein, all capitalized terms shall have the respective meanings ascribed to them in the Unit Power Agreement, as amended hereby, unless otherwise provided. 2. Amendment. The following new paragraph shall be inserted at the end of Article 7.4: Buyer and Seller agree that if (i) Seller computes the monthly allowance for income taxes pursuant to Article 7.3(b)(2) of this Agreement on the basis of an effective income tax rate (other than for federal income taxes) that differs from the applicable income tax rate as determined by a Competent Taxing Authority, or (ii) Seller's charges for state excise taxes pursuant to Article 7.3(a)(4) of this Agreement differ from the actual liability of Seller or partners in Seller as determined by a Competent Taxing Authority, then Seller shall true-up any such difference, and shall either refund to Buyer or collect from Buyer the Buyer's Share of the difference between the amount previously billed and the amount of (a) the monthly allowance under Article 7.3(b)(2) computed on the basis of such applicable income tax rate, (b) the charges for taxes under Article 7.3(a)(4) based on such actual tax liability of Seller or partners in Seller, and (c) interest and penalties, if any, assessed (or credited in the case of overpayments) by a Competent Taxing Authority with respect to such taxes. Notwithstanding anything to the contrary in this Article 7.4, Seller shall true-up any such tax allowance or charges with respect to any Contract Year at any time during the term of this Agreement or after the termination of this Agreement, irrespective of whether Seller previously had rendered recomputed bills pursuant to Article 7.4; provided, however, that Seller shall render a statement for such true-up not later than three months following a final and non-appealable determination with respect to any such tax liabilities. Seller (or partners in Seller as the case may be) agrees to take reasonable actions to contest or challenge any assessment of taxes subject to true-up pursuant to this paragraph, and the Operating Committee shall determine what reasonable actions should be taken in this regard. For purposes of this Article 7.4, "Competent Taxing Authority" shall mean any state taxing authority having jurisdiction over Seller or partners in Seller with respect to corporate income and corporate excise taxes, and "applicable income tax rate" shall mean the effective rate of corporate income tax found to be applicable to Seller or partners in Seller with respect to income of Seller. 3 . Effectiveness. It shall be a condition precedent to the effectiveness of this Fourth Amendment that Seller shall have obtained the consent of the Majority Noteholders (as defined in the Note and Guaranty Agreement, dated October l9, 1992) with respect to this Amendment. IN WITNESS WHEREOF, Seller and Buyer have executed this Fourth Amendment to the Unit Power Agreement for the Sale of Unit Capacity and Energy from Ocean State Power II to Newport Electric Corporation, as of the date written above. OCEAN STATE POWER II, a General Partnership By: JMC Ocean State Corporation, a General Partner, By: /s/ Michael McCleish Title: Vice President MONTAUP ELECTRIC COMPANY By: /s/ Kevin A. Kirby Kevin A. Kirby Vice President EX-13 8 EXHIBIT 13-1.03 EUA ANNUAL REPORT Eastern Utilities A diversified energy services company leading the way into the era of electric utility competition 1996 Annual Report EUA System Profile Eastern Utilities Associates is a diversified energy services company whose shares are traded on the New York and Pacific Stock Exchanges under the ticker symbol EUA. Its subsidiaries are engaged in the generation, transmission, distribution and sale of electricity, and energy-related services such as energy management and conservation and efficient use of energy. To better reflect the competitive business environment in which it operates, EUA is organized in four distinct business units. Core Electric Business EUA's core electric business comprises two business units. The retail business unit provides electric distribution service to approximately 299,000 customers in southeastern Massachusetts, and northern and coastal Rhode Island. Electric distribution subsidiaries are Blackstone Valley Electric Company, Eastern Edison Company and Newport Electric Corporation. The wholesale business unit is Montaup Electric Company, EUA's generation and transmission subsidiary, which provides electricity at whole sale to the electric distribution subsidiaries and two other non-affiliated municipal electric utilities, and high voltage transmission services. Energy Related Business EUA's energy related business unit includes EUA Cogenex Corporation, EUA Ocean State Corporation, EUA Energy Investment Corporation and EUA Energy Services Corporation which owns our interest in Duke/Louis Dreyfus Energy Services (New England) LLC, a power marketing partnership. EUA Cogenex is the most active of our energy related companies with energy services contracts throughout the United States and Canada. EUA Ocean State owns a 29.9% partnership interest in the Ocean State Power electric generating station in northern Rhode Island. EUA Energy Investment makes investments in energy related businesses. Duke/Louis Dreyfus Energy Services plans to market energy and energy related services in New England. Corporate The corporate business unit is made up of Eastern Utilities Associates - the System's parent company - and EUA Service Corporation which provides professional and technical services to all EUA System companies. Cover: The reorganization of our industry required the untiring efforts of many members of the EUA team. Our employees are working together with all our constituents to smooth the transition from monopoly to competition. The photos in the continuum of this annual report reflect the diversity and diligence of their contributions. To Our Shareholders Dear Shareholder: 1996 was a defining year for the electric utility industry in New England, including Eastern Utilities Associates. It was a year in which we were continually challenged to be flexible and innovative. Regulatory and legislative initiatives addressing electric utility restructuring created an atmosphere of uncertainty about the future. Massachusetts and Rhode Island, the two states in which EUA's utility subsidiaries do business, are at the forefront of electric utility industry restructuring. We took a proactive role in working with all stakeholders in the restructuring process to bring about a consensus that is fair to all. By year's end, there was no question that the age of utility competition had arrived. The uncertainty created by utility restructuring negatively impacted the electric utility industry nationwide and particularly in New England. Coupled with the poor performance of EUA Cogenex and EUA Energy Investment it led to EUA's common shares underperforming during 1996. The performance of our Energy Related Businesses was, for the most part, a disappointment in 1996. While our EUA Ocean State subsidiary continued to provide a significant contribution to earnings - our investments in EUA Cogenex and EUA Energy Investment did not meet expectations and operated at a loss. EUA's 1996 consolidated net earnings of $30.6 million represented a 6.2% decrease from those in 1995, a year that was also disappointing. EUA Cogenex's operating losses, which included a one-time charge of 18 cents per share, the unusual number of severe storms which struck our service territory in 1996, and increased outage costs related to the Millstone III nuclear generating plant negatively impacted 1996 results. While earnings were less than expected, EUA continues to maintain a strong cash position. Cash flow per share for 1996 was $5.44. The EUA System continues to generate more than 100% of its cash construction needs internally. This strong cash flow, coupled with the underlying earnings of our Core Electric Business, enabled us to increase the dividend by 3.8% in May, 1996 to its current annual rate of $1.66 per share. Our goal has been to provide our shareholders with annual dividend increase s, greater than the utility industry average, while maintaining a conservative payout ratio. While our goal has not changed we recognize that the developing competitive market for both our Core Electric Business and diversified operations requires u s to proceed cautiously. The section following this letter entitled "The Competitive Revolution" provides more detail on the regulatory and legislative initiatives impacting our Core Electric Business and the competitive forces that have slowed the progress of our Energy Related Businesses. Not everything that happened during 1996 was negative. Teamwork enabled us to meet the many challenges we faced in creative ways. (Teams of EUA employees working together and with our customers appear in the photos running along these pages.) Positive developments in 1996 included: - The regulatory and legislative initiatives in Massachusetts and Rhode Island are now taking shape, removing much of the uncertainty surrounding utility restructuring and its impact on our Core Electric Business. Our proactive involvement in the restructuring process, which led to settlement agreements in Massachusetts and Rhode Island, and our role in building consensus for Rhode Island's Utility Restructuring Act show that we are ready to move into the competitive arena. Movement into the competitive arena may result in EUA divesting its entire generation portfolio. - We made strategic moves during 1996 to put Cogenex back on the path to profitability. Enhancing and refocusing of the Cogenex sales and marketing efforts in the third quarter and a workforce reduction at year's end, together with additional cost saving measures, should help Cogenex return to profitability in the second half of 1997. - The development of a prototype biomass-fueled combustion turbine in Tennessee by the BIOTEN general partnership, in which we hold a 40% interest. Testing of the unit has been encouraging to date. - The June purchase by our EUA Energy Investment subsidiary of a 20% ownership interest in Separation Technologies, a Massachusetts company which develops and installs high volume materials separation equipment using proprietary technology. The company's patented system to separate unburned carbon from coal ash provides coal-burning power plants with a marketable by- product at the same time it reduces potential environmental consequences associated with the disposal of high-carbon fly-ash. The system has been proven in commercial use. Customer interest from throughout the United States and Europe makes this an investment that has the potential of making a positive contribution to earnings in 1997. - Although TransCapacity, our subsidiary which develops gas industry software, continued to operate at a loss during 1996, we are encouraged by the fact that in late 1996 the Federal Energy Regulatory Commission (FERC) issued new directives which require gas pipelines to phase in compliance with electronic data interchange (EDI) regulations during April, May and June of 1997. TransCapacity's T/Nominatr TM product is in full compliance with these mandated FERC standards for transporting natural gas. Pipeline compliance with FERC mandates during the second quarter of 1997 will be critical to TransCapacity's success. The teamwork of our dedicated workforce in all aspects of our business enabled EUA to successfully meet many of its challenges in this past tumultuous year. That won't change. If anything, the need to find innovative ways to build our business in t he competitive arena means we must continue our commitment to finding creative ways to perform at ever higher levels. We thank the employees who, as a team, restored power after 18 storms, worked harder with fewer resources to continue to provide excellent customer service, and who served on the restructuring teams that continued the reorganization of our company in 1996. We are confident that this team effort will help us meet the many challenges we will face as we go forward in the competitive era. Your management team recognizes that 1996 was a disappointing year. Our team is fully committed to reversing the downward trend in earnings and restoring greater value to your EUA Common Shares. Donald G. Pardus John R. Stevens Chairman and Chief Executive Officer President and Chief Operating Officer March 11, 1997 Highlights
1996 1995 1994 FINANCIAL DATA ($ in thousands) Operating Revenues $ 527,068 $ 563,363 $ 564,278 Consolidated Net Earnings 30,614 32,626 47,370 Return on Average Common Equity 8.2% 8.8% 13.6% Common Shareholder Equity- % of Capitalization (Year-End) 45.8% 44.5% 42.8% Total Assets 1,257,029 1,206,130 1,234,049 Cash Construction Expenditures 62,730 77,923 50,519 COMMON SHARE DATA Consolidated Earnings per Share $ 1.50 $ 1.61 $ 2.41 Dividends Paid per Share $ 1.645 $ 1.585 $ 1.515 Annual Dividend Rate $ 1.66 $ 1.60 $ 1.54 Total Common Shares Outstanding 20,435,997 20,436,764 19,936,980 Average Common Shares Traded Daily 91,843 58,573 35,359 Book Value per Share (Year-End) $ 18.19 $ 18.36 $ 18.33 Market Price - High 24 1/4 25 27 3/8 - Low 14 3/4 21 1/2 21 3/8 - Year-End 17 3/8 23 5/8 22 OPERATING DATA Total Primary Sales (mWh) 4,491,000 4,441,000 4,410,000 System Requirements (mwh) 4,699,000 4,668,000 4,643,000 System Peak Demand (mw) 854 931 921 System Reserve Margin (At Peak) 34.4% 24.2% 22.4% System Load Factor 62.6% 57.2% 57.5% Customers (Year-End) 299,471 297,331 293,707 Employees (Year-End) - Core Electric 468 541 720 - Energy Related 213 253 240 - Corporate 564 536 437 See Management's Discussion and Analysis of Financial Condition and Results of Operations for details of one-time impacts to earnings. Reflects employee shift resulting from corporate reorganization.
The Competitive Revolution The Age of Utility Competition Is Here New England, home of the Industrial Revolution two centuries ago, is leading the nation in the Competitive Revolution sweeping through the electric utility industry today. Massachusetts and Rhode Island - home of Eastern Utilities Associates' (EUA) electric distribution subsidiaries - are at the forefront of states restructuring the way electric utilities conduct business. The age of competition for electric utility customers is here. EUA restructuring teams worked throughout the year with regulators, legislators and various stakeholders in both states to produce a blueprint for a restructured electric utility industry. Our teams provided comments to the Federal Energy Regulatory Commission (FERC) during that agency's consideration of rules to open the nation's bulk transmission system to wholesale competition. The ground rules have been set in Massachusetts and Rhode Island and a broad outline drawn at the federal level. Regulators and legislators recognize the importance of an economically sound electric utility industry to maintain reliability of service and safety. The rules to implement competition in both Massachusetts and Rhode Island treat all stakeholders fairly. They afford a framework for us to provide immediate customer cost savings and provide for the recovery of the historic investments incurred to build power plants that provide safe, reliable electric service, that may not be able to compete on an economic basis - often referred to as "stranded costs." By doing so, these rules maximize the benefits of competition for both our shareholders and our customers. How? They remove much of the uncertainty about stranded cost recovery ensuring the continued financial health of our utility operations while providing for the opportunity of additional cost reductions and service benefits for our customers as the competitive electricity market matures. At the same time, the advent of competition provides the vehicle to continue to pursue power marketing opportunities in the six New England States with Duke/Louis Dreyfus Energy Services (New England), our partnership with Duke Energy Marketing and Louis Dreyfus Electric Power. The provisions of our settlement agreements in Massachusetts and Rhode Island are consistent with those aims. Federal Energy Regulatory Commission Spurs Competition On the national level, FERC's order opening bulk power transmission lines to all users on a non-discriminatory basis provides the framework for an equitable competitive wholesale power market. Montaup Electric Company (Montaup), EUA's electric generation subsidiary, filed its open-access rates with FERC to ensure that all potential power suppliers will have the appropriate access to EUA System transmission lines. Application of these rate s for competitive generation sources will begin when Massachusetts and Rhode Island formally open to competition. Also, the New England Power Pool (NEPOOL) has filed an amendment with FERC which provides for an independent system operator of New England's bulk power system, market-based pricing and easier entry into NEPOOL membership by power marketers, brokers and load aggregators. Rhode Island Legislation Leads the Way While the general principles are effectively the same in Massachusetts and Rhode Island, the states approached restructuring from different directions. In Rhode Island, competition was brought into being with history-making legislation. The state's Utility Restructuring Act of 1996 (URA) made Rhode Island the first state to legislate competition among electric utilities. We worked with the governor and the leadership of Rhode Island's legislative bodies to reach consensus among the many interested parties while the legislation was under debate. Critical issues were addressed in a responsible manner, enabling Rhode Island to enact legislation that may well serve as a model for other states in their approach to restructuring the electric utility industry. The Rhode Island legislation provides for unbundling of electric service into generation, transmission, and distribution functions, recovery of stranded costs, performance incentives for distribution services, and phases competition into effect. The state's largest users may choose their supplier starting July 1, 1997; competition will be open to all customers no later than July 1, 1998. While the legislation opens the state to competition, it also allows customers to elect to continue to take full service from their local distribution company. The distribution company will arrange for generation, or supply, at a non-discriminatory " standard offer" price for those customers. The law also provides for adjustments to the distribution companies' base rates using the prior year's Consumer Price Index and other performance factors. In February 1997, Blackstone Valley Electric Company (Blackstone), Newport Electric Corporation (Newport) and Montaup reached a settlement with the Rhode Island Division of Public Utilities and Carriers and the state's Attorney General. In addition to complying with the URA, the settlement, to be formally submitted to the Rhode Island Public Utilities Commission (RIPUC) in March 1997, provides for an immediate 10% rate deduction and the filing of a plan to divest all of Montaup's generating assets. Massachusetts: Negotiation and Regulation Rather than the legislative approach taken in Rhode Island, Massachusetts moved into the competitive era through the regulatory arena and through the vehicle of negotiated settlements between utilities, the state's Division of Energy Resources (DOER) and Attorney General, whose "Consumers First" initiative envisions that all customers will have their choice of electricity supplier effective January 1, 1998. Regulators, the DOER and the Attorney General took the view that a restructured utility industry must lead to lower costs, over time, for all consumers of electricity. In December 1996, Eastern Edison Company (Eastern Edison), our Massachusetts electric distribution subsidiary, and Montaup reached a settlement in principle with the Attorney General and the DOER. Our settlement agreement provides for, among other things, a 10% reduction in the total cost of electric service to our Eastern Edison customers when competition starts, while at the same time providing for full recovery of our stranded costs through a non-bypassable transition charge. The settlement also recognizes our need to fully recover our stranded costs in order to remain financially viable and provides for the filing of a plan to divest all of Montaup's generating assets. At the end of the year, the Massachusetts Department of Public Utilities (MDPU) announced its model rules and legislative proposal for a restructured utility industry. The MDPU describes the package as a "framework to ensure full and fair competition in the generation of electric power and model rules to implement that framework." Legislation, introduced in 1997, is needed to provide regulators with the authority to fully implement their model rules. Our settlement with the Attorney General and the DOER is expected to be filed with the MDPU in March 1997. Stranded Cost Recovery The Rhode Island legislation and our Massachusetts and Rhode Island settlements provide for full recovery of above market net investments in generating facilities, with a return, over 12 years via a non-bypassable transition charge passed through to all retail customers in both states. Proceeds realized from the sale of any or all generating assets (market value) will be used to mitigate the transition charge. Commitments to nuclear power are treated somewhat differently. New England's commitment to nuclear power was made at a time when nuclear power was considered the best available option to reduce dependence on oil and protect the environment. Many of those nuclear power plants may not be able to compete cost effectively with newer generation sources. Regulators and legislators recognize the need to ensure that funds are available to safely decommission nuclear plants at the end of their useful lives. Costs of decommissioning nuclear power plants will be recovered as incurred via the non-bypassable transition charge over the remaining life of each unit. EUA does not operate any of New England's nuclear generators, though we are joint owners of some and are obligated under power purchase contracts to others. Also, a utility's commitments under power purchase contracts will be compared to prevailing market costs of electricity. Any contract costs above or below market rates will be charged or credited to customers through the transition charge for the duration of the individual contracts. EUA believes its transition charge is the second lowest among Massachusetts utilities. How Competition Will Work In a competitive marketplace, traditional utility services - generation, transmission, and distribution - will be unbundled into separate and distinct services. Customers will be permitted to choose their own electric supplier at an open market price. Distribution and transmission services will remain regulated. Just as the local telephone company continues to deliver the long distance service chosen by the customer, the local electric distribution company - Eastern Edison, Blackstone, and Newport, in our case - retains the responsibility of providing electric distribution services to all customers no matter who supplies the electricity. The distribution companies also arrange for the power supply for customers who "choose not to choose," at a "standard offer" price. We plan to put the standard offer energy requirement out to bid, with Montaup or a successor serving as the backstop generation source. As a result, Montaup plans to file an application with FERC to replace its all-requirements power contracts with our three electric distribution companies with a contract termination charge to recover stranded costs. The distribution companies will collect these costs from ultimate electricity consumers through the non- bypassable transition charge discussed above. As previously mentioned, the rates customers pay for electric distribution and transmission services will continue to be regulated. But they won't be regulated in the same way as in the past. Historically, regulators allowed utilities to recover their costs of doing business, plus a specified "fair return" on the investment of the utility's shareholders. Under this type of regulation - known as cost of service regulation - utilities periodically applied to regulators for changes in rates to c over known or anticipated changes in costs. In the restructured environment of the competitive marketplace, rates charged by distribution companies will incorporate performance standards, commonly referred to as performance-based regulation. Under this technique, rates are set for a specified period - five years, for example - during which the utility is encouraged to manage its costs prudently to earn a premium return while being penalized for not achieving specific agreed-upon regulated performance objectives. Utility returns, or earnings, will be subject to a guaranteed floor and a ceiling. Utilities which manage well can keep some of their savings; those that manage poorly are penalized by lower earnings and/or pre-determined penalty charges. This is another area where our efforts have already proven effective. Since 1990 we have reduced the workforce of our Corporate and Core Electric businesses by 23% through a combination of normal attrition and voluntary retirement. In that same time period, our employees held the line on operation and maintenance costs. We consolidated management of our utilities into a single structure in 1995, further reducing costs. We will continue to find creative solutions to the new challenges raised by competition, responding with ever more creative approaches, including continued cross-functional staff assignments, and more efficient use of existing equipment. Energy-Related Business Continues To Be Important While a great proportion of our attention was devoted to ensuring that we remain a financially strong utility in the age of competition, our Energy Related Businesses are also important. This business unit includes our non- utility investments design ed to enhance shareholder value over the long-term, and it remains a key factor in our strategy for growth. EUA Ocean State, with its 29.9% ownership interest in Ocean State Power's twin 250-megawatt, gas-fired generating units, will continue to provide significant earnings contributions for the foreseeable future. EUA Cogenex Corporation (EUA Cogenex), the largest of our energy-related subsidiaries, provides energy efficiency products and energy-management services throughout North America. Despite a financially difficult year, EUA Cogenex remains a national leader in the energy services field. In the third quarter of 1996, EUA Cogenex refocused its sales efforts. Also, EUA Cogenex reduced its year-end 1995 employee level by 22% through a combination of attrition and a year-end workforce reduction in 1 996. A return to profitability for EUA Cogenex is expected in the second half of 1997. TransCapacity, our limited partnership which provides advanced information systems to the natural gas industry, performed below our expectations in 1996. We continue to expand the capability of its product T/Nominatr TM, which provides clients with a single interface for making electronic data interchange (EDI) notifications to move gas throughout multiple pipelines. T/Nominatr TM is in full compliance with standards recently mandated by FERC for transporting natural gas. Unfortunately, FERC delayed required compliance with these standards until the second quarter of 1997. Because of delays by pipelines in effecting EDI services, TransCapacity did not make a positive contribution to 1996 earnings. We expect that TransCapacity will start making positive contributions by year-end 1997. Our BIOTEN partnership is in the final stages of testing its prototype biomass generation unit. These units can solve disposal problems for producers of large amounts of environmentally hazardous sawdust while producing electricity. Its biomass-fired combustion turbine technology has received significant interest from both potential buyers and fabricators. And, our newest investment, a 20% ownership interest in Separation Technologies, Inc., is expected to make a positive earnings contribution during 1997. Potential customers throughout the United States and in Europe have shown strong interest in the company's proprietary system to separate unburned carbon from coal ash, providing coal-burning power plants with a marketable product - high quality fly-ash - at the same time it reduces a potential environmental disposal problem. The system has be en proven in commercial use at New England power plants. This company fits well with our goal of finding niche-type energy-related investments for our EUA Energy Investment subsidiary. We're Ready for Competition Competition in the electric utility industry is well underway - at a much quicker pace than anyone might have thought possible a year ago. Certainly, not every issue of the competitive generation market and the new regulatory environment has been addressed. But, our success in building consensus in Massachusetts and Rhode Island shows that the private and public sectors can, indeed, work as a team to treat all stakeholders fairly in such a complex situation. Our team has built strong skills in meeting the challenge of being among the first to enter the competitive arena. We are ready to enter that arena, and to act quickly to seize the opportunities presented by competition. To counter revenue reductions anticipated during 1998 from the 10% rate reduction required in the Rhode Island and Massachusetts settlement agreements, we will continue to find ways to reduce costs and improve our operating efficiency. Selected Consolidated Financial Data Years Ended December 31, (In Thousands Except Common Share Data) 1996 1995 1994 1993 1992
INCOME STATEMENT DATA: Operating Revenues $ 527,068 $ 563,363 $ 564,278 $ 566,477 $ 541,964 Operating Income 55,841 71,728 73,795 75,649 64,347 Consolidated Net Earnings 30,614 32,626 47,370 44,931 34,111 BALANCE SHEET DATA: Plant in Service 1,067,056 1,037,662 1,020,859 1,016,453 1,002,717 Construction Work in Progress 3,839 7,570 8,389 8,728 4,943 Gross Utility Plant 1,070,895 1,045,232 1,029,248 1,025,181 1,007,660 Accumulated Depreciation and Amortization 350,816 324,146 304,034 296,995 274,725 Net Utility Plant 720,079 721,086 725,214 728,186 732,935 Total Assets 1,257,029 1,206,130 1,234,049 1,203,137 1,203,320 CAPITALIZATION: Long-Term Debt - Net 406,337 434,871 455,412 496,816 462,958 Redeemable Preferred Stock - Net 27,035 26,255 25,390 25,053 28,496 Non-Redeemable Preferred Stock - Net 6,900 6,900 6,900 6,900 15,850 Common Equity 371,813 375,229 365,443 333,165 266,855 Total Capitalization 812,085 843,255 853,145 861,934 774,159 Short-Term Debt 51,848 39,540 31,678 37,168 109,936 COMMON SHARE DATA: Consolidated Earnings per Average Common Share $ 1.50 $ 1.61 $ 2.41 $ 2.44 $ 2.00 Average Number of Shares Outstanding 20,436,217 20,238,961 19,671,970 18,391,147 17,039,224 Return on Average Common Equity 8.2% 8.8% 13.6% 15.0% 13.2% Market Price - High 24 1/4 25 27 3/8 29 7/8 25 1/4 - Low 14 3/4 21 1/2 21 3/8 23 7/8 20 3/8 - Year-End 17 3/8 23 5/8 22 28 24 3/4 Dividends Paid per Share $ 1.645 $ 1.585 $ 1.515 $ 1.42 $ 1.36 See Management's Discussion and Analysis of Financial Condition and Results of Operations for details of one-time impacts to earnings.
Management's Discussion and Analysis of Financial Condition and Review of Operations Overview Consolidated net earnings for 1996 were $30.6 million, or $1.50 per share, on revenues of $527.1 million, compared with 1995 earnings of $32.6 million, or $1.61 per share, on revenues of $563.4 million. The results for both years include one-time, after-tax charges to earnings, discussed below, and listed in the following table. Net Earnings and Earnings Per Share by business unit for 1996 and 1995 were as follows: 1996 1995 Net Earnings (Loss) Earnings (Loss) Net Earnings (Loss) Earnings (Loss) (000's) Per Share (000's) Per Share Core Electric Business $ 37,595 $ 1.84 $ 42,062 $ 2.08 Energy Related Business (2,738) (0.13) 3,658 0.18 Corporate (571) (0.03) 151 0.01 From Operations $ 34,286 $ 1.68 $ 45,871 $ 2.27 One-Time Impacts: Cogenex Charge (3,672) (0.18) Voluntary Retirement Incentive (2,747) (0.14) Cogeneration Discontinuance (10,498) (0.52) Consolidated $ 30,614 $ 1.50 $ 32,626 $ 1.61
Major impacts on earnings by business unit are described in the following paragraphs. Cogenex Charge to Earnings Difficulties in turning project proposals into signed contracts, the virtual elimination of utility-sponsored demand side management programs and the termination of the AYP Capital and Westar joint ventures hampered EUA Cogenex earnings. As a result, a write-off of certain start-up costs of abandoned joint ventures, and expenses related to certain project proposals along with a reduction in carrying value of certain ongoing projects necessitated by current market conditions resulted in a $5.9 million pre-tax ($3.7 million after-tax or 18 cents per share) charge to earnings in the second quarter of 1996. In an effort to refocus its sales activity, EUA Cogenex replaced virtually all of its sales staff with individuals possessing more experience and proven sales capability in the energy efficiency market. Cogenex has also restructured its NOVA Division because of changing market conditions. While EUA believes that the energy efficiency market still provides a viable business opportunity for EUA Cogenex, it will be important for EUA Cogenex to improve its sales activity and reduce its overhead burdens. Voluntary Retirement Incentive (VRI) Offer In March 1995, EUA announced a corporate reorganization which, among other things, consolidated management of Eastern Edison, Blackstone and Newport. As part of the reorganization, a VRI was offered to 66 professionals within the EUA System. Forty-nine of those eligible for the program accepted the incentive and retired effective June 1, 1995. This incentive program resulted in a one-time $4.5 million pre-tax ($2.7 million after-tax, or 14 cents per share) charge to second quarter 1995 earnings of the Core Electric Business. Discontinuation of Cogeneration Operations In September 1995, EUA announced that EUA Cogenex was discontinuing its cogeneration operations because overall, the cogeneration portfolio had not performed up to expectations. EUA Cogenex's total net investment in its cogeneration portfolio was $2 9.2 million. The decision to discontinue cogeneration operations resulted in a one-time, after-tax charge to third quarter 1995 earnings of approximately $10.5 million, or 52 cents per share. Operating Revenues The following table sets forth estimates of the factors which contributed to the change in Operating Revenues from 1994 through 1996: Increase (Decrease) From Prior Years ($ in millions) 1996 1995 Operating Revenue change attributable to: Core Electric Business: Purchased Power Recovery $ (7.0) $ (2.5) Recovery of Fuel Costs 0.2 11.8 Recovery of C&LM Expenses (5.4) (3.9) Effect of Rate Changes (4.9) Unit Contracts and Sales to NEPOOL 0.6 (8.2) Kilowatthour (kWh) Sales and Other (1.5) 1.8 Energy Related Business: EUA Cogenex (23.2) 5.0 Total Operating Revenues $(36.3) $(0.9) Core Electric Business: The revenues attributable to Purchased Power Recovery reflect our retail companies' recovery of purchased power capacity costs. Revenues attributable to Recovery of Fuel Costs and conservation and load management (C&LM) expenses result from the operation of adjustment clauses. The change in such revenues reflects corresponding underlying changes in costs. The Effect of Rate Changes reflects a base rate decrease for Montaup implemented on May 21, 1994. Revenues attributable to Unit Contracts and sales to NEPOOL reflect energy revenues from such short-term contracts and interchange sales with NEPOOL. The change in revenues associated with kWh Sales and Other reflects the effect of kWh sales and demand billings on base revenues and changes in other operating revenues including off-system contract demand sales. Energy Related Business: EUA Cogenex revenues, which account for virtually all of the Energy Related Business Unit revenues, decreased by $23.2 million in 1996. This decrease was due primarily to lower project sales of approximately $18.8 million, the absence of cogeneration revenues which aggregated $5.5 million in 1995 and decreased EUA Nova revenues of $7.9 million. These decreases were offset somewhat by increased revenues of EUA Highland, EUA Citizens and EUA Day aggregating $8.8 million . The 1995 change was due primarily to the impact of EUA Cogenex's acquisitions of Highland Energy Group (Highland) and Citizens Conservation Corporation (Citizens) in 1995. Core Electric Business kWh Sales Primary kWh sales of electricity by EUA's Core Electric Business Unit increased by a modest 1.1% in 1996 compared to the prior year. This change was led by an increase of 2.6% in the residential customer class, which is typically more weather sensitive. The first and second quarter increases, largely due to colder weather, were mitigated by the third and fourth quarter results, when we saw a milder than normal weather pattern. Total energy sales increased by 2.0%, mainly due to increased sales to NEPOOL, slightly offset by decreased short-term unit contract energy sales. Primary kWh sales of electricity by EUA's Core Electric Business unit increased by 0.7% in 1995 compared to 1994. Total energy sales decreased 11.1% in 1995, due mainly to decreased energy sales to NEPOOL and decreased short-term unit contract sales. Purchased power contracts of Montaup totaling 41 megawatts (mw) which expired in October 1994 resulted in lower kWh available to Montaup for interchange and short-term energy sales. These interchange and short-term energy sales essentially recover fuel costs only and have little or no earnings impact. Percentage Changes in kWh Sales by Class of Customer for the past two years were as follows: Percent Increase (Decrease) From Prior Year 1996 1995 Residential 2.6 1.1 Commercial (0.5) 0.2 Industrial 0.1 2.0 Other Electric Utilities 15.7 1.4 Other 2.6 (5.7) Total Primary Sales 1.1 0.7 Losses and Company Use (8.6) (2.6) Total System Requirements 0.7 0.5 Unit Contracts 16.2 (59.8) Total Energy Sales 2.0 (11.1) 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 45% of total operating expenses in 1996. Fuel expense of the Core Electric Business increased by $1.3 million or 1.4% in 1996, due primarily to a 2.0% increase in total energy generated and purchased. The $3.3 million increase in 1995 was caused by a 14.1% increase in the average cost of fuel, offset by an 11.1% decrease in total energy generated and purchased. Also, a classification adjustment increased fuel expense and decreased purchased power expense by approximately $1.8 million in 1995. Purchased Power demand expense decreased $6.8 million or 5.4% in 1996. The decrease is due primarily to the impact of lower billings from the Pilgrim nuclear unit of approximately $4.2 million, which includes a prior period refund of approximately $2 .0 million, and decreased billings from the Ocean State Power Project (OSP) and the Maine Yankee nuclear unit aggregating $2.5 million. Purchased Power demand expense for 1995 decreased $4.5 million due primarily to decreases of $6.7 million related to 41 mw of purchased power contracts which expired in October 1994 and the classification adjustments discussed above. These decreases were partially offset by increased billings from OSP and the Yankee nuclear units aggregating $5.2 million. Other Operation and Maintenance (O&M): O&M expenses for 1996 decreased by $7.5 million or 4.0% compared to 1995. Total O&M expenses are comprised of three components: Direct Controllable, Indirect and Energy Related. O&M expenses by component for 1996, 1995 and 1994 were as follows: ($ in millions) 1996 1995 1994 Direct Controllable $ 87.5 $ 83.4 $ 87.7 Indirect 36.7 41.3 46.7 Energy Related 55.7 62.7 50.1 Total O&M $179.9 $187.4 $184.5 Direct Controllable expenses of our Core Electric and Corporate Business units represent 48.6% of total 1996 O&M and include expense items such as: salaries, fringe benefits, insurance and maintenance. In 1996 these expenses increased by $4.1 million due primarily to incremental storm expenses related to an unusual number of severe storms which struck our retail service territories, costs related to the electric industry restructuring activities and increased assessments by FERC. The 1995 decrease was due primarily to one-time computer software development and hardware buy-out costs aggregating $1.9 million expensed in 1994, decreased insurance expense of approximately $1.2 million and strict attention to cost control. Indirect expenses include items over which we have limited short-term control. Indirects include such expense items as: O&M expenses related to Montaup's joint ownership interests in generating facilities such as Seabrook I and Millstone III (see Note H of Notes to Consolidated Financial Statements for other jointly-owned units), power contracts where transmission rental fees are fixed, C&LM expenses that are fully recovered in revenues, and expenses related to accounting standards such as Statement of Financial Accounting Standard No. 106, "Accounting for Post-Retirement Benefits Other Than Pensions" (FAS 106). Indirect expenses decreased by $4.6 million in 1996. The decrease included lower C&LM and Montaup power contract expenses aggregating $6.4 million somewhat offset by increased legal expenses and jointly owned unit expenses, which include incremental outage costs of Millstone III. The 1995 change was due primarily to $4.2 million of decreased C&LM expense and lower litigation expense. 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 93% of the total O&M expenses of this business unit in 1996. Energy Related expenses decreased by $7.0 million in 1996. The change included decreases in EUA Cogenex sales-related expenses of $10.8 million, decreased EUA Nova costs of goods sold of $5.6 million and the absence of cogeneration related expenses which amounted to $4.6 million in 1995. EUA Energy Investment Corporation (EUA Energy Investment) expenses decreased by $400,000. These decreases were offset somewhat by the June 1996 EUA Cogenex charge of $5.9 million and increased expenses of EUA Highland and EUA Citizens aggregating $7.9 million. EUA Cogenex's O&M expenses for 1995 increased by $10.4 million and are directly related to increased revenues, the acquisition of Citizens and High land and costs related to new product development of the EUA Day division. Also, operating and development expenses of EUA Energy Investment increased $2.2 million in 1995. Taxes Other Than Income: Taxes other than income increased $3.2 million in 1996 and decreased by $3.6 million in 1995. A 1995 reversal of previously over- accrued property taxes was primarily responsible for the change in both years. Income Taxes: EUA files a consolidated federal income tax return for the EUA System. The composite federal and state effective income tax rate for 1996 increased to 35.1% from 30.1% for 1995 due mainly to a decrease in state income tax benefits. EUA's 1994 effective tax rate was approximately 29%. In 1994 EUA Ocean State recognized $3.9 million of investment tax credits (ITC) which lowered the effective rate. Other Income (Deductions) - Net: Other Income and (Deductions)-Net increased $2.5 million in 1996. Approximately $1.7 million of this increase was due to the sale of Seabrook II equipment jointly owned by Montaup. In addition, an increase in EUA Cogenex interest income was partially offset by the impact of the write-off of Cogenex's AYP Capital and Westar joint venture start-up costs, included in the June 1996 $5.9 million charge. Other Income (Deductions) - Net decreased by $4.3 million in 1 995 from 1994. The 1994 amount included: (i) ITC recognized by EUA Ocean State of approximately $3.9 million as previously discussed; (ii) a settlement of $900,000 received in 1994 from the Vermont Electric Generation and Transmission Cooperative, Inc. related to Seabrook Nuclear Project payments previously withheld; and (iii) the 1994 income recognition of $900,000 of capitalized costs related to nuclear fuel buyouts which were previously deferred. EUA Cogenex interest income and management fee income increased by approximately $1.1 million in 1995. Interest Charges: Net interest charges for 1996 decreased approximately $2.3 million from 1995 amounts. This decrease was primarily due to the December 1995 maturity of $25 million of 9-9 1/4% Unsecured Medium Term Notes and $10 million of 8.9% Firs t Mortgage and Collateral Trust Bonds of Eastern Edison, offset somewhat by a decrease in capitalized interest by EUA Cogenex and higher interest expense related to increased short-term debt. The 1995 decrease of $2.3 million was due primarily to decreased long-term debt interest resulting from normal cash sinking fund payments, increases in capitalized interest of EUA Cogenex and decreased Other Interest Expense. Other Interest Expense in 1994 included approximately $1.0 million related to Internal Revenue Service audits of prior years' consolidated income tax returns. 1996 System Financing Activity Core Electric Business: On September 1, 1996, Eastern Edison used available cash to fund maturities of $7 million of 4 7/8% First Mortgage Bonds. Energy Related Business: As a result of the June 1996 $5.9 million charge to earnings and lower than anticipated sales, EUA Cogenex was not in compliance with the interest coverage covenant contained in certain of its unsecured note agreements and therefore EUA Cogenex was in default under said note agreements. EUA Cogenex has reached agreement with lenders to modify the interest coverage covenant contained in these note agreements through January 1, 1998, and to waive the default created by the June 1996 charge. 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. To the extent that EUA divests all or a portion of its generation assets, these needs will diminish. Core Electric Business: For 1996, 1995 and 1994, Core Electric Business cash construction expenditures were $33.3 million, $31.5 million, and $33.0 million, respectively. Internally generated funds available after the payment of dividends supplied approximately 118%, 210%, and 150% of these cash construction requirements in 1996, 1995 and 1994, 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 1997, 1998 and 1999 are estimated to be approximately $22.4 million, $16.3 million and $16.5 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 in 1997, 1998, 1999, 2000 and 2001 are $2.3 million, $62.2 million, $11.6 million, $2.3 million and $4.1 million, respectively. Energy Related Business: Capital expenditures of our Energy Related Business amounted to $28.1 million, $44.7 million, and $17.2 million in 1996, 1995 and 1994, respectively. Internally generated funds supplied 71.5%, 68.8%, and 111.9% of cash capital requirements in 1996, 1995 and 1994, respectively. Estimated capital expenditures of the Energy Related Business are $49.9 million, $46.7 million and $54.1 million in 1997, 1998 and 1999, respectively. Internally generated funds are expected to supply approximately 70% of 1997 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 $24.2 million in 1997, $9.2 million in 1998 and 1999, $59.2 million in 2000 and $9.2 million in 2001. 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 1996 are $1.1 million. Short-Term Lines of Credit: At December 31, 1996, EUA System companies maintained short-term lines of credit with various banks aggregating approximately $140 million. Year-End Short-Term Debt Outstanding by business unit: ($ in thousands) 1996 1995 Core Electric Business $ 3,670 $ 6,761 Energy Electric Business 24,341 14,421 Corporate 23,837 18,358 Total $51,848 $39,540 EUA expects to repay the outstanding balances of short-term indebtedness through internally generated funds. Energy Related Businesses Net Earnings and Earnings Per Share contributions of EUA's Energy Related Businesses for 1996 and 1995 were as follows: 1996 1995 Net Net Earnings Earnings Earnings Earnings (Loss) (Loss) (Loss) (Loss) (000's) Per Share (000's) Per Share EUA Cogenex $ (2,850) $ (0.14) $ 2,704 $ 0.13 EUA Ocean State 4,152 0.20 4,617 0.23 EUA Energy Investment (3,990) (0.19) (3,663) (0.18) EUA Energy Services (50) (0.00) From Operations (2,738) (0.13) $ 3,658 $ 0.18 Cogenex Charge (3,672) (0.18) Cogenex Discontinuance (10,498) (0.52) Energy Related Business $ (6,410) $ (0.31) $ (6,840) $ 0.34 Excludes June 1996 charge to earnings of $3.7 million or 18 cents per share. Excludes one-time charge of $10.5 million, or 52 cents per share, related to discontinuance of cogeneration operations.
EUA Cogenex: EUA Cogenex's earnings from continuing operations decreased by approximately $5.6 million in 1996 due primarily to lower earnings on project sales and operating losses of its EUA Nova division. Also, 1996 saw a significant reduction in demand side management activity as electric utilities nationwide prepared themselves for the evolution to a competitive marketplace. In 1996, EUA Cogenex refocused its national sales force toward the private sector and reduced its employee level by 22% through attrition and a 1996 year- end workforce reduction. EUA Cogenex will continue to develop its sales and marketing organization, evaluate and enter into strategic alliances, and emphasize cost control in 1997. EUA Ocean State: EUA Ocean State owns 29.9% of each of the partnerships which developed and operate Units I and II of Ocean State Power, twin 250-megawatt, 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 change in EUA Ocean State's earnings contribution was due to a lower allowed return on equity and a lower investment base billed by the project in 1996. EUA Energy Investment: EUA Energy Investment was organized to seek out investments in energy related businesses. The 1996 results reflect an increase in operating and development expenses versus 1995, in particular, expenses related to the operating expenses of EUA Transcapacity, and development costs of BIOTEN's biomass-fired combustion turbine electric generation system. EUA Energy Services: The loss generated by EUA Energy Services relates to startup costs of the Duke/Louis Dreyfus Energy Services (New England) partnership in 1996. Electric Utility Industry Restructuring Initiatives On August 7, 1996 the Governor of Rhode Island signed into law the Utility Restructuring Act of 1996 (URA). The URA provides for customer choice of electricity supplier to be phased-in commencing July 1, 1997 for large manufacturing customers, certain new commercial and industrial customers, and State of Rhode Island accounts. By July 1, 1998, or sooner, all customers will have retail access. Under the URA the local distribution company will retain the responsibility of providing distribution services to the ultimate electricity consumer within its franchised service territory. For customers who choose not to choose, the local distribution company would arrange for supply at a non-discriminatory, "standard offer" price. Distribution companies will also be providers of last resort, required to arrange for supply at prevailing market prices for customers who are unable to obtain their own supply. The URA provides for full recovery of prudently incurred embedded generation costs that might not be recovered in a competitive electric generation market, commonly referred to as "stranded costs," through a non-bypassable transition charge initially set at 2.8 cents per kWh through December 31, 2000. The transition charge recovers, among other things, costs of depreciated generation, net of its market value, regulatory assets, nuclear decommissioning costs and above market payments to power suppliers. The costs of net, above- market generation assets and regulatory assets will be recovered, with a return, through a fixed component of the transition charge from July 1, 1997, through December 31, 2009. A variable component of the transition charge will recover, on a reconciling basis, among other things, nuclear decommissioning and above market purchased power commitments from July 1, 1997, through the life of the respective unit or contract. The URA also provides for commitments to demand side management initiatives and renewables, low income customer protections, divestiture of at least 15% of owned non-nuclear generating units as a valuation basis for mitigation of stranded cost recovery, and performance based rate-making standards for electric distribution companies. These performance based standards provide for a 6% minimum and an approximate 12% maximum allowed return on equity for EUA's Rhode Island distribution companies, Blackstone and Newport. In addition, the URA provides for adjustments to electric distribution companies' base rates using the prior year's Consumer Price Index and other performance factors. Under this provision of the law, base rates were increased 1.88% for customers of Blackstone, and 2.18% for our Newport customers effective January 1, 1997. The implementation of the URA requires approvals from applicable regulatory agencies, including the Federal Energy Regulatory Commission (FERC), the RIPUC, and the Securities and Exchange Commission (SEC). In February 1997, Blackstone, Newport and Montaup reached a settlement with the Rhode Island Division of Public Utilities and Carriers and the state's Attorney General. In addition to complying with the URA, the settlement, to be formally submitted to the RIPUC in March 1997, provides for an immediate 10% rate reduction and the filing of a plan to divest all of Montaup's generating assets, and is similar in many respects to the settlement negotiated in Massachusetts, described below. On December 23, 1996, Eastern Edison and Montaup reached an agreement in principle with the Attorney General of Massachusetts and the Massachusetts DOER on a plan, similar in many aspects to the URA, which would allow retail customers to choose their supplier of electricity in 1998 and provide Eastern Edison and Montaup full recovery of "stranded costs." A formal plan is expected to be filed with the MDPU in March 1997. The agreement envisions that all of Eastern Edison's customers will have the ability to choose an alternative supplier of electricity beginning January 1, 1998. Until a customer chooses an alternative supplier, that customer would receive "standard offer" service which would be priced to guarantee at least a 10% savings from today's electricity rates. Eastern Edison would be required to arrange for "standard offer" service and would purchase power for "standard offer" service from suppliers through a competitive bidding process. The agreement is also designed to achieve full divestiture of Montaup's generating assets via implementation of a plan, to be submitted to the MDPU by July 1, 1997, that would require (1) separation by Montaup of its generating and transmission businesses and (2) full market valuation and sale of all generating assets through an auction or equivalent process, to be conducted by an independent third party. Upon the commencement of retail choice in Massachusetts, Montaup's wholesale contract with Eastern Edison would be terminated. In return, the cost of Montaup's above market, embedded generation commitments to serve Eastern Edison's customers would be recovered, with a return, through a non-bypassable transition access charge to all Eastern Edison customers. The transition access charge would be reduced by the fair market value of Montaup's generating assets as determined by selling, spinning off, or otherwise disposing of such generating facilities. Embedded costs associated with generating plants and regulatory assets would be recovered, with a return, over a period of 12 years. Purchased power contracts and nuclear decommissioning costs would be recovered as incurred over the life of those obligations, a period expected to extend beyond 12 years. The initial transition access charge would be set at 3.04 cents per kWh through December 31, 2000, and is expected to decline thereafter. The agreement also establishes performance-based regulation for Eastern Edison, incorporating a floor and cap on allowed return on equity. Under the agreement, Eastern Edison's distribution rates would be frozen until December 31, 2000. Subsequent to the commencement of retail choice, Eastern Edison's annual return on equity would be subject to a floor of 6% and a ceiling of 11.75%. In addition to MDPU approval of the agreement, implementation is also subject to the approval of FERC. Any disposition of generation assets resulting from the agreements or the URA would also require the approval of the SEC under the Public Utility Holding Company Act of 1935. While removing much of the uncertainty which currently exists as to how EUA will be impacted by electric utility restructuring, the agreements, if approved, are expected to have an estimated negative impact on EUA System earnings in 1998 of between 1 0% and 12%. Historically, electric rates have been designed to recover a utility's full costs of providing electric service including recovery of investment in plant assets. Also, in a regulated environment, electric utilities are subject to certain accounting rules that are not applicable to other industries. These accounting rules allow regulated companies, in appropriate circumstances, to establish regulatory assets and liabilities, which defer the current financial impact of certain costs that are expected to be recovered in future rates. The SEC has raised issues concerning the continued applicability of these standards with certain other electric utilities in other states facing restructuring. EUA believes that its Core Electric operations will continue to meet the criteria established in these accounting standards. However, the potential exists that the final outcome of state and federal agency determinations could result in EUA no longer meeting the criteria of these accounting standards which could trigger the discontinuance of Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation" (FAS71). Should it be required to discontinue the application of FAS71, EUA would be required to take an immediate write-down of the affected assets in accordance with FAS101, "Accounting for the Discontinuation of Application of FAS71." In addition, if legislative or regulatory changes and/or competition result in electric rates which do not fully recover the company's costs, a write-down of plant assets could be required pursuant to Financial Accounting Standard No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of" (FAS121). 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. 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 t he 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, 1996, the EUA System had incurred costs of approximately $5.7 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 $2.8 million may be incurred at these sites through 1998 by its subsidiaries. Estimates beyond 1998 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 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 dire ct 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 III, an 1154-mw nuclear unit that is jointly owned by a number of New England utilities, including subsidiaries of Northeast Utilities (Northeast), the operator of the plant. On March 30, 1996, Northeast shut down the unit following an engineering evaluation which determined that four safety-related valves would not be able to perform their design function during certain postulated events. The Nuclear Regulatory Commission (NRC) has raised numerous issues with respect to the unit and certain of the other nuclear units operated by Northeast. The NRC has established a Special Projects Office to oversee inspection and licensing activities at Millstone and 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. Northeast management has indicated it cannot currently estimate the effect these efforts will have on the timing of restarts or what additional costs, if any, these developments may cause. While Millstone III is out of service, Montaup will incur incremental replacement power costs estimated at $400,000 to $800,000 per month. Montaup bills its replacement power costs through its fuel adjustment clause, a wholesale tariff jurisdictional to FERC. However, there is no comparable clause in Montaup's FERC-approved rates which at this time would permit Montaup to recover its share of the incremental O&M costs incurred at Millstone III. EUA cannot predict the ultimate outcome of the NRC inquiries or the impact which they may have on Montaup and the EUA system. Montaup is also evaluating its rights and obligations under the various agreements relating to the ownership and operation of Millstone III. Montaup holds a 4.0% ownership interest in the Maine Yankee Nuclear Unit. In December 1996 the unit was shut down for inspections and repairs and in January 1997 the NRC announced that it had placed the unit on its watch list. The operator of the u nit had been addressing issues of non-conformance to the unit's licensing basis identified by the NRC in October 1996, prior to the NRC's January 1997 announcement. The operator of the plant cannot estimate when the unit will restart. Connecticut Yankee, a 582-mw nuclear unit, was taken off-line in July 1996 because of issues related to certain containment air recirculation and service water systems. Montaup has a 4.5% equity ownership in Connecticut Yankee with a book value of $ 4.8 million at December 31, 1996. In October 1996, Montaup, as one of the joint owners, participated in an economic evaluation of Connecticut Yankee which recommended permanently closing the unit and replacing its output with less expensive energy sources. As a result of the analysis, work at the plant had slowed pending a final board decision. In December 1996, the Board of Directors voted to retire the generating station. Connecticut Yankee certified to the NRC that it had permanently closed power generation operations and removed fuel from the reactor. Connecticut Yankee has two years to submit its decommissioning plan with the NRC. The preliminary estimate of the sum of future payments for the permanent shutdown, decommissioning, and recovery of the remaining investment in Connecticut Yankee, is approximately $758 million. Montaup's share of the total estimated costs is $34.1 million and is included with Other Liabilities on the Consolidated Balance Sheet at December 31, 1996. Due to anticipated recoverability, a regulatory asset has been recorded for the same amount and is included with Other Assets. 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 h ave 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 III and Seabrook I nuclear generating units. Montaup's share of the currently allowed estimated total costs to decommission Millstone III is approximately $18.6 million in 1996 dollars and Seabrook I is approximately $13.1 million in 1996 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. Other EUA occasionally makes forward-looking projections of expected future performance or statements of our plans and objectives. These forward-looking statements may be contained in filings with the SEC, press releases and oral statements. Actual results could differ materially from these statements. Therefore, no assurances can be given that such forward-looking statements and estimates will be achieved. "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. Financial Table of Contents Consolidated Statement of Income 26 Consolidated Statement of Cash Flows 27 Consolidated Balance Sheet 28 Consolidated Statement of Retained Earnings 29 Consolidated Statement of Equity Capital and Preferred Stock 29 Consolidated Statement of Indebtedness 30 Notes to Consolidated Financial Statements 31 Report of Independent Accountants 40 Report of Management 40 Quarterly Financial and Common Share Information 41 Consolidated Operating and Financial Statistics 42 Shareholder Information 44 Trustees and Officers Inside Back Cover Consolidated Statement of Income Years Ended December 31, (In Thousands Except Common Shares and per Share Amounts) 1996 1995 1994
OPERATING REVENUES $ 527,068 $ 563,363 $ 564,278 OPERATING EXPENSES: Fuel 92,166 90,888 87,573 Purchased Power-Demand 118,830 125,616 130,080 Other Operation 154,831 163,907 160,985 Voluntary Retirement Incentive 4,505 Maintenance 25,047 23,468 23,510 Depreciation and Amortization 45,478 45,492 46,455 Taxes - Other Than Income 23,933 20,744 24,337 Income Taxes 10,942 17,015 17,543 Total Operating Expenses 471,227 491,635 490,483 Operating Income 55,841 71,728 73,795 Equity in Earnings of Jointly Owned Companies 10,698 12,063 12,485 Allowance for Other Funds Used During Construction 452 538 351 Loss on Disposal of Cogeneration Operations (18,086) Income Tax Impact of Loss on Disposal of Cogeneration Operations 7,588 Other Income (Deductions) - Net 5,054 2,574 6,847 Income Before Interest Charges 72,045 76,405 93,478 INTEREST CHARGES: Interest on Long-Term Debt 34,035 38,216 38,987 Amortization of Debt Expense and Premium - Net 2,620 2,752 2,729 Other Interest Expense 4,199 3,167 3,849 Allowance for Borrowed Funds Used During Construction (Credit) (1,735) (2,677) (1,788) Net Interest Charges 39,119 41,458 43,777 Net Income 32,926 34,947 49,701 Preferred Dividends of Subsidiaries 2,312 2,321 2,331 Consolidated Net Earnings $ 30,614 $ 32,626 $ 47,370 Average Common Shares Outstanding 20,436,217 20,238,961 19,671,970 Consolidated Earnings per Share $ 1.50 $ 1.61 $ 2.41 Dividends Paid per Share $ 1.645 $ 1.585 $ 1.515
Consolidated Statement of Cash Flows Years Ended December 31, (In Thousands) 1996 1995 1994
CASH FLOW FROM OPERATING ACTIVITIES: Net Income $ 32,926 $ 34,947 $ 49,701 Adjustments to Reconcile Net Income to Net Cash Provided from Operating Activities: Depreciation and Amortization 50,690 52,413 54,091 Amortization of Nuclear Fuel 1,676 3,647 3,310 Deferred Taxes 11,610 (985) 8,017 Non-cash Expenses/(Gains) on Sales of Investments in Energy Savings Projects 8,262 (1,264) 382 Loss on Disposal of Cogeneration Operations 18,086 Investment Tax Credit, Net (1,207) (1,212) (181) Allowance for Other Funds Used During Construction (452) (538) (351) Collections and Sales of Project Notes and Leases Receivable 7,776 17,748 11,115 Other - Net 6,373 5,129 (10,360) Changes in Operating Assets and Liabilities: Accounts Receivable (5,777) 5,729 (4,509) Materials and Supplies 2,385 (1,280) (2,035) Accounts Payable (1,958) 1,543 (2,668) Taxes Accrued (1,539) (1,921) (5,834) Other - Net 4,930 (19,079) 9,641 Net Cash Provided from Operating Activities 115,695 112,963 110,319 CASH FLOW FROM INVESTING ACTIVITIES: Construction Expenditures (62,730) (77,923) (50,519) Collections on Notes and Lease Receivables of EUA Cogenex 3,665 3,125 1,635 Proceeds from Disposal of Cogeneration Assets 11,501 Increase in Other Investments (3,889) (2,300) (11,329) Net Cash (Used in) Investing Activities (62,954) (65,597) (60,213) CASH FLOW FROM FINANCING ACTIVITIES: Issuances: Common Shares 5,985 9,538 Long-Term Debt 7,925 Redemptions: Long-Term Debt (20,617) (42,725) (13,233) Preferred Stock (90) (100) (100) Premium on Reacquisition and Financing Expenses (15) (63) (689) EUA Common Share Dividends Paid (33,618) (32,050) (29,795) Subsidiary Preferred Dividends Paid (2,314) (2,324) (2,333) Net Increase (Decrease) in Short-Term Debt 12,308 7,862 (5,490) Net Cash (Used in) Financing Activities (44,346) (63,415) (34,177) NET INCREASE (DECREASE) IN CASH AND TEMPORARY CASH INVESTMENTS: 8,395 (16,049) 15,929 Cash and Temporary Cash Investments at Beginning of Year 4,060 20,109 4,180 Cash and Temporary Cash Investments at End of Year $ 12,455 $ 4,060 $ 20,109 Cash Paid during the year for: Interest (Net of Amounts Capitalized) $ 40,658 $ 39,306 $ 39,650 Income Taxes $ 11,530 $ 9,412 $ 15,233 Conversion of Investments in Energy Savings Projects to Notes and Leases Receivable $ 7,779 $ 19,324 $ 10,914
Consolidated Balance Sheet December 31, (In Thousands) 1996 1995
ASSETS Utility Plant and Other Investments: Utility Plant in Service $ 1,067,056 $ 1,037,662 Less Accumulated Provisions for Depreciation and Amortization 350,816 324,146 Net Utility Plant in Service 716,240 713,516 Construction Work in Progress 3,839 7,570 Net Utility Plant 720,079 721,086 Non-utility Property - Net 72,653 82,347 Investments in Jointly Owned Companies 71,626 70,210 Other 68,031 67,157 Total Utility Plant and Other Investments 932,389 940,800 Current Assets: Cash and Temporary Cash Investments 12,455 4,060 Accounts Receivable: Customers, Net 66,089 61,096 Accrued Unbilled Revenues 10,282 11,311 Other 13,782 11,969 Notes Receivable 24,691 18,663 Materials and Supplies (at average cost): Fuel 6,924 7,450 Plant Materials and Operating Supplies 7,207 9,066 Other Current Assets 7,668 11,804 Total Current Assets 149,098 135,419 Other Assets 175,542 129,911 Total Assets $ 1,257,029 $ 1,206,130 LIABILITIES AND CAPITALIZATION Capitalization: Common Equity $ 371,813 $ 375,229 Non-Redeemable Preferred Stock of Subsidiaries - Net 6,900 6,900 Redeemable Preferred Stock of Subsidiaries - Net 27,035 26,255 Long-Term Debt - Net 406,337 434,871 Total Capitalization 812,085 843,255 Current Liabilities: Short-Term Debt 51,848 39,540 Long-Term Debt Due Within One Year 27,512 19,506 Accounts Payable 33,811 35,769 Redeemable Preferred Stock Sinking Fund Requirement 50 Taxes Accrued 3,004 4,544 Interest Accrued 9,612 10,861 Other Current Liabilities 26,772 19,931 Total Current Liabilities 152,559 130,201 Other Liabilities 123,209 91,934 Accumulated Deferred Taxes 169,176 140,740 Commitments and Contingencies (Note J) Total Liabilities and Capitalization $1,257,029 $ 1,206,130
Consolidated Statement of Retained Earnings Years Ended December 31, (In Thousands) 1996 1995 1994
Retained Earnings - Beginning of Year $ 56,228 $ 56,617 $ 39,642 Consolidated Net Earnings 30,614 32,626 47,370 Total 86,842 89,243 87,012 Dividends Paid - EUA Common Shares 33,618 32,050 29,795 Other 820 965 600 Retained Earnings - Accumulated since June 1991 Accounting Reorganization $ 52,404 $ 56,228 $ 56,617
Consolidated Statement Of Equity Capital & Preferred Stock December 31, (Dollar Amounts In Thousands) 1996 1995
EASTERN UTILITIES ASSOCIATES: Common Shares: $5 par value 36,000,000 shares authorized, 20,435,997 shares outstanding in 1996 and 20,436,764 shares in 1995 $ 102,180 $ 102,184 Other Paid-In Capital 221,160 220,730 Common Share Expense (3,931) (3,913) Retained Earnings - Accumulated since June 1991 Accounting Reorganization 52,404 56,228 Total Common Equity 371,813 375,229 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 (2,630) (3,447) Newport Electric Corporation: 9.75% $100 par value 900 shares 90 Expense (3) Sinking Fund Requirement Due Within One Year (50) Total Redeemable Preferred Stock 27,035 26,255 Total Preferred Stock of Subsidiaries $ 33,935 $ 33,155 Authorized and Outstanding. Authorized 400,000 shares. Outstanding 300,000 at December 31, 1996.
Consolidated Statement of Indebtedness December 31, (In Thousands) 1996 1995
EUA Service Corporation: 10.2% Secured Notes due 2008 $ 10,100 $ 12,300 EUA Cogenex Corporation: 7.22% Unsecured Notes due 1997 15,000 15,000 7.0% Unsecured Notes due 2000 50,000 50,000 9.6% Unsecured Notes due 2001 16,000 19,200 10.56% Unsecured Notes due 2005 31,500 35,000 EUA Ocean State Corporation: 9.59% Unsecured Notes due 2011 31,067 33,544 Blackstone Valley Electric Company: First Mortgage Bonds: 9 1/2% due 2004 (Series B) 12,000 13,500 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: 4 7/8% due 1996 7,000 5 7/8% due 1998 20,000 20,000 5 3/4% due 1998 40,000 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 3,250 3,900 Small Business Administration Loan: 6.5% due 2005 719 809 Variable Rate Revenue Refunding Bonds due 2011 7,925 7,925 Unamortized (Discount) - Net (598) (687) 433,849 454,377 Less Portion Due Within One Year 27,512 19,506 Total Long-Term Debt - Net $ 406,337 $ 434,871 Weighted average interest rate was 3.5% for 1996 and 3.9% for 1995.
Notes to Consolidated Financial Statements December 31, 1996, 1995 and 1994 (A) Nature of Operations and Summary of Significant Accounting Policies: General: Eastern Utilities Associates (EUA) is a diversified energy services holding company. 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. 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. Reclassifications: Certain prior period amounts on the financial statements have been reclassified to conform with current presentation. 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 2.50% to 4.50%. Montaup is entitled to electricity produced from these facilities based on its ownership interests and is billed for its entitlement pursuant to contractual agreements which are approved by the Federal Energy Regulatory Commission (FERC). One of the four facilities, Yankee Atomic, is being decommissioned, but Montaup is required to pay, and has received FERC authorization to recover, its proportionate share of any unrecovered costs and costs incurred after the plant's retirement. Montaup's share of all unrecovered assets and the total estimated costs to decommission the unit aggregated approximately $7.8 million at December 31, 1996 and is included with Other Liabilities on the Consolidated Balance Sheet. Also, due to recoverability, a regulatory asset has been recorded for the same amount and is included with Other Assets. In December 1996, the Board of Directors of Connecticut Yankee voted to retire the generating station. Connecticut Yankee certified to the NRC that it had permanently closed power generation operations and removed fuel from the reactor. Montaup has a 4.5% equity ownership in Connecticut Yankee. Montaup's share of all unrecovered assets and the total estimated costs to decommission the unit aggregated approximately $34.1 million at December 31, 1996 and is included with Other Liabilities on the Consolidated Balance Sheet. Also, due to anticipated recoverability, a regulatory asset has been recorded for the same amount and is included with Other Assets. 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 40% partners hip interest in BIOTEN, G.P. and for its 20% stock ownership in Separation Technologies, Inc. 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 3.7% in 1996, 3.6% in 1995, and 3.3% in 1994 based on the average depreciable property balances at the beginning and end of each year. 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. Other Assets: The components of Other Assets at December 31, 1996 and 1995 are detailed as follows:
(In Thousands) 1996 1995 Regulatory Assets: Unamortized losses on reacquired debt $ 14,088 $ 15,894 Unrecovered plant and decommissioning costs 41,914 10,100 Deferred FAS 109 costs (Note B) 58,712 48,196 Deferred FAS 106 costs 4,054 4,583 Mendon Road judgment (Note J) 6,154 5,857 Other regulatory assets 6,363 6,031 Total regulatory assets 131,285 90,661 Other deferred charges and assets: Unamortized debt expenses 4,625 5,349 Goodwill 6,848 7,054 Other 32,784 26,847 Total Other Assets $ 175,542 $ 129,911
Regulatory Accounting: EUA's 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. EUA believes that its Core Electric operations continue to meet the criteria established in these accounting standards. Effects of legislation and/or regulatory initiatives or EUA's own initiatives could ultimately cause the Core Electric companies to no longer follow these accounting rules. In such an event, a non- cash write-off of regulatory assets and liabilities could be required at that time. 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 a s a result of higher depreciation expense. The combined rate used in calculating AFUDC was 9.0% in 1996, 9.2% in 1995, and 9.7% in 1994. The caption "Allowance for Borrowed Funds Used During Construction" also includes interest capitalized for non-regulated entities in accordance with Financial Accounting Standards Board (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 base rate revenues at the end of each month to match costs and revenues more closely. In addition they also record the difference between fuel costs incur red and fuel costs billed. Montaup recognizes revenues when billed. Montaup, Blackstone, and Newport also record revenues related to rate adjustment mechanisms. 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 con tracts 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 defer recognition of annual investment tax credits (ITC) and amortize these credits over the productive lives of the related assets. 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. (B) Income Taxes: EUA adopted FASB statement No. 109, "Accounting for Income Taxes" (FAS 109), 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 1996 and 1995 are comprised as follows: Deferred Tax Deferred Tax ($ in thousands) Assets ($ in thousands) Liabilities 1996 1995 1996 1995 Plant Related Plant Related Differences $18,442 $21,028 Differences $188,425 $170,562 Alternative Refinancing Minimum Tax 852 9,302 Costs 1,623 1,919 NOL Carryforward 1,655 1,646 Pensions 1,313 1,496 Pensions 4,012 3,392 Acquisitions 3,965 4,281 Other 5,657 5,663 Other 12,042 11,684 Total $34,583 $45,312 Total $203,403 $185,661 As of December 31, 1996 and 1995, EUA has recorded on its Consolidated Balance Sheet a regulatory liability to ratepayers of approximately $21.2 million and $27.2 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, 1996 and 1995, a regulatory asset of approximately $58.7 million and $48.2 million, respectively, h as been recorded, representing the cumulative amount of federal income taxes on temporary depreciation differences which were previously flowed through to ratepayers. EUA has $0.9 million of alternative minimum tax credits which have no expiration and can be utilized to reduce the consolidated regular tax liability. In 1994, EUA Ocean State utilized $3.9 million of ITC related to its investment in OSP, which were charged against 1994 federal income tax expense and reduced the consolidated regular tax liability. EUA has no remaining ITC carryforwards available. Components of income tax expense for the year 1996, 1995, and 1994 are as follows: ($ in thousands) 1996 1995 1994 Federal: Current $ (231) $ 10,335 $ 5,986 Deferred 9,838 6,456 9,199 Investment Tax Credit, Net (1,125) (1,130) (99) 8,482 15,661 15,086 State: Current 2,823 2,579 1,154 Deferred (363) (1,225) 1,303 2,460 1,354 2,457 Charged to Operations 10,942 17,015 17,543 Charged to Other Income: Current 4,798 4,353 9,243 Deferred 2,135 (6,217) (2,486) Investment Tax Credit, Net (82) (82) (3,972) 6,851 (1,946) 2,785 Total $17,793 $ 15,069 $ 20,328 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) 1996 1995 1994 Federal Income Tax Computed at Statutory Rates $ 17,751 $ 17,506 $ 24,510 (Decrease) Increase in Tax From: Equity Component of AFUDC (189) (187) (123) Depreciation Differences 2 118 50 Amortization and Utilization of ITC (1,207) (1,212) (5,115) State Taxes, Net of Federal Income Tax Benefit 1,952 (44) 2,285 Other (516) (1,112) (1,279) Total Income Tax Expense $ 17,793 $ 15,069 $ 20,328
(C) Capital Stock: The changes in the number of common shares outstanding and related increases in Other Paid-In Capital during the years ended December 31, 1996, 1995, and 1994 were as follows:
Number of Common Shares Issued Dividend Northeast Highland Common Other Reinvestment Energy Energy Shares Paid-In and Employee J.L. Day Co. Management Group At Par Capital Savings Plans Acquisition Acquisition Acquisition (000) (000) 1996 (767) $ (4) $ 4 1995 323,526 176,258 2,499 7,683 1994 427,304 12,499 464,579 4,522 10,209
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, 1996 and 1995, 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. In October 1996, Newport redeemed the remaining 900 shares of its 9.75% Preferred Stock, representing 500 shares under the mandatory sinking fund provision and 400 shares under the optional provision of the sinking fund. (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, in the principal amount of approximately $236 million. Blackstone's Variable Rate Demand Bonds are collateralized by an irrevocable letter of credit which expires on January 21, 1998. 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, 1998, 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 September, Eastern Edison used available cash to redeem $7 million of 4 7/8% First Mortgage Bonds at maturity. 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 1996 are: $27.5 million in 19 97, $72.5 million in 1998, $21.9 million in 1999, $62.5 million in 2000, and $14.3 million in 2001. As a result of the June 1996 $5.9 million charge to earnings and lower than anticipated sales, EUA Cogenex was not in compliance with the interest coverage covenant contained in certain of its unsecured note agreements and therefore EUA Cogenex was i n default under said note agreements. EUA Cogenex has reached agreement with lenders to modify the interest coverage covenant contained in these note agreements through January 1, 1998, and to waive the default created by the June 1996 charge. (F) Fair Value Of Financial Instruments: The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate: Cash and Temporary Cash Investments: The carrying amount approximates fair value because of the short-term maturity of these instruments. Long Term Notes Receivable and Net Investment in Sales-Type Leases: The fair value of these assets are based on market rates of similar securities. Preferred Stock and Long-Term Debt of Subsidiaries: The fair value of the System's redeemable preferred stock and long-term debt were based on quoted market prices for such securities at December 31, 1996. The estimated fair values of the System's financial instruments at December 31, 1996, are as follows: Carrying Fair ($ in thousands) Amount Value Cash and Temporary Cash Investments $ 12,455 $ 12,455 Long-Term Notes Receivable and Net Investment in Sales-Type Leases 52,599 54,869 Redeemable Preferred Stock 30,000 30,300 Long-Term Debt 434,447 450,419 (G) Lines Of Credit: EUA System companies maintain short-term lines of credit with various banks aggregating approximately $140 million. At December 31, 1996, unused short- term lines of credit were approximately $89 million. In accordance with informal agreements with the various banks, commitment fees are required to maintain certain lines of credit. During 1996, the weighted average interest rate for short-term borrowings was 5.5%. (H) Jointly Owned Facilities: At December 31, 1996, in addition to the stock ownership interests discussed in Note A, Nature of Operations and Summary of Significant Accounting Policies - Jointly Owned Companies, Montaup and Newport had direct ownership interests in the following electric generating facilities: Accumulated Provision For Net Construc- Utility Depreciation Utility tion Percent Plant in and Plant in Work in ($ in thousands) Owned Service Amortization Service Progress Montaup: Canal Unit 2 50.00% $ 83,194 $41,843 $ 41,351 $446 Wyman Unit 4 1.96% 4,051 2,130 1,921 Seabrook Unit 1 2.90% 194,928 29,983 164,945 251 Millstone Unit 3 4.01% 178,854 49,560 129,294 170 Newport: Wyman Unit 4 0.67% 1,285 726 559 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, 1996, Montaup's total net investment in nuclear fuel of the Seabrook and Millstone Units amounted to $2.8 million and $1.8 million, respectively. Montaup's and Newport's shares of related operating and maintenance expenses with respect to units reflected in the table above are included in the corresponding operating expenses. (I) Financial Information By Business Segments: The Core Electric Business includes results of the electric utility operations of Blackstone, Eastern Edison, Newport and Montaup. Energy Related Business includes results of our diversified energy related subsidiaries, EUA Cogenex, EUA Ocean State and EUA Energy Investment Corporation (EUA Energy) and EUA Energy Services. Corporate results include the operations of EUA Service and EUA Parent.
Pre-Tax Depreciation Cash Equity in Operating Operating Income and Construction Subsidiary ($ in thousands) Revenues Income Taxes Amortization Expenditures Earnings Year Ended December 31, 1996 Core Electric $ 470,719 $ 80,042 $ 19,902 $ 35,178 $ 33,337 $ 1,587 Energy Related 56,349 (11,536) (9,231) 10,290 28,121 9,111 Corporate (1,723) 271 10 1,272 Total $ 527,068 $ 66,783 $ 10,942 $ 45,478 $ 62,730 $10,698 Year Ended December 31, 1995 Core Electric $ 483,864 $ 86,505 $ 20,312 $ 34,218 $ 31,466 $ 1,646 Energy Related 79,499 3,377 (3,318) 11,265 44,684 10,417 Corporate (1,139) 21 9 1,773 Total $ 563,363 $ 88,743 $ 17,015 $ 45,492 $ 77,923 $12,063 Year Ended December 31, 1994 Core Electric $ 489,798 $ 83,966 $ 18,879 $ 33,409 $ 32,978 $ 1,700 Energy Related 74,480 9,905 (1,149) 12,491 17,231 10,785 Corporate (2,533) (187) 555 310 Total $ 564,278 $ 91,338 $ 17,543 $ 46,455 $ 50,519 $12,485
December 31, ($ in thousands) 1996 1995 Total Plant and Other Investments Core Electric $ 715,796 $ 716,828 Energy Related 196,236 203,670 Corporate 20,357 20,302 Total Plant and Other Investments 932,389 940,800 Other Assets Core Electric 232,443 191,152 Energy Related 66,212 57,083 Corporate 25,985 17,095 Total Other Assets 324,640 265,330 Total Assets $1,257,029 $1,206,130
(J) Commitments And Contingencies: 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. Montaup owns a 4.01% interest in Millstone III and a 2.9% interest in Seabrook I. Northeast Utilities, the operator of the units, indicates that Millstone III 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 o r power buyers as an additional fuel charge on a monthly basis and is currently being recovered by Montaup through rates. Also, Montaup is recovering through rates its share of estimated decommissioning costs for Millstone III and Seabrook I. Montaup's share of the current estimate of total costs to decommission Millstone III is $18.6 million in 1996 dollars, and Seabrook I is $13.1 million in 1996 dollars. These figures are based on studies performed for the lead owners of the units. Montaup also pays into decommissioning reserves pursuant to contractual arrangements with other nuclear generating facilities in which it has an equity ownership interest or life of the unit entitlement. Such expenses are currently recoverable through rates. Pensions: EUA maintains a non-contributory defined benefit pension plan covering substantially all employees of the EUA System (Retirement Plan). Retirement Plan benefits are based on years of service and average compensation over the four years prior to retirement. It is the EUA System's policy to fund the Retirement Plan on a current basis in amounts determined to meet the funding standards established by the Employee Retirement Income Security Act of 1974. Total pension expense for the Retirement Plan, including amounts related to the 1995 voluntary retirement incentive offer, for 1996, 1995 and 1994 included the following components: ($ in thousands) 1996 1995 1994 Service cost-benefits earned during the period $ 3,126 $ 2,776 $ 3,281 Interest cost on projected benefit obligations 9,765 9,391 8,848 Actual loss (return) on assets (16,451) (36,220) 1,523 Net amortization and deferrals 4,060 24,392 (12,494) Net periodic pension expense 500 339 1,158 Voluntary Retirement Incentive 1,653 Total periodic pension expense $ 500 $ 1,992 $ 1,158 Assumptions used to determine pension costs: Discount Rate 7.25% 8.25% 7.25% Compensation Increase Rate 4.25% 4.75% 4.75% Long-Term Return on Assets 9.50% 9.50% 9.50% The following table sets forth the actuarial present value of benefit obligations and funded status at December 31, 1996, 1995 and 1994:
($ in thousands) 1996 1995 1994 Accumulated benefit obligations Vested $ (118,739) $ (117,060) $ (96,045) Non-vested (254) (271) (315) Total $ (118,993) $ (117,331) $ (96,360) Projected benefit obligations $ (136,286) $ (135,415) $ (112,483) Plan assets at fair value, primarily stocks and bonds 161,300 152,308 122,816 Unrecognized net (gain) (29,963) (21,769) (13,643) Unamortized net assets at January 1 4,513 4,939 5,365 Net pension (liability) assets $ (436) $ 63 $ 2,055
The discount rate and compensation increase rate used to determine pension obligations, effective January 1, 1997 are 7.5% and 4.25% respectively, and were used to calculate the plan's funded status at December 31, 1996. The one-time voluntary retirement incentive also resulted in $1.6 million of non-qualified pension benefits which were expensed in 1995. At December 31, 1996, approximately $1.4 million was included in other liabilities for these unfunded benefits. EUA also maintains non-qualified supplemental retirement plans for certain officers 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 to fund in whole, or in part, its future liabilities under the Supplemental Plans. As of December 31, 1996, approximately $4.4 million was included in accrued expenses and other liabilities f or these plans. For the years ended December 31, 1996, 1995 and 1994 expenses related to the Supplemental Plans were $1.5 million, $1.5 million, and $516,000, respectively. 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 $1.3 million in 1996, $1.4 million in 1995 and $1.3 million in 1994. 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 EUA System adopted Statement of Financial Accounting Standard No. 106, "Accounting for Post-Retirement Benefits Other Than Pensions," (FAS 106) as of January 1, 1993. This standard establishes accounting and reporting standards for such post-retirement benefits as health care and life insurance. Under FAS 106 the present value of future benefits is recorded as a periodic expense over employee service periods through the date they become fully eligible for benefits. With respect to period s prior to adopting FAS 106, EUA elected to recognize accrued costs (the Transition Obligation) over a period of 20 years, as permitted by FAS 106. The resultant annual expense, including amortization of the Transition Obligation and net of capitalized and deferred amounts, was approximately $6.1 million in 1996, $6.3 million in 1995 and $5.8 million in 1994. The total cost of post-retirement benefits other than pensions, including amounts related to the 1995 voluntary retirement incentive offer, for 1996, 1995 and 1994 includes the following components: ($ in thousands) 1996 1995 1994 Service cost $ 1,123 $ 996 $ 1,537 Interest cost 4,449 4,822 5,381 Actual return on plan assets (253) (671) (126) Amortization of transition obligation 3,313 3,312 3,429 Other amortizations & deferrals - net (1,211) (970) (85) Net periodic post-retirement benefit cost 7,421 7,489 10,136 Voluntary Retirement Incentive 832 Total periodic post-retirement benefit costs $ 7,421 $ 8,321 $10,136 Assumptions used to determine post-retirement benefit costs Discount rate 7.25% 8.25% 7.25% Health care cost trend rate - near-term 9.00% 11.00% 13.00% - long-term 5.00% 5.00% 5.00% Compensation increase rate 4.25% 4.75% 4.75% Long-term return on assets - union 8.50% 8.50% 8.50% - non-union 7.50% 5.50% 5.50% Reconciliation of funded status: ($ in thousands) 1996 1995 1994 Accumulated post-retirement benefit obligation (APBO): Retirees $(36,518) $(40,817) $(35,386) Active employees fully eligible for benefits (5,952) (9,760) (9,778) Other active employees (19,652) (20,115) $(23,306) Total $(62,122) $(70,692) $(68,470) Plan assets at fair value, primarily notes and bonds 17,743 12,614 7,722 Unrecognized transition obligation 53,001 56,314 61,718 Unrecognized net loss (gain) (17,551) (7,575) (9,098) (Accrued)/prepaid post-retirement benefit cost $ (8,929) $ (9,339) $(8,128) The discount rate and compensation increase rate used to determine post- retirement benefit obligations effective January 1, 1997 are 7.5% and 4.25%, respectively, and were used to calculate the funded status of post-retirement benefits at December 31 , 1996. Increasing the assumed health care cost trend rate by 1% each year would increase the total post-retirement benefit cost for 1996 by $800,000 and increase the total accumulated post-retirement benefit obligation by $7.5 million. The EUA System has also established separate irrevocable external Voluntary Employees' Beneficiary Association Trust Funds for union and non-union retirees. Contributions to the funds commenced in March 1993 and totaled approximately $7.8 million in 1996, $7.1 million during 1995, and $6.7 million in 1994. 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, 1996, the aggregate annual minimum commitments for such contracts are approximately $122 million in 1997, $116 million in 1998, $114 million in 1999, $111 million in 2000, $111 million in 2001 and will aggregate $1.0 billion for the ensuing year s. In addition, the EUA System is required to pay additional amounts depending on the actual amount of energy received under such contracts. The demand costs associated with these contracts are reflected as Purchased Power-Demand on the Consolidate d Statement of Income. Such costs are currently recoverable through rates. 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. 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. EUA is unable to predict whether liability, if any, will be assumed by, or can be enforced against, the insurance carrier 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 has accumulated since 1985. Due to the uncertainty of the ultimate outcome of this proceeding and anticipated recoverability, Blacks tone recorded the $5.9 million District Court judgment as a deferred debit. This amount is included with Other Assets at December 31, 1996 and 1995. Blackstone filed a Notice of Appeal of the District Court's 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 hazardous. 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, 1996, the EUA System had incurred costs of approximately $5.7 million (excluding the $5.9 million Mendon Road judgment) in connection with 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 $2.8 million (excluding the $5.9 million Mendon Road judgment) may be incurred at these sites through 1998, substantially all of which relates to sites at which Blackstone is a potentially responsible part y. Estimates beyond 1998 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 November of 1996, the EPA proposed to toughen the nation's ozone standards as well as the particulate matters standards. The effect that such rules will have on the EUA System cannot be determined by management at this time. On December 23, 1996, Eastern Edison, Montaup, the Massachusetts Attorney General and Division of Energy Resources reached a settlement in principle regarding electric utility industry restructuring in the state of Massachusetts. The proposed settlement includes a plan for emissions reductions related to Montaup's Somerset Station Units 5 and 6, and to Montaup's 50% ownership share of Canal Electric's Unit #2. 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 is expected to be submitted to the MDPU in March 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 boiler s 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 regulation s 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. 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. The 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 EMF, are continuing. On October 31, 1996, the National Academy of Sciences issued a literature review of all research to date, "Possible Health Effects of Exposure to Residential Electric and Magnetic Fields." Its most widely reported conclusion stated, "No clear, convincing evidence exists to show that residential exposures to EMF are a threat to human health." 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 69kv 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 $31.5 million, 10.56% unsecured long-term notes due 2005 and EUA Ocean State's $31.1 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 7.22% and 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 $4.8 million of the outstanding debt of these two companies. In addition, Montaup and Newport have minimum rental commitments which total approximately $12.7 million and $1.6 million, respectively under a noncancelable transmission facilities support agreement for years subsequent to 1996. Other: In the fourth quarter of 1996 EUA Cogenex was notified by Ridgewood/Mass. Corporation that it intended to seek damages related to certain claims and alleged misrepresentations by EUA Cogenex regarding the sale of its cogeneration portfolio. As part of the "Agreement for Assignment for Beneficial Interests," Ridgewood exercised these rights under the mandatory arbitration clause contained within said agreement. A date has not been determined for the arbitration proceedings at this time. EUA Cogenex has filed a counter-claim against Ridgewood for its failure to pay for certain transitional expenses as stipulated in the "Assignment Agreement." On January 10, 1997, the Internal Revenue Service (IRS) issued a report in connection with its examination of the consolidated income tax returns of EUA for 1992 and 1993. The report includes 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 relating to the redemption of EUA Power's Common and Preferred Stock in 1993. The IRS has taken the position that the redemption of the Preferred Stock resulted in a capital loss transaction and not a deduction in determining ELA. The Company disagrees with the IRS's position and filed a protest in March 1997. EUA believes that it will ultimately prevail in this matter. However, if the ultimate resolution of this matter is a favorable decision for the IRS and EUA has not generated sufficient capital gain transactions to offset the capital loss then EUA would be required to record a charge that could have a material impact on financial results in the year of the charge but would not materially impact the financial position of the company. In early 1997, ten plaintiffs brought suit 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 is $25 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, and EUA is consulting with those insurers to determine the availability and extent of coverage. EUA cannot predict the ultimate outcome of this matter at this time. Report of Independent Accountants To the Trustees and Shareholders of Eastern Utilities Associates We have audited the accompanying consolidated balance sheet and consolidated statements of equity capital and preferred stock and indebtedness of Eastern Utilities Associates and subsidiaries (the Company) as of December 31, 1996 and 1995, and the related consolidated statements of income, retained earnings and cash flows for each of the three years in the period ended December 31, 1996. These financial statements are the responsibility of the Company's management. Our responsibility is to ex press an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards 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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of the Company as of December 31, 1996 and 1995, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 1996 in conformity with generally accepted accounting principles. Coopers & Lybrand L.L.P. Boston, Massachusetts March 5, 1997 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. Coopers & Lybrand L.L.P., 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 Coopers & Lybrand L.L.P. to discuss auditing, internal controls and financial reporting matters. The internal audit ors and Coopers & Lybrand L.L.P. have free access to the Audit Committee without management present. Quarterly Financial and Common Share Information (unaudited) (Thousands of Dollars, Except Per Share and Share Price Amounts) Earnings per Dividends Common Share Consolidated Average Paid Per Market Price Operating Operating Net Net Common Common Revenues Income Income Earnings Share Share High Low FOR THE QUARTERS ENDED 1996: December 31 $ 138,407 $ 14,208 $ 8,312 $ 7,735 $ 0.38 $ 0.415 17 1/2 16 September 30 131,076 13,328 9,389 8,811 0.43 0.415 19 1/2 14 3/4 June 30 122,785 10,024 3,299 2,720 0.13 0.415 21 7/8 18 1/2 March 31 134,800 18,281 11,926 11,348 0.56 0.40 24 1/4 20 5/8 FOR THE QUARTERS ENDED 1995: December 31 $ 135,327 $ 17,274 $ 10,989 $ 10,411 $ 0.51 $ 0.40 25 22 1/2 September 30 143,333 20,626 3,666 3,084 0.15 0.40 24 1/8 21 1/2 June 30 146,736 15,017 8,405 7,825 0.38 0.40 24 7/8 21 5/8 March 31 137,967 18,811 11,887 11,306 0.57 0.385 24 1/8 21 3/4
Consolidated Operating and Financial Statistics Years Ended December 31, 1996 1995 1994 1993 1992 1991 1986 ENERGY GENERATED AND PURCHASED (millions of kWh): Generated - by Somerset Station 719 679 658 319 936 957 887 - by Nuclear Units 977 752 1,008 1,033 1,050 1,109 543 - by Jointly-Owned Units 848 1,410 1,615 1,809 2,105 2,053 2,101 - by Life of the Unit Contracts 526 236 648 602 793 863 667 - by Newport 1 1 1 Interchange with NEPOOL 381 573 295 360 157 191 157 Purchased Power - Unit Power 1,765 1,463 1,526 1,396 1,489 1,006 309 Total Generated and Purchased 5,216 5,113 5,750 5,520 6,531 6,180 4,664 OPERATING REVENUES ($ in thousands): Residential $ 192,569 $ 193,233 $ 190,662 $ 189,470 $ 176,538 $ 178,812 $ 115,744 Commercial 164,096 169,841 169,241 179,145 170,034 171,732 105,777 Industrial 80,417 83,061 81,500 81,445 76,946 78,273 67,973 Other Electric Utilities 5,411 5,447 4,900 5,098 5,103 4,828 16,189 Other 14,281 17,482 17,282 21,790 21,314 17,984 15,019 Total Primary Sales Revenues 456,774 469,064 463,585 476,948 449,935 451,629 320,702 Unit Contracts 13,945 14,800 26,213 22,617 47,875 41,225 22,622 Non-Electric 56,349 79,499 74,480 66,912 44,154 29,729 Total Operating Revenues $ 527,068 $ 563,363 $ 564,278 $ 566,477 $ 541,964 $ 522,583 $ 343,324 ENERGY SALES (millions of kWh): Residential 1,740 1,697 1,678 1,624 1,575 1,579 1,262 Commercial 1,665 1,674 1,671 1,704 1,704 1,689 1,243 Industrial 868 867 850 816 785 777 855 Other Electric Utilities 86 75 74 61 68 66 372 Other 132 128 137 147 147 154 28 Total Primary Sales 4,491 4,441 4,410 4,352 4,279 4,265 3,760 Losses and Company Use 208 227 233 247 241 280 211 Total System Requirements 4,699 4,668 4,643 4,599 4,520 4,545 3,971 Unit Contracts 517 445 1,107 921 2,011 1,635 693 Total Energy Sales 5,216 5,113 5,750 5,520 6,531 6,180 4,664 NUMBER OF CUSTOMERS: Residential 270,319 268,203 263,054 259,654 257,026 255,620 217,899 Commercial 27,331 27,401 29,004 30,805 32,851 32,745 24,356 Industrial 1,779 1,685 1,603 1,294 1,197 1,172 1,250 Other Electric Utilities 8 8 12 12 15 15 15 Other 34 34 34 34 34 34 30 Total Customers 299,471 297,331 293,707 291,799 291,123 289,586 243,550 Average Annual Revenue per Residential Customer ($) 712 720 725 730 687 699 531 Average Annual Use per Residential Customer (kWh) 6,437 6,327 6,379 6,254 6,128 6,177 5,792 AVERAGE REVENUE PER KWH (cents): Residential 11.06 11.39 11.36 11.67 11.21 11.32 9.17 Commercial 9.86 10.15 10.13 10.51 9.98 10.17 8.51 Industrial 9.26 9.58 9.59 9.98 9.80 10.07 7.95
Consolidated Operating and Financial Statistics Years Ended December 31, 1996 1995 1994 1993 1992 1991 1986 CAPITALIZATION ($ in thousands): Bonds - Net $277,313 $ 279,374 $ 288,449 $ 300,389 $ 306,898 $ 346,146 $ 246,500 Other Long-Term Debt - Net 129,024 155,497 166,963 196,427 156,060 142,306 177,289 Total Long-Term Debt - Net 406,337 434,871 455,412 496,816 462,958 488,452 423,789 Preferred Stock - Net 33,935 33,155 32,290 31,953 44,346 45,830 44,931 Common Equity 371,813 375,229 365,443 333,165 266,855 248,598 225,156 Total Capitalization $812,085 $ 843,255 $ 853,145 $ 861,934 $ 774,159 $ 782,880 $ 693,876 CAPITALIZATION RATIOS (%) Long-Term Debt 50 52 53 57 60 62 61 Preferred Stock 4 4 4 4 6 6 7 Common Equity 46 44 43 39 34 32 32 COMMON SHARE DATA: Earnings (Loss) per Average Common Share ($) 1.50 1.61 2.41 2.44 2.00 1.58 2.82 Dividends per Share ($) 1.645 1.585 1.515 1.42 1.36 1.45 2.15 Payout (%) 109.7 98.4 62.9 58.2 68.0 91.8 76.2 Average Common Shares Outstanding 20,436,217 20,238,961 19,671,970 18,391,147 17,039,224 16,608,090 11,537,677 Total Common Shares Outstanding 20,435,997 20,436,764 19,936,980 19,032,598 17,237,788 16,831,062 11,676,229 Book Value per Share ($) 18.19 18.36 18.33 17.50 15.48 14.77 19.28 Percent Earned On Average Common Equity 8.2 8.8 13.6 15.0 13.2 10.8 15.0 Market Price ($): High 24 1/4 25 27 3/8 29 7/8 25 1/4 25 39 1/2 Low 14 3/4 21 1/2 21 3/8 23 7/8 20 3/8 15 3/4 25 3/4 Year End 17 3/8 23 5/8 22 28 24 3/4 20 5/8 38 1/2 Miscellaneous ($ in thousands): Total Construction Expenditures ($) 63,182 78,461 50,870 76,770 71,914 60,174 64,371 Cash Construction Expenditures ($) 62,730 77,923 50,519 76,391 71,365 57,570 47,137 Internally Generated Funds ($) 77,545 90,883 79,274 79,691 48,933 63,681 44,832 Internally Generated Funds as a % of Cash Construction (%) 123.6 116.6 156.9 104.3 68.6 110.6 95.1 Installed Capability - mw 1,208 1,191 1,212 1,256 1,325 1,349 971 Less: Unit Contract Sales - mw 60 35 85 85 85 216 108 System Capability - mw 1,148 1,156 1,127 1,171 1,240 1,133 863 System Peak Demand - mw 854 931 921 854 849 879 691 Reserve Margin (%) 34.4 24.2 22.4 37.1 46.1 28.9 24.9 System Load Factor (%) 62.6 57.2 57.5 61.5 57.5 59.0 65.6 Sources of Energy (%): Nuclear 29.0 28.2 33.8 34.0 34.1 31.3 19.0 Coal 14.7 14.7 11.7 5.4 18.6 21.0 22.0 Oil 19.8 25.5 20.0 28.3 12.7 26.9 59.0 Gas 30.8 26.5 28.4 26.0 29.3 17.2 Other 5.7 5.1 6.1 6.3 5.3 3.6 Cost of Fuel (Mills per kWh): Nuclear 5.0 6.3 6.1 7.5 7.7 8.7 8.6 Coal 19.6 20.3 20.9 24.1 21.2 21.4 23.7 Oil 37.7 30.2 27.1 25.5 26.0 18.9 23.6 Gas 14.4 14.3 14.1 15.1 13.0 16.2 All Fuels Combined 16.7 16.7 14.5 15.5 14.8 15.7 20.8 Excludes the 69 mw Somerset Station Unit #5 which was placed in deactivated reserve on January 25, 1994.
Shareholder Information Shares of Eastern Utilities Associates are listed on the New York and Pacific Stock Exchanges, under the ticker symbol EUA. As of February 1, 1997, there were 11,978 common shareholders of record. Form 10-K A copy of EUA's 1996 Annual Report on Form 10-K filed with the Securities and Exchange Commission is available to shareholders without charge by writing to us. Annual Meeting The 1997 Annual Meeting of Shareholders will be held on Monday, May 19, 1997, at 9:30 a.m., in the Enterprise Room, 5th Floor State Street Bank and Trust Company 225 Franklin Street Boston, Massachusetts Registrar, Transfer Agent and Dividend Disbursing Agent for Common and Preferred Shares Investor Relations The First National Bank of Boston c/o Boston EquiServe P. O. Box 8040 Boston, MA 02266-8040 1-800-736-3001 (Toll-Free) Lost or Stolen Stock Certificates If your stock certificate is lost, destroyed or stolen, you should notify the transfer agent immediately so a "stop transfer" order can be placed on the missing certificate. The transfer agent then will send you the required documents to obtain a replacement certificate. Dividends Schedule of anticipated record and payment dates for 1997 dividends on EUA Common Shares: Record Payment January 31 February 15 May 1 May 15 August 1 August 15 October 31 November 15 Direct Deposit Plan EUA Shareholders have the option of having their EUA Dividends deposited directly into their bank accounts. If you wish to participate, contact EUA investor relations at 1-800-736-3001 (Toll-Free). Replacement of Dividend Checks If you do not receive your dividend check within ten business days after the dividend payment date, or if your check is lost, destroyed or stolen, you should notify the disbursing agent in writing for a replacement. Dividend Reinvestment and Common Share Purchase Plan A Dividend Reinvestment and Common Share Purchase Plan is available to all registered shareholders and EUA System company employees. It is a simple and convenient method of purchasing additional shares of EUA common stock. Participants also may make cash payments to purchase additional shares. You may obtain complete details by writing to Clifford J. Hebert Jr., Treasurer/Secretary at the address shown below under "Financial Community Inquiries." Duplicate Mailings Duplicate mailings are costly. Shareholders may be receiving duplicate copies of annual and quarterly reports due to multiple stock accounts in the same household. To eliminate additional mailings of these reports, please write to us and enclose label(s) or label information from the duplicate reports. Dividend checks and proxy material will continue to be sent for each account on record. EUA is required by law to create a separate account for each name when stock is held in similar but different names (e.g., John A. Smith, J. A. Smith, John A. and Mary K. Smith, etc.). Please contact the Company for instructions if you wish to consolidate multiple accounts. Financial Community Inquiries Institutional investors and securities analysts should direct inquiries to: Clifford J. Hebert, Jr., Vice President - Finance & Treasurer EUA Service Corporation Post Office Box 2333 Boston, MA 02107 (617) 357-9590 The name Eastern Utilities Associates is the designation of the Trustees for the time being under a Declaration of Trust dated April 2, 1928, as amended. All persons dealing with Eastern Utilities Associates must look solely to the trust property for the enforcement of any claims against Eastern Utilities Associates, as neither the Trustees, Officers nor Shareholders assume any personal liability for obligations entered into on behalf of Eastern Utilities Associates. Internet Address Visit EUA's Home Page on the World Wide Web at: http://www.eua.com Trustees Russell A. Boss (A,P) President and Chief Executive Officer, A. T. Cross Company Lincoln, Rhode Island Paul J. Choquette, Jr. (C,P) President, Gilbane Building Company Providence, Rhode Island Peter S. Damon (A,P) President and Chief Executive Officer, Bank of Newport Newport, Rhode Island Peter B. Freeman (A,F) Corporate Director and Trustee Providence, Rhode Island Larry A. Liebenow (A,F) President and Chief Executive Officer, Quaker Fabric Corporation Fall River, Massachusetts Jacek Makowski (F,P) Chairman, Poseidon Resources Corporation Stamford, Connecticut Wesley W. Marple, Jr. (A,C) Professor of Business Administration, Northeastern University Boston, Massachusetts Donald G. Pardus Chairman of the Board of Trustees and Chief Executive Officer of the Association Margaret M. Stapleton (C,F) Vice President, John Hancock Mutual Life Insurance Company Boston, Massachusetts John R. Stevens President and Chief Operating Officer of the Association W. Nicholas Thorndike (C,F) Corporate Director and Trustee Brookline, Massachusetts A- Indicates member of Audit Committee C- Indicates member of Compensation and Nominating Committee F- Indicates member of Finance Committee P- Indicates member of Pension Trust Committee EUA System Officers Donald G. Pardus Chairman of the Board of Trustees and Chief Executive Officer John R. Stevens President and Chief Operating Officer John D. Carney Executive Vice President Robert G. Powderly Executive Vice President Richard M. Burns Comptroller Clifford J. Hebert, Jr. Treasurer and Secretary Donald T. Sena Assistant Treasurer Left to Right: Richard M. Burns, Donald T. Sena, John D. Carney, Robert G. Powderly, Donald G. Pardus, John R. Stevens, Clifford J. Hebert, Jr. EX-13 9 EXHIBIT 13-1.01 BVE ANNUAL REPORT Company Profile Blackstone Valley Electric Company (Blackstone or the Company) is a retail electric utility company. Blackstone supplies retail electric service to approximately 85,000 customers in the cities of Central Falls, Pawtucket and Woonsocket, and four surrounding towns in northern Rhode Island. Blackstone is a wholly owned subsidiary of Eastern Utilities Associates (EUA). EUA owns directly all of the shares of common stock of Blackstone, Eastern Edison Company (Eastern Edison) and Newport Electric Corporation (Newport). Eastern Edison and Newport are retail electric utility companies operating in southeastern Massachusetts and south coastal Rhode Island, respectively. Eastern Edison owns all of the permanent securities of Montaup Electric Company (Montaup), a generation and transmission company, which supplies electricity to Blackstone, to Eastern Edison, to Newport and to two unaffiliated utilities for resale. EUA also owns directly all of the shares of common stock of EUA Cogenex Corporation (EUA Cogenex), EUA Energy Investment Corporation (EUA Energy), EUA Ocean State Corporation (EUA Ocean State), EUA Service Corporation (EUA Service) and EUA Energy Services, Inc. (EUA Energy Services). EUA Service provides various accounting, financial, engineering, planning, data processing and other services to all EUA System companies. EUA Cogenex is an energy services company. EUA Energy was organized to invest in energy-related projects. EUA Ocean State owns a 29.9% interest in Ocean State Power's two gas-fired generating units in northern Rhode Island. EUA Energy Services owns an interest in a limited liability company which markets energy and energy related services in New England. The holding company system of EUA, the three retail subsidiaries, Montaup, EUA Service, EUA Cogenex, EUA Energy, EUA Energy Services and EUA Ocean State is referred to as the EUA System. Form 10-K A copy of EUA's, Eastern Edison's and Blackstone's Co-Registrant 1996 Annual Report on Form 10-K, which is filed with the Securities and Exchange Commission, is available to shareholders without charge by contacting us at: EUA Service Corporation Post Office Box 2333 Boston, MA 02107 (617) 357-9590 Internet Address Visit EUA's Home Page on the worldwide web at: http://www.eua.com. MARKET FOR BLACKSTONE'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS All of Blackstone's common stock is owned beneficially and of record by EUA. The dividends paid on common stock during the past two years are as follows: Dividends Paid Dividends Paid 1996 Per Share 1995 Per Share First Quarter $5.91 First Quarter $5.35 Second Quarter 6.34 Second Quarter 5.69 Third Quarter 6.34 Third Quarter 5.74 Fourth Quarter 6.34 Fourth Quarter 5.74 No dividends may be paid on the common stock unless full dividends on the outstanding preferred stock for all past and the current quarterly dividend periods have been paid or declared and set apart for payment. Blackstone's First Mortgage Indenture and Deed of Trust securing its First Mortgage Bonds contains provisions which restrict the payment by Blackstone of cash dividends on its common stock. See Notes C and D of Notes to Financial Statements and Management's Discussion and Analysis of Financial Condition and Review of Operations under Financial Condition and Liquidity. SELECTED FINANCIAL DATA
For the Years Ended December 31, (In Thousands) 1996 1995 1994 1993 1992 ______________________________________________________________________________ Operating Revenues $136,911 $140,861 $140,611 $143,666 $138,604 Net Earnings 3,776 4,009 3,438 4,069 2,583 Total Assets 132,313 129,835 121,413 114,552 115,698 Capitalization: Long-Term Debt 35,000 36,500 38,000 39,500 39,500 Non-Redeemable Preferred Stock 6,130 6,130 6,130 6,130 6,130 Common Equity 36,232 37,045 37,180 35,378 34,551 Total Capitalization $ 77,362 $ 79,675 $ 81,310 $ 81,008 $ 80,181
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND REVIEW OF OPERATIONS Overview Net Earnings for 1996 decreased approximately $200,000 to $3.8 million compared to those of 1995. Earnings for 1995 include a one-time charge of approximately $550,000, on an after-tax basis, related to the costs of a voluntary retirement incentive (VRI) offer recorded in June 1995. Kilowatthour sales (kWh) of electricity for 1996 decreased by 1.3% as compared to 1995 largely due to milder weather. Sales to commercial and industrial customers decreased by 3.0% and 2.5%, respectively, in 1996. Blackstone's net earnings for 1995 increased approximately $600,000 to $4.0 million compared to 1994 net earnings despite a one-time charge of approximately $550,000, on an after-tax basis, related to the VRI. kWh sales of electricity increased by 1.1% for 1995. Sales to residential customers increased by 2.6% and sales to industrial customers were up 1.0% for 1995 largely due to colder weather in the fourth quarter as compared to 1994. Comparison of Financial Results Operating Revenues Operating revenues for 1996 decreased by approximately $4.0 million as compared to those of 1995. This change was primarily due to recoveries of lower purchased power and conservation and load management (C&LM) expenses, as discussed below, and decreased kilowatthour sales. Operating Revenues for 1995 increased by approximately $300,000 as compared to those in 1994 primarily due to an increase in base revenues, attributable to a 1.1% increase in kWh sales. Purchased power recoveries increased by approximately $800,000 (see Operating Expenses below) offset by a $700,000 decrease in transmission rental revenue. Voluntary Retirement Incentive Offer On March 15, 1995, EUA announced a corporate reorganization which, among other things, consolidated management of Eastern Edison, Blackstone and Newport. As part of the reorganization, a VRI was offered to sixty-six professionals of the EUA System, including nine employees of Blackstone. Forty-nine of those eligible for the program, including five Blackstone employees, accepted the incentive and retired effective June 1, 1995. The cost of this incentive program amounted to a one-time $900,000 pre-tax ($550,000 after-tax) charge to Blackstone's second quarter 1995 earnings. Expenses Purchased Power expense, which is recovered through Blackstone's purchased power adjustment clause and represented 70% of total 1996 operating expense, decreased approximately $4.7 million or 4.9% as compared to 1995. Impacting purchased power expense was a decrease in C&LM expenses of approximately $3.1 million, which were included in purchased power expenses in 1995 but included in Other Operation and Maintenance expense in 1996, and decreased kWh requirements. Purchased Power expense in 1995 increased approximately $800,000 or less than 1.0% as compared to 1994. The average cost of fuel increased 14.1% in 1995 compared to 1994. This increase was partially offset by a wholesale rate decrease by the company's supplier, Montaup effective May 21, 1994. Other Operation and Maintenance expenses are comprised of two components, Direct Controllable and Indirect. Direct Controllable expenses include expense items such as salaries, fringe benefits, insurance, maintenance, etc. Indirect expenses include items over which the Company has limited short-term control including expenses related to accounting standards such as Statement of Financial Accounting Standard No. 106, "Employers' Accounting for Post- Retirement Benefits Other Than Pensions" (FAS106). Other Operation and Maintenance expenses, including affiliated company transactions, for 1996 increased by approximately $2.7 million or 13.8% when compared to 1995. This change is primarily due to an increase of $1.4 million in C&LM expenses recorded as Other Operation and Maintenance expenses, a decrease in capitalized costs of approximately $500,000, and an increase in FAS106 expense of approximately $200,000. Also impacting 1996 results were increases in the provision for uncollectible accounts, legal and storm related expenses aggregating approximately $700,000. Other Operation and Maintenance expenses for 1995 decreased by approximately $2.0 million or 9.3% when compared to 1994. This decrease is primarily due to the Company's continued strict attention to cost control including on-going savings related to the VRI, lower rent expense related to the March 1995 purchase of the Company's general office and operations buildings which were previously leased and decreased FAS106 expenses. Taxes Other than Income for 1996 decreased by $300,000 or 3.6% in 1996 and $400,000 or 4.0% in 1995. These decreases were due primarily to 1% decreases in the Rhode Island Gross Receipts Tax billed to industrial customers in both 1996 and 1995. Net interest charges for 1996 decreased by approximately $300,000 or 6.3%. This decrease was primarily due to lower interest on long-term debt due to reductions in long-term debt balances resulting from required sinking fund payments and decreased customer deposits interest. Net interest charges for 1995 decreased by approximately $400,000 or 8.7%. This decrease was primarily due to decreased customer deposits interest and reduced interest related to Internal Revenue Service (IRS) audits of prior years' consolidated income tax returns, which together aggregated over $300,000. Financial Condition and Liquidity The Company is required to make capital expenditures in order to meet the needs of its existing and future customers. For 1996, 1995 and 1994, the Company's cash construction expenditures were $4.2 million, $5.1 million, $5.7 million, respectively. In 1996, internally generated funds provided over 100% of cash construction requirements. Cash Construction expenditures are expected to be $4.2 million in 1997, $4.4 million in 1998 and $4.5 million in 1999 and are expected to be financed with internally generated funds. Traditionally, construction requirements in excess of internally generated funds are obtained through short-term borrowings which are ultimately funded with permanent capital. EUA System companies, including Blackstone, maintain short-term lines of credit with various banks aggregating approximately $140 million. At December 31, 1996, unused short-term lines of credit amounted to approximately $89 million. These credit lines are available to other EUA System companies under joint credit line arrangements. Blackstone had $700,000 of short-term borrowings outstanding at year end 1996, and $1.3 million at year-end 1995. Blackstone's requirements for sinking fund payments and redemption of securities for each of the five years following 1996 is $1.5 million in 1997, 1998, 1999 and 2000, and $3.3 million in 2001. Electric Utility Industry Restructuring Initiatives On August 7, 1996 the Governor of Rhode Island signed into law the Utility Restructuring Act of 1996 (URA). The URA provides for customer choice of electricity supplier to be phased-in commencing July 1, 1997 for large manufacturing customers, certain new commercial and industrial customers, and State of Rhode Island accounts. By July 1, 1998 or sooner, all customers will have retail access. Under the URA the local distribution company will retain the responsibility of providing distribution services to the ultimate electricity consumer within its franchised service territory. For customers who choose not to choose, the local distribution company would be allowed to arrange for supply at a non-discriminatory, "standard offer" price. Distribution companies will also be providers of last resort, required to arrange for supply, at prevailing market prices, for customers who are unable to do so. Blackstone is currently an all requirements customer of Montaup for generation services. This legislation provides for recovery of prudently incurred embedded generation costs that may not be to recovered in a competitive electric generation market, commonly referred to as "stranded costs," through a non-bypassable transition charge initially set at 2.8 cents per kWh. The transition charge recovers, among other things, costs of depreciated generation net of its market value, regulatory assets, nuclear decommissioning and above market payments to power suppliers. The costs of net, above-market generation assets and regulatory assets will be recovered, with a return, through a fixed component of the transition charge from July 1, 1997 through December 31, 2009. A variable component of the transition charge will recover, on a reconciling basis, among other things, nuclear decommissioning and above market purchased power commitments from July 1, 1997 through the life of the respective unit or contract. The URA also provides for commitments to demand side management initiatives and renewables, low income protections, divestiture of at least 15% of owned non-nuclear generating units as a valuation basis for mitigation of stranded cost recovery, and performance based rate making standards for electric distribution companies. These performance based standards provide for a 6% minimum and an approximate 12.2% maximum allowed return on equity for Blackstone and Newport. In addition, the URA provides for adjustments to electric distribution companies' base rates using the prior year's Consumer Price Index and other performance factors. Under this provision of the law, base rates were increased 1.88% for customers of Blackstone, and 2.18% for our Newport customers effective January 1, 1997. The implementation of the URA will require approvals from applicable regulatory agencies, including the Federal Energy Regulatory Commission (FERC), the Rhode Island Public Utilities Commission (RIPUC), and the Securities and Exchange Commission (SEC). In February 1997, Blackstone, Newport and Montaup reached settlement with the Rhode Island Division of Public Utilities and Carriers and the Rhode Island Attorney General with regard to implementation of a restructuring plan for Blackstone, Newport and Montaup. In addition to complying with the URA, the settlement provides for an immediate 10% rate reduction and a commitment by Montaup to file a plan by July 1, 1997 to divest all of its generating assets. Any disposition of generation assets resulting from the URA would also require the approval of the SEC under the Public Utility Holding Company Act of 1935. Historically, electric rates have been designed to recover a utility's full costs of providing electric service including recovery of investment in plant assets. Also, in a regulated environment, electric utilities are subject to certain accounting rules that are not applicable to other industries. These accounting rules allow regulated companies, in appropriate circumstances, to establish regulatory assets and liabilities, which defer the current financial impact of certain costs that are expected to be recovered in future rates. The SEC has raised issues concerning the continued applicability of these standards with certain other electric utilities, in other states, facing restructuring. The Company believes that its operations will continue to meet the criteria established in these accounting standards. However, the potential exists that the final outcome of state and federal agency determinations could result in the Company no longer meeting the criteria of certain accounting standards which could trigger the discontinuance of Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation" (FAS71). Should it be required to discontinue the application of FAS71, the Company would be required to take an immediate write down of the affected assets in accordance with FAS101, "Accounting for the Discontinuation of Application of FAS71." Environmental Matters Blackstone 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, an environmental audit program designed to ensure compliance with environmental laws and regulations and to identify and reduce liability was instituted by EUA. Because of the nature of Blackstone'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. Blackstone 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. Blackstone has 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, Blackstone is unable to predict whether liability, if any, will be assumed by, or can be enforced against, the insurance carriers in these matters. As of December 31, 1996, Blackstone had incurred costs of approximately $4.9 million, in connection with these sites. These amounts have been financed primarily by internally generated cash. Blackstone is currently recovering certain of its incurred environmental costs in rates. As a result of the recoverability in current rates of environmental costs, and the uncertainty regarding both its estimated liability, as well as potential contributions from insurance carriers, Blackstone does not believe that the ultimate impact of environmental costs will be material to their financial position and thus, no loss provision is required at this time. Blackstone estimates that additional costs of up to $2.7 million may be incurred at these sites through 1998. Estimates beyond 1998 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 incurred by the Commonwealth of Massachusetts at a site in which Blackstone has been named as the responsible party. See Note H of "Notes to 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 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. The 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 EMF, are continuing. On October 31, 1996, the National Academy of Sciences issued a literature review of all research to date, "Possible Health Effects of Exposure to Residential Electric and Magnetic Fields." Its most widely reported conclusion stated, "No clear, convincing evidence exists to show that residential exposures to EMF are a threat to human health." Management cannot predict the ultimate outcome of the EMF issue. Other The Company 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. Actual results could differ materially from these statements, therefore, no assurances can be given that such forward-looking statements and estimates will be achieved. 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 "Financial Statements" and "Notes to Financial Statements" in arriving at a more complete understanding of such matters. [This page left blank intentionally] Financial Table of Contents Statements of Income. . . . . . . . . . . . . . . . . . . . . . . . . . . 10 Statement of Retained Earnings . . . . . . . . . . . . . . . . . . . . . 10 Statement of Cash Flow . . . . . . . . . . . . . . . . . . . . . . . . . 11 Balance Sheet . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 Statement of Capitalization . . . . . . . . . . . . . . . . . . . . . . . 13 Notes to Financial Statements . . . . . . . . . . . . . . . . . . . . . . 15 Report of Independent Accountants . . . . . . . . . . . . . . . . . . . . 27 Blackstone Valley Electric Company Statement of Income Years Ended December 31, (In Thousands)
1996 1995 1994 Operating Revenues $ 136,911 $ 140,861 $ 140,611 Operating Expenses: Purchased Power (principally from an affiliate) 91,016 95,725 94,970 Other Operation and Maintenance 11,781 10,938 13,405 Affiliated Company Transactions 10,092 8,280 7,787 Voluntary Retirement Incentive 0 912 Depreciation 5,594 5,501 5,303 Taxes - Other than Income 8,506 8,821 9,202 Income and Deferred Taxes 2,156 2,347 1,885 Total Operating Expenses 129,145 132,524 132,552 Operating Income 7,766 8,337 8,059 Allowance for Other Funds Used During Construction 50 33 39 Other Income (Deductions) - Net 30 (38) 78 Income Before Interest Charges 7,846 8,332 8,176 Interest Charges: Interest on Long-Term Debt 3,313 3,481 3,476 Other Interest Expense 524 612 1,009 Allowance for Borrowed Funds Used During Construction (Credit) (56) (59) (36) Net Interest Charges 3,781 4,034 4,449 Net Income 4,065 4,298 3,727 Preferred Dividend Requirements 289 289 289 Net Earnings Applicable to Common Stock $ 3,776 $ 4,009 $ 3,438
Statement of Retained Earnings Years Ended December 31, (In Thousands) 1996 1995 1994 Restated Retained Earnings - Beginning of Year $ 9,934 $ 10,069 $ 10,204 Net Income 4,065 4,298 3,727 Total 13,999 14,367 13,931 Dividends Paid: Preferred 289 289 289 Common 4,589 4,144 3,573 Retained Earnings - End of Year $ 9,121 $ 9,934 $ 10,069 The accompanying notes are an integral part of the financial statements. Blackstone Valley Electric Company Statement of Cash Flows Years Ended December 31, (In Thousands)
1996 1995 1994 CASH FLOW FROM OPERATING ACTIVITIES: Net Income $ 4,065 $ 4,298 $ 3,727 Adjustments to Reconcile Net Income to Net Cash Provided from Operating Activities: Depreciation and Amortization 5,976 5,953 6,157 Deferred Taxes (561) 1,200 176 Investment Tax Credit, Net (182) (183) 253 Allowance for Funds Used During Construction (50) (34) (39) Other - Net (555) 643 (6,072) Net Changes in Operating Assets and Liabilities: Accounts Receivable 2,389 (2,324) (603) Materials and Supplies 66 (172) (27) Accounts Payable (383) 7,540 1,484 Accrued Taxes (362) 337 (1,280) Other - Net 740 (7,239) 5,454 Net Cash Provided from Operating Activities 11,143 10,019 9,230 CASH FLOW FROM INVESTING ACTIVITIES: Construction Expenditures (4,196) (5,064) (5,653) Net Cash (Used in) Investing Activities (4,196) (5,064) (5,653) CASH FLOW FROM FINANCING ACTIVITIES: Redemptions: Long-Term Debt (1,500) (1,500) Premium on Reacquisition and Financing Expenses Common Share Dividends Paid (4,589) (4,144) (3,573) Preferred Dividends Paid (289) (289) (289) Net (Decrease) Increase in Short-Term Debt (524) 1,259 Net Cash (Used in) Financing Activities (6,902) (4,674) (3,862) Net Increase (Decrease) in Cash 45 281 (285) Cash and Temporary Cash Investments at Beginning of Year 753 472 757 Cash and Temporary Cash Investments at End of Year $ 798 $ 753 $ 472 Cash paid during the year for: Interest (Net of Amounts Capitalized) $ 3,390 $ 3,565 $ 3,506 Income Taxes $ 3,301 $ 690 $ 1,836
The accompanying notes are an integral part of the financial statements. Blackstone Valley Electric Company Balance Sheet December 31, (In Thousands)
ASSETS 1996 1995 Utility Plant and Other Investments: Utility Plant $ 139,366 $ 136,503 Less Accumulated Provision for Depreciation 51,952 48,023 Net Utility Plant 87,414 88,480 Non-Utility Property - Net 46 47 Total Utility Plant and Other Investments 87,460 88,527 Current Assets: Cash and Temporary Cash Investments 798 753 Accounts Receivable: Customers, Net 11,141 11,254 Accrued Unbilled Revenue 1,196 1,339 Others 2,541 4,726 Associated Companies 482 429 Plant Materials and Operating Supplies (at average cost) 873 939 Other Current Assets 417 393 Total Current Assets 17,448 19,833 Other Assets (Note A) 27,405 21,475 Total Assets $ 132,313 $ 129,835 LIABILITIES AND CAPITALIZATION Capitalization: Common Equity $ 36,232 $ 37,045 Non-Redeemable Preferred Stock 6,130 6,130 Long-Term Debt 35,000 36,500 Total Capitalization 77,362 79,675 Current Liabilities: Long-Term Debt Due Within One Year 1,500 1,500 Notes Payable 735 1,259 Accounts Payable: Public 509 282 Associated Companies 16,759 17,371 Customer Deposits 1,113 992 Taxes Accrued 1,415 1,777 Dividends Accrued 72 72 Interest Accrued 899 981 Other Current Liabilities 1,157 431 Total Current Liabilities 24,159 24,665 Deferred Credits: Unamortized Investment Credit 2,561 2,743 Other Deferred Credits 14,002 13,836 Total Deferred Credits 16,563 16,579 Accumulated Deferred Taxes 14,229 8,916 Commitments and Contingencies (Note H) Total Liabilities and Capitalization $ 132,313 $ 129,835
The accompanying notes are an integral part of the financial statements. Blackstone Valley Electric Company Statement of Capitalization December 31, (In Thousands)
1996 1995 Common Stock, $50 par value, authorized 233,000 shares, issued and outstanding 184,062 shares $ 9,203 $ 9,203 Other Paid-in Capital 17,908 17,908 Retained Earnings 9,121 9,934 Total Common Equity 36,232 37,045 Non-Redeemable Cumulative Preferred Stock: 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 130 130 Total Non-Redeemable Cumulative Preferred Stock 6,130 6,130 Long-Term Debt: First Mortgage Bonds: 9 1/2% due 2004 (Series B) 12,000 13,500 10.35% due 2010 (Series C) 18,000 18,000 Variable Rate Demand Bonds Due 2014 6,500 6,500 36,500 38,000 Less Portion Due Within One Year 1,500 1,500 Total Long-Term Debt 35,000 36,500 Total Capitalization $ 77,362 $ 79,675 Authorized and Outstanding. Weighted average interest rate was 3.5% for 1996 and 3.9% for 1995.
The accompanying notes are an integral part of the financial statements. BLACKSTONE VALLEY ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS December 31, 1996, 1995 and 1994 (A) Nature of Operations and Summary of Significant Accounting Policies: General: Blackstone Valley Electric Company (Blackstone or the Company) is principally engaged in the distribution and sale of electric energy. 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. The accounting policies and practices of Blackstone are subject to regulation by FERC and RIPUC with respect to its rates and accounting. Blackstone conforms with generally accepted accounting principles, as applied in the case of regulated public utilities, and conforms with the accounting requirements and ratemaking practices of the RIPUC. A description of the significant accounting policies follows. Reclassifications: Certain prior period amounts on the financial statements have been reclassified to conform with current presentation. Transactions with Affiliates: The Company is a wholly-owned subsidiary of EUA. In addition to its investment in the Company, EUA has interests in other retail and wholesale utility companies, a service corporation, and four other non-utility companies. Transactions between Blackstone and other affiliated companies include the following: purchased power costs billed by Montaup of approximately $90,970,000 in 1996, $95,683,000 in 1995 and $94,944,000 in 1994; accounting, engineering and other services rendered by EUA Service of approximately $11,923,000 in 1996, $10,448,000 in 1995 and $9,524,000 in 1994; and operating revenue from the rental of transmission facilities to Montaup of approximately $2,501,000 in 1996, $3,047,000 in 1995 and $2,665,000 in 1994. Transactions with affiliated companies are subject to review by applicable regulatory commissions. Utility 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. Provisions for depreciation were equivalent to a composite rate of approximately 3.9% in 1996, 1995 and 1994, based on the average depreciable property balances at the beginning and end of each year. Other Assets: The components of Other Assets at December 31, 1996 and 1995 are detailed as follows: (In Thousands) 1996 1995 Regulatory Assets: Unamortized losses on reacquired debt $ 425 $ 455 Deferred SFAS 109 costs (Note B) 7,487 1,996 Deferred SFAS 106 costs 872 1,017 Mendon Road Judgment (Note H) 6,154 5,857 Other regulatory assets 1,234 959 Total regulatory assets 16,172 10,284 Other deferred charges and assets: Unamortized debt expenses 639 710 Other 10,594 10,481 Total Other Assets $27,405 $21,475 Regulatory Accounting: Blackstone is 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. Blackstone believes that its operations continue to meet the criteria established in these accounting standards. Effects of legislation and/or regulatory initiatives or EUA's own initiatives could ultimately cause Blackstone to no longer follow these accounting rules. In such an event, a non-cash write-off of regulatory assets and liabilities could be required at that time. Allowance for Funds Used During Construction (AFUDC): AFUDC represents the estimated cost of borrowed and equity funds used to finance the Company'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 rate used in calculating AFUDC was 9.4% in 1996, 8.6% in 1995 and 10.0% in 1994. Operating Revenues: Revenues are based on billing rates authorized by the RIPUC. The Company follows the policy of accruing the estimated amount of unbilled base rate revenues for electricity provided at the end of the month to more closely match costs and revenues. In addition, the Company also accrues the difference between fuel and purchased power costs incurred and fuel and purchased power costs billed to its customers. Income Taxes: The general policy of Blackstone with respect to accounting for federal and state income taxes is to reflect in income the estimated amount of taxes currently payable, as determined from the EUA consolidated tax return on an allocated basis, and to provide for deferred taxes on certain items subject to temporary differences to the extent permitted by the regulatory commissions. Blackstone has provided deferred income taxes on certain income and expense items that are accounted for in different periods for financial accounting purposes than for income tax purposes. Prior to 1987, AFUDC and certain costs for pensions, employee benefits and payroll-related insurances and payroll taxes applicable to construction activity, which were included in utility plant, were deducted currently for income tax purposes. Deferred taxes on these amounts and on certain differences created by the use of different depreciation methods in the years prior to 1981 have not been provided. The tax benefits on these items have been flowed through in accordance with approved rate orders of the RIPUC. As permitted by the regulatory commissions, it is the policy of the Company to defer recognition of annual investment tax credits and to amortize these credits over the productive lives of the related assets. Cash and Temporary Cash Investments: Blackstone considers all highly liquid investments and temporary cash investments with a maturity of three months or less when acquired to be cash equivalents. (B) Income Taxes: Components of income and deferred tax expense for the years 1996, 1995, and 1994 are as follows: _______________________________________________________________________ (In Thousands) 1996 1995 1994 Federal: Current $2,901 $1,329 $1,436 Deferred (531) 1,133 176 Investment Tax Credit, Net (182) (184) 253 $2,188 $2,278 1,865 State: Current 2 1 20 Deferred (34) 68 (32) 69 20 Charged to Operations 2,156 2,347 1,885 Charged to Other Income: Current 40 3 46 Total $2,196 $2,350 $1,931 Total income tax expense was different than the amounts computed by applying federal income tax statutory rates to book income subject to tax for the following reasons: _____________________________________________________________________________ (In Thousands) 1996 1995 1994 Federal Income Tax Computed at Statutory Rates $2,191 $2,327 $1,980 (Decreases) Increases in Tax from: Equity Component of AFUDC (17) (12) (14) Consolidated Tax Savings (32) (15) (125) Depreciation Differences 283 262 260 Amortization and Utilization of ITC (182) (184) (194) State Taxes, Net of Federal Income Tax Benefit (21) 45 13 Cost of Removal (67) (110) Other (26) (6) 121 Total Income Tax Expense $2,196 $2,350 $1,931 (B) Income Taxes (continued) Blackstone adopted Statement of Financial Accounting Standard No. 109, "Accounting for Income Taxes" (FAS109) which required 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 the temporary differences reverse. Generally, for regulated companies, the change in tax rates may not be immediately recognized in operating results because of rate making treatment and provisions in the Tax Reform Act of 1986. Total deferred tax assets and liabilities for 1996 and 1995 are comprised as follows: Deferred Tax Deferred Tax Assets Liabilities ($000) ($000) 1996 1995 1996 1995 Plant Related Plant Related Differences $1,581 $1,730 Differences $ 14,593 $ 8,540 Pensions 425 501 Refinancing Other 773 609 Costs 144 155 Total $2,779 $2,840 Pensions 436 556 Other 1,832 2,496 Total $17,005 $11,747 Blackstone has recorded on its Balance Sheets as of December 31, 1996 and 1995 a regulatory liability to ratepayers of approximately $3.0 million and $3.4 million, respectively. This amount primarily represents excess deferred income taxes resulting from the reduction in the federal income tax rate and also includes deferred taxes provided on investment tax credits. Also at December 31, 1996 and 1995, a regulatory asset of approximately $7.5 million and $2.0 million, respectively, has been recorded, representing the cumulative amount of federal income taxes on temporary depreciation differences which were previously flowed through to ratepayers. (C) Capital Stock: There were no changes in the number of shares of common or preferred stock during the years ended December 31, 1996, 1995, and 1994. In the event of involuntary liquidation, the holders of non-redeemable preferred stock of Blackstone are entitled to $100 per share plus accrued dividends. In the event of voluntary liquidation, or if redeemed at the option of the Company, each share of the non-redeemable preferred stock is entitled to accrued dividends and to: 4.25% issue, $104.40; 5.60% issue, $103.82. (C) Capital Stock (continued) Under the terms and provisions of the First Mortgage Indenture and of the issues of preferred stock of Blackstone, certain restrictions are placed upon the payment of dividends on common stock by the Company. At the years ended December 31, 1996 and 1995, the respective capitalization ratios were in excess of the minimum which would make these restrictions effective. (D) Retained Earnings: Under the provisions of Blackstone's First Mortgage Indenture, retained earnings in the amount of $4,124,784 were unrestricted as to the payment of cash dividends on its common stock at December 31, 1996. (E) Long-Term Debt: Blackstone's First Mortgage Bonds are collateralized by substantially all of its utility plant. Blackstone's Variable Rate Demand Bonds are collateralized by an irrevocable letter of credit which expires on January 21, 1998. The letter of credit permits extensions on an annual basis upon mutual agreement of the bank and Blackstone. The aggregate amount of Blackstone's cash sinking fund requirements and maturities for long-term debt for each of the five years following 1996 is $1.5 million in 1997, 1998, 1999, and 2000, and $3.3 million in 2001. (F) Lines of Credit: The EUA System Companies, including Blackstone maintain short-term lines of credit with various banks aggregating approximately $140 million. At December 31, 1996, unused short-term lines of credit amounted to approximately $89 million. These credit lines are available to other EUA System companies under joint credit line arrangements. In accordance with informal agreements with various banks, commitment fees are required to maintain certain lines of credit. Blackstone had $700,000 of short-term borrowings outstanding at year end. During 1996, Blackstone's weighted average interest rate for short-term borrowings was 5.6%. (G) Fair Value of Financial Instruments: The following methods 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 those instruments. (G) Fair Value of Financial Instruments (continued) Long-Term Debt: The fair value of the Company's long-term debt was based on quoted market prices for such securities. The estimated fair values of the Company's financial instruments at December 31, 1996 are as follows (In Thousands): Carrying Fair Amount Value Cash and Temporary Cash Investments $ 798 $ 798 Long-Term Debt $36,500 $37,596 (H) Commitments and Contingencies: Pensions: Blackstone participates with other EUA System companies in a non-contributory, defined benefit pension plan covering substantially all of their employees (Retirement Plan). Retirement Plan benefits are based on years of service and average compensation over the four years prior to retirement. It is the EUA System's policy to fund the Retirement Plan on a current basis in amounts determined to meet the funding standards established by the Employee Retirement Income Security Act of 1974. Total pension (income) expense for the Retirement Plan, including amounts related to the 1995 Voluntary Retirement Incentive offer, for 1996, 1995 and 1994 includes the following components ($ In Thousands): 1996 1995 1994 Service cost - benefits earned during the period $ 664 $ 606 $ 696 Interest cost on projected benefit obligation 2,373 2,346 2,186 Actual (return) loss on assets (4,216) (9,560) 397 Net amortization and deferrals 1,063 6,470 (3,241) Net periodic pension (income) expense $ (116) $ (138) $ 38 Voluntary retirement incentive 410 Total periodic pension (income) expense $(116) $ 272 $ 38 Assumptions used to determine pension cost: Discount Rate 7.25% 8.25% 7.25% Compensation Increase Rate 4.25% 4.75% 4.75% Long-Term Return on Assets 9.50% 9.50% 9.50% (H) Commitments and Contingencies (continued) The discount rate used to determine pension obligations was changed effective January 1, 1997 to 7.5%. The funded status of the Retirement Plan cannot be presented separately for Blackstone as it participates in the Retirement Plan with other subsidiaries of EUA. The one-time voluntary retirement incentive also resulted in approximately $310,000 of non-qualified pension benefits which were expensed in 1995. At December 31, 1996, approximately $177,000 is included in other liabilities for these unfunded benefits. EUA also maintains non-qualified supplemental retirement plans for certain officers 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 the participants of the Supplemental Plans to fund in whole, or in part, its future liabilities under the Supplemental Plans. For the years ended December 31, 1996, 1995 and 1994, Blackstone's portion of expenses related to the Supplemental Plans were approximately $284,000, $306,000 and $147,000, respectively. The Company also provides a defined contribution 401(k) savings plan for substantially all employees. The Company's matching percentage of employees' voluntary contributions to the plan, amounted to approximately $111,000 in 1996, approximately $148,000 in 1995 and approximately $181,000 in 1994. 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 Blackstone for all qualified employees. Blackstone adopted FAS106, "Employers' Accounting for Post-Retirement Benefits Other Than Pensions," as of January 1, 1993. This standard establishes accounting and reporting standards for such post-retirement benefits as health care and life insurance. Under FAS106 the present value of future benefits is recorded as a periodic expense over employee service periods through the date they become fully eligible for benefits. With respect to periods prior to adopting FAS106, EUA elected to recognize accrued costs (the Transition Obligation) over a period of 20 years, as permitted by FAS106. The resultant annual expense, including amortization of the Transition Obligation and net of capitalized and deferred amounts, was approximately $1.5 million in 1996, $1.3 million in 1995 and $1.5 million in 1994. (H) Commitments and Contingencies (continued) The total cost of Post-Retirement Benefits other than Pensions, including amounts related to the 1995 Voluntary Retirement Incentive offer, for 1996, 1995 and 1994 includes the following components ($ In Thousands):
1996 1995 1994 Service cost $ 216 $ 191 $ 299 Interest cost 1,060 1,170 1,323 Actual return on plan assets (6) (111) (20) Amortization of transition obligation 835 829 866 Net other amortization & deferrals (274) (239) (10) Net periodic post-retirement benefit costs 1,831 1,840 2,458 Voluntary retirement incentive 90 Total periodic post-retirement benefit costs $ 1,831 $ 1,930 $2,458 Assumptions: Discount rate 7.25% 8.25% 7.25% Health care cost trend rate-near-term 9.00% 11.00% 13.00% Health care cost trend rate-long-term 5.00% 5.00% 5.00% Compensation increase rate 4.25% 4.75% 4.75% Rate of return on plan assets 7.50% 5.50% 5.50% Reconciliation of funded status: ($ In Thousands) 1996 1995 1994 Accumulated post-retirement benefit obligation (APBO): Retirees $(7,045) $(8,235) $ (7,498) Active employees fully eligible for benefits (1,543) (2,825) (2,589) Other active employees (2,413) (3,052) (4,093) Total $(11,001) $(14,112) $ (14,180) Fair Value of assets (primarily notes and bonds) 1,573 924 364 Unrecognized transition obligation 11,372 12,083 13,328 Unrecognized net (gain) loss (5,551) (2,217) (2,358) (Accrued) prepaid post-retirement benefit cost $ (3,607) $ (3,322) $ (2,846)
The discount rate and compensation increase rate used to determine post- retirement benefit obligations, effective January 1, 1997, are 7.5% and 4.25%, respectively and were used to calculate the funded status of Post-Retirement benefits at December 31, 1996. Increasing the assumed health care cost trend rate by 1% each year would increase the total post-retirement benefit cost for 1996 by approximately $108,000 and increase the total accumulated post-retirement benefit obligation by $1.2 million. Blackstone has also established an irrevocable external Voluntary Employee's Beneficiary Association (VEBA) Trust Fund as required by the aforementioned regulatory decisions. Contributions to the VEBA fund commenced in March 1993 and totaled approximately $1.2 million during 1996, $1.1 million during 1995, and $800,000 during 1994. Environmental Matters: The Comprehensive Environmental Response, Compensation Liability Act of 1980, as amended by the Superfund Amendments and Reauthorization Act of 1986, and certain similar state statutes authorize various governmental authorities to seek court orders compelling responsible parties to take cleanup action at disposal sites which have been determined by such governmental authorities to present an imminent and substantial danger to the public and to the environment because of an actual or threatened release of hazardous substances. Because of the nature of Blackstone's business, various by-products and substances are produced or handled which are classified as hazardous under the rules and regulations promulgated by the EPA as well as state and local authorities. Blackstone 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. Blackstone has 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 Blackstone to notify liability insurers and to initiate claims. However, it is not possible at this time 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 has accumulated since 1985. Due to the uncertainty of the ultimate outcome of this proceeding and anticipated recoverability, Blackstone recorded the $5.9 million District Court judgment as a deferred debit. This amount is included with Other Assets at December 31, 1996 and 1995. Blackstone filed a Notice of Appeal of the District Court's judgment and filed its brief with the United States Court of Appeals for the First Circuit (Circuit Court) on February 24, 1995. On October 6, 1995, the Circuit Court vacated the District Court's $5.9 million judgement. Rather than remand the case to the District Court for a trial on the issue of whether ferric ferrocyanide (FFC) is a hazardous substance, the Circuit Court exercised its primary jurisdictional powers to send the matter to the EPA for an administrative determination on the issue. If the EPA determines that FFC is not a hazardous substance, given the present posture of the case, Blackstone may not be liable to reimburse the Commonwealth for the Mendon Road cleanup costs. On January 9, 1997, Blackstone met with representatives of EPA and the Commonwealth to discuss the procedure EPA would follow in resolving the FFC issue. In January 1997, Blackstone submitted written comments to be followed by the Commonwealth's written reply. (H) Commitments and Contingencies (continued) The EPA will determine whether FFC is a hazardous substance. Further court proceedings are likely. 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 Massachusetts 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 hazardous. 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, 1996, Blackstone had incurred costs of approximately $4.9 million (excluding the $5.9 million Mendon Road judgment) in connection with these sites. 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. The Company estimates that additional costs (excluding the Mendon Road judgment) may be incurred at these sites through 1998 of up to approximately $2.7 million by it and the other responsible parties. Estimated amounts after 1998 are not now determinable 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 potential contributions from insurance carriers and other responsible parties, Blackstone does not believe that the ultimate impact of the environmental costs will be material to its financial position and thus, no loss provision is required at this time. 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 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. The 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 EMF, are continuing. On October 31, 1996, the National Academy of Sciences issued a literature review of all research to date, "Possible Health Effects of Exposure to Residential Electric and Magnetic Fields." Its most widely reported conclusion stated, "No clear, convincing evidence exists to show that residential exposures to EMF are a threat to human health." Some states have enacted regulations to limit the strength of EMF at the edge of transmission line rights-of-way. Rhode Island enacted a statute which authorizes and directs the Rhode Island 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 impact, if any, which legislation or other developments concerning EMF may have on Blackstone. In April 1992, NESCAUM, an environmental advisory group for eight northeast states, including Massachusetts and Rhode Island, issued recommendations for nitrogen oxide 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 EPA's 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 or more tons per year of oxides of nitrogen. Rhode Island has also issued similar regulations. Montaup has initiated compliance through, among other things, selective, noncatalytic reduction processes. Other: In early 1997, ten plaintiffs brought suit 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 is $25 million in compensatory and punitive damages, plus exemplary damages and interest and costs. Each names between fifteen and twenty-eight defendants, including EUA. These complaints have been referred to the applicable insurance companies, and EUA is consulting with those insurers to determine the availability and extent of coverage. EUA cannot predict the ultimate outcome of this matter at this time. Report of Independent Accountants To the Directors and Shareholder of Blackstone Valley Electric Company: We have audited the accompanying balance sheet and statement of capitalization of Blackstone Valley Electric Company (the Company) as of December 31, 1996 and 1995, and the related statements of income, retained earnings and cash flows for each of the three years in the period ended December 31, 1996. 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 in accordance with generally accepted auditing standards. Those standards 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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 1996 and 1995, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1996 in conformity with generally accepted accounting principles. /s/Coopers & Lybrand L.L.P. Boston, Massachusetts March 5, 1997 [This page is left blank intentionally] EX-13 10 EXHIBIT 13-1.08 EECO ANNUAL REPORT Company Profile Eastern Edison Company (Eastern Edison or the Company) is a retail electric utility company. Eastern Edison supplies retail electric service to approximately 182,000 customers in 22 cities and towns in southeastern Massachusetts. The largest communities served are the cities of Brockton and Fall River, Massachusetts. Eastern Edison is a wholly owned subsidiary of Eastern Utilities Associates (EUA). EUA owns directly all of the shares of common stock of Eastern Edison, Blackstone Valley Electric Company (Blackstone) and Newport Electric Corporation (Newport). Blackstone and Newport are retail electric utility companies operating in northern Rhode Island and south coastal Rhode Island, respectively. Eastern Edison owns all of the permanent securities of Montaup Electric Company (Montaup), a generation and transmission company, which supplies electricity to Eastern Edison, to Blackstone, to Newport and to two unaffiliated utilities for resale. EUA also owns directly all of the shares of common stock of EUA Cogenex Corporation (EUA Cogenex), EUA Energy Investment Corporation (EUA Energy), EUA Ocean State Corporation (EUA Ocean State), EUA Energy Services Corporation (EUA Energy Services) and EUA Service Corporation (EUA Service). EUA Service provides various accounting, financial, engineering, planning, data processing and other services to all EUA System companies. EUA Cogenex is an energy services company. EUA Energy was organized to invest in energy-related projects. EUA Ocean State owns a 29.9% interest in Ocean State Power's two gas-fired generating units in northern Rhode Island. EUA Energy Services owns an interest in a limited liability company which markets energy and energy services. The holding company system of EUA, the three retail subsidiaries, Montaup, EUA Service, EUA Cogenex, EUA Energy, EUA Energy Services and EUA Ocean State is referred to as the EUA System. Form 10-K A copy of EUA's, Eastern Edison's and Blackstone's Co-Registrant 1996 Annual Report on Form 10-K, which is filed with the Securities and Exchange Commission, is available to shareholders without charge by contacting us at: EUA Service Corporation Post Office Box 2333 Boston, MA 02107 (617) 357-9590 Internet Address Visit EUA's Home Page on the worldwide web at: http://www.eua.com. MARKET FOR EASTERN EDISON'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS All of Eastern Edison's common stock is owned beneficially and of record by Eastern Utilities Associates (EUA). The dividends paid on Eastern Edison's common stock during the past two years are as follows: Dividends Paid Dividends Paid 1996 Per Share 1995 Per Share First Quarter $2.87 First Quarter $2.53 Second Quarter 3.00 Second Quarter 0.43 Third Quarter 3.00 Third Quarter 0.46 Fourth Quarter 3.00 Fourth Quarter 0.45 No dividends may be paid on Eastern Edison's common stock unless full dividends on Eastern Edison's outstanding Preferred Stock for all past and the current quarterly dividend periods have been paid or declared and set apart for payment, nor may any dividends be paid on Eastern Edison's common stock if Eastern Edison is in default on any sinking fund obligation provided for its Preferred Stock. See also Notes C, D and E of Notes to Consolidated Financial Statements. SELECTED CONSOLIDATED FINANCIAL DATA For the Years Ended December 31, (In Thousands) 1996 1995 1994 1993 1992 _________________________________________________________________________ Operating Revenues $404,808 $420,069 $418,424 $417,021 $420,188 Net Earnings 30,983 31,455 31,395 28,145 29,231 Total Assets 775,082 739,198 756,045 742,273 776,510 Capitalization: Long-Term Debt 222,402 222,313 229,224 264,134 269,995 Redeemable Preferred Stock-Net 27,035 26,218 25,257 24,824 28,171 Non-Redeemable Preferred Stock 8,949 Common Equity 240,213 244,368 225,064 223,005 220,257 Total Capitalization $489,650 $492,899 $479,545 $511,963 $527,372 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND REVIEW OF OPERATIONS Overview 1996 Consolidated Net Earnings of approximately $31.0 million decreased $0.5 million, or 1.5% compared to those of 1995 which included a one-time charge of approximately $1.5 million, on an after tax basis, related to the voluntary retirement incentive offer (VRI). The results were impacted by increased expenses related to an unusual number of severe storms which struck Eastern Edison's service territory during 1996 and increased legal expenses, partially offset by a decrease in interest expense from debt issues that matured in 1995. Consolidated Net Earnings for 1995 of approximately $31.5 million were slightly higher than 1994 net earnings of $31.4 million due primarily to lower litigation expenses resulting from favorable court decisions rendered in 1995, lower interest expense and successful cost control efforts. Offsetting these impacts somewhat were the VRI charge and Montaup's approximately $13.9 million annual wholesale rate reduction effective May 21, 1994. Comparison of Financial Results Operating Revenues Operating Revenues for 1996 decreased by approximately $15.3 million, as compared to 1995. The change was primarily due to decreased purchased power recoveries of $6.9 million, decreased conservation and load management (C&LM) expense recoveries of $7.1 million, and decreased contract demand sales of $1.6 million. Operating Revenues for 1995 increased by approximately $1.6 million as compared to 1994. This change was primarily due to increased purchased power and fuel expense recoveries aggregating $5.8 million and additional revenues related to the full year impact of Newport becoming an all-requirements customer of Montaup on May 21, 1994. Offsetting these increases somewhat were decreased C&LM expense recoveries of $3.9 million and the full year impact of Montaup's wholesale rate reduction implemented on May 21, 1994 which lowered 1995 revenues by approximately $4.9 million. Voluntary Retirement Incentive Offer On March 15, 1995, EUA announced a corporate reorganization which, among other things, consolidated management of Eastern Edison, Blackstone and Newport. As part of the reorganization, a VRI was offered to 66 professionals of the EUA System including 22 employees of Eastern Edison and Montaup. Forty-nine of those eligible for the program, including 16 employees of Eastern Edison and Montaup, accepted the incentive and retired effective June 1, 1995. The cost to Eastern Edison of this incentive program amounted to a one-time $2.4 million pre-tax ($1.5 million after-tax) charge to second quarter 1995 earnings. Expenses The Company's most significant expense items continue to be fuel and purchased power expenses which together comprised about 59% of total operating expenses for 1996. Fuel expense increased by $1.3 million or 1.4% in 1996 as compared to 1995 due to primarily to a 2.0% increase in total energy generated and purchased. Fuel expense increased by $3.4 million or 3.8% in 1995 as compared to 1994. This change was caused by an increase of 14.1% in the average cost of fuel offset by decreases in total energy generated and purchased of 11.1%. Purchased Power demand expense decreased $6.8 million or 5.4% in 1996. The decrease was due primarily to the impact of lower billings from the Pilgrim nuclear unit of approximately $4.2 million which includes a prior period refund of approximately $2.0 million, and decreased billings from the Ocean State Power Project and the Maine Yankee nuclear unit aggregating $2.5 million. Purchased Power demand expense for 1995 increased $2.6 million to $125.6 million. This increase was due primarily to the impact of Newport's purchased power contracts assumed by Montaup effective May 21, 1994, coincident with Newport becoming an all-requirements customer of Montaup, aggregating approximately $4.8 million, and increased billings from the Ocean State Power project and the Yankee nuclear units aggregating $5.2 million. These increases were offset somewhat by decreases of approximately $6.7 million resulting from purchase power contracts totaling 41 mw which expired in October 1994, and a net $700,000 reduction in purchases from other power suppliers. Other Operation and Maintenance expenses are comprised of two components, Direct Controllable and Indirect. Direct Controllable expenses include expense items such as salaries, fringe benefits, insurance, maintenance, etc. Indirect expenses include items over which the Company has limited short-term control and include such expense items as Montaup's joint ownership interests in generating facilities such as Seabrook I and Millstone III, power contracts where transmission rental fees are fixed, conservation and load management expenses that are fully recovered in revenues and expenses related to accounting standards such as Statement of Financial Accounting Standard No. 106, "Employers' Accounting for Post Retirement Benefits-Retirement Benefits Other Than Pensions" (FAS106). Other Operation and Maintenance expenses, including affiliated company transactions, decreased by $4.8 million or 5% in 1996. The change was primarily due to decreased C&LM expenses of $7.7 million, lower power contract and transmission expenses of Montaup and effective cost control efforts aggregating $1.1 million. Offsetting these decreases somewhat were increases in storm related, legal and jointly owned unit expenses aggregating $4.5 million. Other Operation and Maintenance expenses for 1995 decreased by approximately $5.7 million or 5.6% from 1994 levels. This decrease was due primarily to lower C&LM expense totaling $4.3 million, decreased legal costs of approximately $2.1 million and successful cost control efforts. Offsetting these year-to date decreases somewhat were increases in Montaup power contract expenses and FAS106 expenses aggregating $1.4 million. Net interest charges decreased by approximately $2.7 million, due primarily to the December 1995 maturity of $25 million of 9-9 1/4% Unsecured Medium Term Notes and $10 million of 8.9% First Mortgage and Collateral Trust Bonds and the September 1996 maturity of $7 million of 4 % First Mortgage Collateral Trust Bonds of Eastern Edison. Net interest charges decreased by $1.4 million in 1995 versus 1994. Other Interest expense provisions recorded in June 1994 aggregating $1.0 million related to Internal Revenue Service audits of prior years' consolidated income tax returns were primarily responsible for this change. Financial Condition and Liquidity Eastern Edison's and Montaup's need for permanent capital is primarily related to the construction of facilities required to meet the needs of existing and future customers. For 1996, 1995 and 1994, Eastern Edison's and Montaup's combined cash construction expenditures were $26.0 million, $23.4 million, and $23.6 million, respectively. Internally generated funds provided approximately 118% of Eastern Edison's and Montaup's combined cash construction requirements in 1996. Cash construction expenditures are expected to be approximately $16.2 million in 1997, and $9.9 million in 1998 and 1999, and are expected to be financed with internally generated funds. In the utility industry, cash construction requirements not met with internally generated funds are obtained through short-term borrowings which are ultimately funded with permanent capital. EUA System companies, including Eastern Edison and Montaup, maintain short-term lines of credit with various banks aggregating approximately $140 million. These credit lines are available to other affiliated companies under joint credit line arrangements. At December 31, 1996, unused short-term lines of credit amounted to approximately $89 million. At December 31, 1996, Eastern Edison had $2.0 million of outstanding short-term debt and Montaup had no outstanding short-term debt. In addition to construction expenditures, projected requirements for maturing long-term debt securities through 2001 are $60 million in 1998. The Company has no sinking fund requirements until the year 2003. Electric Utility Industry Restructuring Initiatives On August 7, 1996 the Governor of Rhode Island signed into law the Utility Restructuring Act of 1996 (URA). The URA provides for customer choice of electricity supplier to be phased-in commencing July 1, 1997 for large manufacturing customers, certain new commercial and industrial customers, and State of Rhode Island accounts. By July 1, 1998 or sooner, all customers will have retail access. Under the URA the local distribution company will retain the responsibility of providing distribution services to the ultimate electricity consumer within its franchised service territory. For customers who choose not to choose, the local distribution company would be allowed to arrange for supply at a non-discriminatory, "standard offer" price. Distribution companies will also be providers of last resort, required to arrange for supply, at prevailing market prices, for customers who are unable to do so. Both Blackstone and Newport are currently all requirements customers of Montaup for generation services. This legislation provides for recovery of prudently incurred embedded generation costs that may not be to recovered in a competitive electric generation market, commonly referred to as "stranded costs", through a non-bypassable transition charge initially set at 2.8 cents per kWh. The transition charge recovers, among other things, costs of depreciated generation net of its market value, regulatory assets, nuclear decommissioning and above market payments to power suppliers. The costs of net, above-market generation assets and regulatory assets will be recovered, with a return, through a fixed component of the transition charge from July 1, 1997 through December 31, 2009. A variable component of the transition charge will recover, on a reconciling basis, among other things, nuclear decommissioning and above market purchased power commitments from July 1, 1997 through the life of the respective unit or contract. The URA also provides for commitments to demand side management initiatives and renewables, low income protections, divestiture of at least 15% of owned non-nuclear generating units as a valuation basis for mitigation of stranded cost recovery, and performance based rate making standards for electric distribution companies. Performance based regulation provides for a minimum and maximum allowed return on equity. In addition, the URA provides for adjustments to electric distribution companies' base rates using the prior year's Consumer Price Index and other performance factors. Under this provision of the law, base rates were increased 1.88% for customers of Blackstone, and 2.18% for our Newport customers effective January 1, 1997. The implementation of the URA will require approvals from applicable regulatory agencies, including the Federal Energy Regulatory Commission (FERC), the Rhode Island Public Utilities Commission (RIPUC), and the Securities and Exchange Commission (SEC). In February 1997, Blackstone, Newport and Montaup reached settlement with the Rhode Island Division of Public Utilities and Carriers (RIDPUC) and the Rhode Island Attorney General with regards to implementation of a restructuring plan for Blackstone, Newport and Montaup. In addition to complying with the URA, the settlement provides for an immediate 10% rate reduction and a commitment by Montaup to file a plan by July 1, 1997 to divest all of its generating assets, and is similar in many respects to the settlement negotiated in Massachusetts, described below. On December 23, 1996, Eastern Edison and Montaup reached an agreement in principle with the Attorney General of Massachusetts and the Massachusetts Division of Energy Resources on a plan, similar in many aspects to the URA, which would allow retail customers to choose their supplier of electricity in 1998 and provide Eastern Edison and Montaup full recovery of "stranded costs." A formal plan is expected to be filed with the Massachusetts Department of Public Utilities (MDPU) in March of 1997. The agreement envisions that all of Eastern Edison's customers will have the ability to choose an alternative supplier of electricity beginning on January 1, 1998. Until a customer chooses an alternative supplier, that customer would receive "standard offer" service which would be priced to guarantee that customer at least a ten percent savings from today's electricity prices. Eastern Edison would be required to arrange for "standard offer" service and would purchase power for "standard offer" service from suppliers through a competitive bidding process. The agreement is also designed to achieve full divestiture of Montaup's generating assets via implementation of a plan, to be submitted to the MDPU by July 1, 1997, that would require (1) separation by Montaup of its generating and transmission businesses and (2) full market valuation and sale of all generating assets through an auction or equivalent process, to be conducted by an independent third party. Upon the commencement of retail choice in Massachusetts, Montaup's wholesale contract with Eastern Edison would be terminated. In return, the cost of Montaup's above market, embedded generation commitments to serve Eastern Edison's customers would be recovered, with a return, through a non- bypassable transition access charge to all Eastern Edison customers. The transition access charge would be reduced by the fair market value of Montaup's generating assets as determined by selling, spinning off, or otherwise disposing of such generating facilities. Embedded costs associated with generating plants and regulatory assets would be recovered, with a return, over a period of 12 years. Purchased power contracts and nuclear decommissioning costs would be recovered as incurred over the life of those obligations, a period expected to extend beyond 12 years. The initial transition access charge would be set at 3.04 cents per kWh through December 31, 2000, and is expected to decline thereafter. The agreement also establishes performance-based regulation for Eastern Edison incorporating a floor and cap on allowed return on equity. Under the agreement, Eastern Edison's distribution rates would be frozen at 1996 levels until December 31, 2000. Subsequent to the commencement of retail choice, Eastern Edison's annual return on equity would be subject to a floor of 6 percent and a ceiling of 11.75 percent. In addition to MDPU approval of the agreement, implementation is also subject to the approval of the FERC. Any disposition of generation assets resulting from the agreement or the URA would also require the approval of the SEC under the Public Utility Holding Company Act of 1935. Historically, electric rates have been designed to recover a utility's full costs of providing electric service including recovery of investment in plant assets. Also, in a regulated environment, electric utilities are subject to certain accounting rules that are not applicable to other industries. These accounting rules allow regulated companies, in appropriate circumstances, to establish regulatory assets and liabilities, which defer the current financial impact of certain costs that are expected to be recovered in future rates. The SEC has raised issues concerning the continued applicability of these standards with certain other electric utilities, in other states, facing restructuring. The Company believes that its operations will continue to meet the criteria established in these accounting standards. However, the potential exists that the final outcome of state and federal agency determinations could result in the Company no longer meeting the criteria of certain accounting standards which could trigger the discontinuance of Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation" (FAS71). Should it be required to discontinue the application of FAS71, the Company would be required to take an immediate write down of the affected assets in accordance with FAS101, "Accounting for the Discontinuation of Application of FAS71." In addition, if legislative or regulatory changes and/or competition result in electric rates which do not fully recover the company's costs, a write-down of plant assets could be required pursuant to Financial Accounting Standard No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of" (FAS121) issued in March 1995. Environmental Matters Eastern Edison, Montaup 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 United States 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, an environmental audit program designed to ensure compliance with environmental laws and regulations and to identify and reduce liability was instituted by EUA. Because of the nature of Eastern Edison's and Montaup'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. Eastern Edison and Montaup generally provide 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 cleanup costs. Eastern Edison and Montaup 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, Eastern Edison and Montaup are unable to predict whether liability, if any, will be assumed by, or can be enforced against, the insurance carriers in these matters. As of December 31, 1996, Eastern Edison and Montaup had incurred costs of approximately $800,000, in connection with these sites. These amounts have been financed primarily by internally generated cash. Montaup is currently recovering certain of its incurred environmental costs in rates. Eastern Edison and Montaup estimate that additional costs of up to $130,000 may be incurred at these sites through 1998. Estimates beyond 1998 cannot be made since site studies, which are the basis of these estimates, have not been completed. As a result of the recoverability in current rates of environmental costs, and the uncertainty regarding both its estimated liability, as well as potential contributions from insurance carriers, Eastern Edison and Montaup do not believe that the ultimate impact of environmental costs will be material to their financial position and thus, no loss provision is required at this time. 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 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. The 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 EMF, are continuing. On October 31, 1996, the National Academy of Sciences issued a literature review of all research to date, "Possible Health Effects of Exposure to Residential Electric and Magnetic Fields." Its most widely reported conclusion stated, "No clear, convincing evidence exists to show that residential exposures to EMF are a threat to human health." Management cannot predict the ultimate outcome of the EMF issue. Nuclear Power Issues Montaup has a 4.01% ownership interest in Millstone III, an 1154-mw nuclear unit that is jointly owned by a number of New England utilities, including subsidiaries of Northeast Utilities (Northeast), the operator of the plant. On March 30, 1996, Northeast shut down the unit following an engineering evaluation which determined that four safety-related valves would not be able to perform their design function during certain postulated events. The Nuclear Regulatory Commission (NRC) has raised numerous issues with respect to the unit and certain of the other nuclear units operated by Northeast. The NRC has established a Special Projects Office to oversee inspection and licensing activities at Millstone and 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. Northeast management has indicated it cannot currently estimate the effect these efforts will have on the timing of restarts or what additional costs, if any, these developments may cause. While Millstone III is out of service, Montaup will incur incremental replacement power costs estimated at $400,000 to $800,000 per month. Montaup bills its replacement power costs through its fuel adjustment clause, a wholesale tariff jurisdictional to FERC. However, there is no comparable clause in Montaup's FERC-approved rates which at this time would permit Montaup to recover its share of the incremental O&M costs incurred at Millstone III. The Company cannot predict the ultimate outcome of the NRC inquiries or the impact which they may have on Montaup. Montaup is also evaluating its rights and obligations under the various agreements relating to the ownership and operation of Millstone III. Montaup holds a 4.0% ownership interest in the Maine Yankee nuclear unit. In December, 1996 the unit was shut down for inspections and repairs and in January 1997 the NRC announced that it had placed the unit on its watch list. The operator of the unit had been addressing issues of non-conformance to the unit's licensing basis identified by the NRC in October 1996, prior to the NRC's January 1997 announcement. The operator of the plant cannot estimate when the unit will restart. Connecticut Yankee, a 582-mw nuclear unit, was taken off-line in July 1996 because of issues related to certain containment air recirculation and service water systems. Montaup has a 4.5% equity ownership in Connecticut Yankee with a book value of $4.8 million at December 31, 1996. In October 1996, Montaup, as one of the joint owners, participated in an economic evaluation of Connecticut Yankee which recommended permanently closing the unit and replacing its output with less expensive energy sources. As a result of the analysis, work at the plant had slowed pending a final board decision. In December 1996, the Board of Directors voted to retire the generating station. Connecticut Yankee certified to the NRC that it had permanently closed power generation operations and removed fuel from the reactor. Connecticut Yankee has two years to submit its decommissioning plan to the NRC. The preliminary estimate of the sum of future payments for the permanent shutdown, decommissioning, and recovery of the remaining investment in Connecticut Yankee, is approximately $758 million. Montaup's share of the total estimated costs is $34.1 million at December 31, 1996 and is included in Other Liabilities on the Consolidated Balance Sheet at December 31, 1996. Also, due to anticipated recoverability, a regulatory asset has been recorded for the same amount and is included with Other Assets. 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 III and Seabrook I nuclear generating units. Montaup's share of the currently allowed estimated total costs to decommission Millstone III is approximately $18.6 million in 1996 dollars and Seabrook I is approximately $13.1 million in 1996 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. Other The Company 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. Actual results could differ materially from these statements. Therefore, no assurances can be given that such forward-looking statements and estimates will be achieved. 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" in arriving at a more complete understanding of such matters. Financial Table of Contents Consolidated Statement of Income. . . . . . . . . . . . . . . 12 Consolidated Statement of Retained Earnings . . . . . . . . . . . . . . 12 Consolidated Statement of Cash Flow . . . . . . . . . . . . . . . . . . 13 Consolidated Balance Sheet . . . . . . . . . . . . . . . . . . . . . . . 14 Consolidated Statement of Capitalization . . . . . . . . . . . . . . . . 15 Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . 16 Report of Independent Accountants . . . . . . . . . . . . . . . . . . . . 31 Eastern Edison Company and Subsidiary Consolidated Statement of Income Years Ended December 31, (In Thousands)
1996 1995 1994 Operating Revenues: From Affiliated Companies $ 127,981 $ 133,388 $ 126,481 Other 276,827 286,681 291,943 Total Operating Revenues 404,808 420,069 418,424 Operating Expenses: Fuel 92,159 90,881 87,522 Purchased Power - Demand 118,843 125,594 122,995 Other Operation and Maintenance 66,311 73,638 80,300 Affiliated Company Transactions 25,908 23,386 22,446 Voluntary Retirement Incentive 0 2,413 Depreciation and Amortization 26,810 26,039 25,546 Taxes - Other than Income 10,705 10,233 10,543 - Income 16,058 15,653 15,830 Total Operating Expenses 356,794 367,837 365,182 Operating Income 48,014 52,232 53,242 Equity in Earnings of Jointly Owned Companies 1,587 1,646 1,700 Allowance for Other Funds Used During Construction 365 473 263 Other Income (Deductions) - Net 1,583 407 897 Income Before Interest Charges 51,549 54,758 56,102 Interest Charges: Interest on Long-Term Debt 15,233 18,277 18,488 Other Interest Expense 3,653 3,541 4,525 Allowance for Borrowed Funds Used During Construction (Credit) (308) (503) (294) Net Interest Charges 18,578 21,315 22,719 Net Income 32,971 33,443 33,383 Preferred Dividend Requirements 1,988 1,988 1,988 Consolidated Net Earnings Applicable to Common Stock $ 30,983 $ 31,455 $ 31,395
Consolidated Statement of Retained Earnings Years Ended December 31, (In Thousands)
1996 1995 1994 Retained Earnings - Beginning of Year $ 124,878 $ 105,574 $ 103,515 Net Income 32,971 33,443 33,383 Amortization of Preferred Stock Redemption Premium (817) (961) (596) Total 157,032 138,056 136,302 Dividends Paid: Preferred 1,988 1,988 1,988 Common 34,320 11,190 28,740 Retained Earnings - End of Year $ 120,724 $ 124,878 $ 105,574
The accompanying notes are an integral part of the financial statements. Eastern Edison Company and Subsidiary Consolidated Statement of Cash Flows Years Ended December 31, (In Thousands)
1996 1995 1994 CASH FLOW FROM OPERATING ACTIVITIES: Net Income $ 32,971 $ 33,443 $ 33,383 Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities: Depreciation and Amortization 28,607 29,852 28,981 Amortization of Nuclear Fuel 1,676 3,647 3,310 Deferred Taxes 5,217 2,694 5,500 Investment Tax Credit, Net (939) (942) (348) Allowance for Funds Used During Construction (365) (473) (263) Other - Net (2,333) 1,219 (3,285) Changes to Operating Assets and Liabilities: Accounts Receivable (1,862) (7,055) (7,667) Fuel, Materials and Supplies 673 (1,678) 194 Accounts Payable 186 827 3,495 Accrued Taxes (241) 1,807 (2,814) Other - Net 9,266 (6,630) 4,485 Net Cash Provided from Operating Activities 72,856 56,711 64,971 CASH FLOW FROM INVESTING ACTIVITIES: Construction Expenditures (26,006) (23,423) (23,613) Decrease in Other Investments 148 Net Cash (Used in) Investing Activities (25,858) (23,423) (23,613) CASH FLOW FROM FINANCING ACTIVITIES: Redemptions: Long-Term Debt (7,000) (35,000) Premium on Reacquisition and Financing Expenses (62) Common Stock Dividends Paid (34,320) (11,190) (28,740) Preferred Dividends Paid (1,988) (1,988) (1,988) Net (Decrease) Increase in Short Term De (2,118) 4,158 Net Cash (Used in) Financing Activities (45,426) (44,020) (30,790) Net Increase (Decrease) in Cash and Temporary Cash Investments 1,572 (10,732) 10,568 Cash and Temporary Cash Investments at Beginning of Year 533 11,265 697 Cash and Temporary Cash Investments at End of Year $ 2,105 $ 533 $ 11,265 Cash paid during the year for: Interest (Net of Amounts Capitalized) $ 15,241 $ 18,343 $ 18,406 Income Taxes $ 13,267 $ 9,044 $ 15,877
The accompanying notes are an integral part of the financial statements. Eastern Edison Company and Subsidiary Consolidated Balance Sheet December 31, (In Thousands)
ASSETS 1996 1995 Utility Plant and Other Investments: Utility Plant $ 817,992 $ 798,706 Less Accumulated Provision for Depreciation 261,464 241,673 Net Utility Plant 556,528 557,033 Non-Utility Property - Net 2,705 2,705 Investment in Jointly Owned Companies 13,210 13,223 Other Investments (at cost) 95 50 Total Utility Plant and Other Investments 572,538 573,011 Current Assets: Cash and Temporary Cash Investments 2,105 533 Accounts Receivable: Customers 27,633 25,730 Others 3,464 2,348 Accrued Unbilled Revenue 8,376 9,158 Associated Companies 25,486 25,861 Fuel (at average cost) 6,844 7,385 Plant Materials and Operating Supplies (at average cost) 3,805 3,937 Prepayments and Other Current Assets 3,598 4,170 Total Current Assets 81,311 79,122 Other Assets (Note A) 121,233 87,065 Total Assets $ 775,082 $ 739,198 LIABILITIES AND CAPITALIZATION Capitalization: Common Equity $ 240,213 $ 244,368 Redeemable Preferred Stock - Net 29,665 29,665 Preferred Stock Redempton Cost (2,630) (3,447) Long-term Debt - Net 222,402 222,313 Total Capitalization 489,650 492,899 Current Liabilities: Long-term Debt Due Within One Year 0 7,000 Notes Payable 2,040 4,158 Accounts Payable: Public 27,391 27,242 Associated Companies 3,950 3,913 Customer Deposits 1,153 1,103 Taxes Accrued 2,977 3,219 Interest Accrued 4,895 4,999 Other Current Liabilities 16,081 7,332 Total Current Liabilities 58,487 58,966 Other Liabilities 41,914 10,100 Deferred Credits: Unamortized Investment Credit 16,903 17,842 Other Deferred Credits 25,689 30,625 Total Deferred Credits 42,592 48,467 Accumulated Deferred Taxes 142,439 128,766 Commitments and Contingencies (Note J) Total Liabilities and Capitalization $ 775,082 $ 739,198
The accompanying notes are an integral part of the financial statements. Eastern Edison Company and Subsidiary Consolidated Statement of Capitalization December 31, (In Thousands)
1996 1995 Common Stock: $25 par value, authorized and outstanding 2,891,357 shares $ 72,284 $ 72,284 Other Paid-In Capital 47,249 47,249 Common Stock Expense (44) (43) Retained Earnings 120,724 124,878 Total Common Equity 240,213 244,368 Redeemable Preferred Stock: 6 5/8%, $100 par value, 300,000 shares 30,000 30,000 Expense, Net of Premium (335) (335) Preferred Stock Redemption Cost (2,630) (3,447) Total Redeemable Preferred Stock 27,035 26,218 Long-Term Debt: First Mortgage and Collateral Trust Bonds: 5 7/8% due 1998 20,000 20,000 6 7/8% due 2003 40,000 40,000 8% due 2023 40,000 40,000 5 3/4% due 1998 40,000 40,000 6.35% due 2003 8,000 8,000 4.875% due 1996 0 7,000 7.78% Secured Medium-Term Notes due 2002 35,000 35,000 Pollution Control Revenue Bond: 5 7/8% due 2008 40,000 40,000 Unamortized (Discount) - Net (598) (687) 222,402 229,313 Less Portion Due Within One Year 0 7,000 Total Long-Term Debt 222,402 222,313 Total Capitalization $ 489,650 $ 492,899 Authorized and Outstanding.
The accompanying notes are an integral part of the financial statements. EASTERN EDISON COMPANY AND SUBSIDIARY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 1996, 1995, and 1994 (A) Nature of Operations and Summary of Significant Accounting Policies: General: Eastern Edison Company (Eastern Edison or the Company) and its wholly owned subsidiary, Montaup Electric Company (Montaup) are principally engaged in the generation, transmission, distribution and sale of electric energy. 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. The accounting policies and practices of Eastern Edison and of Montaup are subject to regulation by FERC and the MDPU with respect to their rates and accounting. Eastern Edison and Montaup conform with generally accepted accounting principles, as applied in the case of regulated public utilities, and conform with the accounting requirements and ratemaking practices of the regulatory authority having jurisdiction. Principles of Consolidation: The consolidated financial statements include the accounts of Eastern Edison and its subsidiary, Montaup. All material intercompany balances and transactions have been eliminated in consolidation. Reclassifications: Certain prior period amounts on the financial statements have been reclassified to conform with current presentation. Jointly Owned Companies: 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 2.50 to 4.50 percent. Montaup is entitled to electricity produced from these facilities based on its ownership interests and is billed for its entitlement pursuant to contractual agreements which are approved by FERC. One of the four nuclear generating facilities, Yankee Atomic, is being decommissioned. Montaup is required to pay, and has received FERC authorization to recover, its proportionate share of any unrecovered costs and costs incurred after the plant's retirement. Montaup's share of all unrecovered assets and the total estimated costs to decommission the unit aggregated approximately $7.8 million at December 31, 1996 and is included with Other Liabilities on the Consolidated Balance Sheet. Also, due to recoverability, a regulatory asset has been recorded for the same amount and is included with Other Assets. In December 1996 the Board of Directors of Connecticut Yankee voted to retire the generating station. Connecticut Yankee certified to the NRC that it had permanently closed power generation operations and removed fuel from the reactor. Montaup has a 4.5% equity ownership in Connecticut Yankee. Montaup's share of all unrecovered assets and the total estimated costs to decommission the unit aggregated approximately $34.1 million at December 31, 1996 and is included with Other Liabilities on the Consolidated Balance Sheet. Also, due to anticipated recoverability, a regulatory asset has been recorded for the same amount and is included with Other Assets. Montaup also has a stock ownership investment of 3.27% in each of the two companies which own and operate certain interconnection facilities used to transmit hydroelectric power between the Hydro-Quebec Electric System and New England. Transactions with Affiliates: Eastern Edison is a wholly owned subsidiary of Eastern Utilities Associates (EUA). In addition to its investment in Eastern Edison, EUA has interests in two other retail companies, a service corporation, and four other non-utility companies. Transactions between Montaup and other affiliated companies include the following: sales of electricity by Montaup to Blackstone Valley Electric Company (Blackstone) and Newport Electric Corporation (Newport) aggregating approximately $127,536,000 in 1996, $133,841,000 in 1995 and $126,237,000 in 1994; accounting, engineering and other services rendered by EUA Service Corporation to Eastern Edison and Montaup of approximately $30,886,000, $29,264,000, and $27,365,000, in 1996, 1995 and 1994, respectively; and operating expense from the rental of transmission and generation facilities by Blackstone and Newport to Montaup aggregating approximately $3,960,000 in 1996, $4,351,000 in 1995 and $3,627,000 in 1994. Montaup rental of transmission facilities to Newport was zero in 1996 and 1995, and $149,000 for 1994, respectively. Transactions with affiliated companies are subject to review by applicable regulatory commissions. Utility 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. Provisions for depreciation, on a consolidated basis, were equivalent to a composite rate of approximately 3.2% in 1996, 1995 and 1994 based on the average depreciable property balances at the beginning and end of each year. Electric Plant Held for Future Use: In January 1994 Montaup determined that it would not be economically feasible to bring its 42-year old, coal-fired Somerset Station Unit 5 generating unit into compliance with Clean Air Act Amendments of 1990 (Clean Air Act). The unit was placed in cold storage and its net investment, $5.4 million, was transferred to electric plant held for future use pending final determination by Montaup of its usefulness. Under terms of the settlement agreement filed with FERC, entered into by Montaup and the intervenors in Montaup's 1994 rate decrease application, Montaup continues to earn a return on the net investment of the unit. Other Assets: The components of Other Assets at December 31, 1996 and 1995 are detailed as follows: (In Thousands) 1996 1995 Regulatory Assets: Unamortized losses on reacquired debt $13,277 $14,981 Unrecovered plant and decommissioning cost 41,914 10,100 Deferred SFAS 109 costs (Note B) 47,326 44,387 Deferred SFAS 106 costs (Note J) 2,153 2,365 Other regulatory assets 4,886 4,790 Total regulatory assets 109,556 76,623 Other deferred charges and assets: Unamortized debt expenses 2,456 2,847 Other 9,221 7,595 Total Other Assets $121,233 $87,065 Regulatory Accounting: Eastern Edison and Montaup 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. Eastern Edison and Montaup believe that their operations continue to meet the criteria established in these accounting standards. Effects of legislation and/or regulatory initiatives or EUA's own initiatives could ultimately cause Eastern Edison and Montaup to no longer follow these accounting rules. In such an event, a non-cash write-off of regulatory assets and liabilities could be required at that time. Allowance for Funds Used During Construction (AFUDC): AFUDC represents the estimated cost of borrowed and equity funds used to finance Eastern Edison's and Montaup'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 8.9% in 1996, 9.4% in 1995 and 9.6% in 1994. Operating Revenues: Revenues are based on billing rates authorized by applicable federal and state regulatory commissions. Eastern Edison follows the policy of accruing the estimated amount of unbilled base rate revenues for electricity provided at the end of the month to more closely match costs and revenues. Montaup recognizes revenues when billed. In addition, Eastern Edison and Montaup also record the difference between fuel costs incurred and fuel costs billed. Montaup also records the difference between purchased power costs incurred and billed. (A) Nature of Operations and Summary of Significant Accounting Policies: (continued) Income Taxes: The general policy of Eastern Edison and Montaup with respect to accounting for federal and state income taxes is to reflect in income the estimated amount of taxes currently payable, as determined from the EUA consolidated tax return on an allocated basis, and to provide for deferred taxes on certain items subject to temporary differences to the extent permitted by the various regulatory commissions. As permitted by the regulatory commissions, it is the policy of Eastern Edison and Montaup to defer recognition of the annual investment tax credits and to amortize these credits over the productive lives of the related assets. Cash and Temporary Cash Investments: Eastern Edison and Montaup consider all highly liquid investments and temporary cash investments with a maturity of three months or less, when acquired, to be cash equivalents. (B) Income Taxes: Components of income tax expense for the years 1996, 1995, and 1994 are as follows: ___________________________________________________________________ (In Thousands) 1996 1995 1994 Federal: Current $9,111 $11,387 $ 9,143 Deferred 5,152 3,679 4,697 Investment Tax Credit, Net (939) (942) (348) $13,324 $14,124 $13,492 State: Current 2,612 2,447 1,468 Deferred 122 (918) 870 2,734 1,529 2,338 Charged to Operations 16,058 15,653 15,830 Charged to Other Income: Current 1,233 522 617 Deferred (67) (67) (67) Total $17,224 $16,108 $16,380 Total income tax expense was different than the amounts computed by applying federal income tax statutory rates to book income subject to tax for the following reasons: _____________________________________________________________________________ (In Thousands) 1996 1995 1994 Federal Income Tax Computed at Statutory Rates $17,568 $17,343 $17,417 (Decreases) Increases in Tax from: Equity Component of AFUDC (128) (165) (92) Consolidated Tax Savings (156) (108) (651) Depreciation Differences (452) (264) (321) Amortization and Utilization of ITC (939) (942) (945) State Taxes, Net of Federal Income Tax Benefit 1,897 (2,625) 1,614 Cost of Removal 58 (226) Other (566) 2,811 (416) Total Income Tax Expense $17,224 $16,108 $16,380 (B) Income Taxes (continued) Eastern Edison and Montaup adopted Statement of Financial Accounting Standard No. 109, "Accounting for Income Taxes" (FAS109) which required 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 rate making treatment and provisions in the Tax Reform Act of 1986. The total deferred tax assets and liabilities at December 31, 1996 and 1995 are comprised as follows: Deferred Tax Deferred Tax Assets Liabilities ($000) ($000) 1996 1995 1996 1995 Plant Related Plant Related Differences $13,490 $16,181 Differences $153,471 $146,632 Alternative Refinancing Minimum Tax 412 4,470 Costs 1,471 1,691 Pensions 1,299 1,070 Pensions 877 940 Other 1,040 1,060 Other 2,507 1,901 Total 16,241 $22,781 Total $158,326 $151,164 As of December 31, 1996 and 1995, the Company had recorded on its Consolidated Balance Sheet a regulatory liability to ratepayers of approximately $18.0 million and $23.6 million, respectively. This amount primarily represents excess deferred income taxes resulting from the reduction in the federal income tax rate and also includes deferred taxes provided on investment tax credits. Also at December 31, 1996 and 1995, a regulatory asset of approximately $47.3 million and $44.4 million, respectively, has been recorded, representing the cumulative amount of federal income taxes on temporary depreciation differences which were previously flowed through to ratepayers. Montaup has approximately $0.4 million, respectively, of alternative minimum tax credits which can be utilized to reduce the EUA System's consolidated regular tax liability and have no expiration. (C) Capital Stock: There were no changes in the number of shares of common or preferred stock during the years ended December 31, 1996, 1995 and 1994. Under the terms and provisions of the issues of preferred stock of Eastern Edison, certain restrictions are placed upon the payment of dividends on common stock by Eastern Edison. At December 31, 1996, 1995 and 1994, the respective capitalization ratios were in excess of the minimum requirements which would make these restrictions effective. (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 will be 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) Retained Earnings: Under the provisions of Eastern Edison's Indenture securing the First Mortgage and Collateral Trust Bonds, retained earnings in the amount of $117,385,954 as of December 31, 1996 were unrestricted as to the payment of cash dividends on its Common Stock. (F) Long-Term Debt: The various mortgage bond issues of Eastern Edison 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, in the principal amount of approximately $236 million. In September, Eastern Edison used available cash to redeem $7 million of 4.875% First Mortgage Bonds at maturity. The Company'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 1996 are: none in 1997, $60 million in 1998, and none in 1999, 2000 and 2001. (G) Lines of Credit: EUA System companies including Eastern Edison maintain short-term lines of credit with various banks aggregating approximately $140 million. At December 31, 1996, unused short-term lines of credit were approximately $89 million. These credit lines are available to other EUA System companies under joint credit line arrangements. In accordance with informal agreements with the various banks, commitment fees are required to maintain certain lines of credit. During 1996, the weighted average interest rate for short-term borrowings by the Company was 5.6%. (H) Jointly Owned Facilities: At December 31, 1996, in addition to the stock ownership interests discussed in Note A, Summary of Significant Accounting Policies - Jointly Owned Companies, Montaup had direct ownership interests in the following electric generating facilities (In Thousands): Accumulated Provision For Net Construc- Utility Depreciation Utility tion Percent Plant in and Plant in Work in ($ In Thousands) Owned Service Amortization Service Progress Montaup: Canal 2 50.00% $ 83,194 $41,843 $ 41,351 $446 Wyman 4 1.96% 4,051 2,130 1,921 Seabrook I 2.90% 194,928 29,983 164,945 251 Millstone III 4.01% 178,854 49,560 129,294 170 The foregoing amounts represent Montaup'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, 1996, Montaup's total net investment in nuclear fuel of the Seabrook and Millstone units amounted to $2.8 million and $1.8 million, respectively. Montaup's shares of related operating and maintenance expenses with respect to units reflected in the table above are included in the corresponding operating expenses on the Consolidated Statement of Income. (I) 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 those instruments. Redeemable Preferred Stock and Long-Term Debt: The fair value of the Company's redeemable preferred stock and long-term debt were based on quoted market prices for such securities. The estimated fair values of the Company's financial instruments at December 31, 1996 are as follows (In Thousands): Carrying Fair Amount Value Cash and Temporary Cash Investments $ 2,105 $ 2,105 Redeemable Preferred Stock 30,000 30,300 Long-Term Debt $223,000 $225,870 (J) Commitments and Contingencies: Nuclear Fuel Disposal and Nuclear 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. Montaup owns a 4.01% interest in Millstone III and a 2.9% interest in Seabrook I. Northeast Utilities, the operator of the units, indicates that Millstone III 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. Also, Montaup is recovering through rates its share of estimated decommissioning costs for Millstone III and Seabrook I. Montaup's share of the current estimate of total costs to decommission Millstone III is $18.6 million in 1996 dollars, and Seabrook I is $13.1 million in 1996 dollars. These figures are based on studies performed for the lead owner of the units. Montaup also pays into decommissioning reserves pursuant to contractual arrangements with other nuclear generating facilities in which it has an equity ownership interest or life of the unit entitlement. Such expenses are currently recoverable through rates. Pensions: Eastern Edison and Montaup participate with the other EUA System companies in a non-contributory defined benefit pension plan covering substantially all of their employees (Retirement Plan). Retirement Plan benefits are based on years of service and average compensation over the four years prior to retirement. It is the EUA System's policy to fund the Retirement Plan on a current basis in amounts determined to meet the funding standards established by the Employee Retirement Income Security Act of 1974. Total pension (income) expense for the Retirement Plan, including amounts related to the 1995 Voluntary Retirement Incentive Offer, for 1996, 1995 and 1994 includes the following components ($ In Thousands): 1996 1995 1994 Service cost - benefits earned during the period $ 1,713 $ 1,504 $ 1,783 Interest cost on projected benefit obligation 5,767 5,575 5,217 Actual (return) loss on assets (10,036) (22,158) 927 Net amortization and deferrals 2,407 14,855 (7,677) Net periodic pension (income) expense $ (149) $ (224) $ 250 Voluntary retirement incentive 857 Total periodic pension (income) expense $ (149) $ 633 $ 250 Assumptions used to determine pension cost: 1996 1995 1994 Discount Rate 7.25% 8.25% 7.25% Compensation Increase Rate 4.25% 4.75% 4.75% Long-Term Return on Assets 9.50% 9.50% 9.50% The discount rate used to determine pension obligations was changed effective January 1, 1997 to 7.5%. The funded status of the Retirement Plan cannot be presented separately for Eastern Edison and Montaup as they participate in the Retirement Plan with other subsidiaries of EUA. The one-time voluntary retirement incentive also resulted in approximately $800,000 of non-qualified pension benefits which were expensed in 1995. At December 31, 1996, approximately $424,000 is included in other liabilities for these unfunded benefits. EUA also maintains non-qualified supplemental retirement plans for certain officers 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 the participants of the Supplemental Plans to fund in whole, or in part, its future liabilities under the Supplemental Plans. For the years ended December 31, 1996, 1995 and 1994 Eastern Edison's and Montaup's expenses related to the Supplemental Plan were approximately $717,000, $825,000 and $266,000, respectively. The Company also provides a defined contribution 401(k) savings plan for substantially all employees. The Company's matching percentage of employees' voluntary contributions to the plan, amounted to approximately $306,000 in 1996, approximately $369,000 in 1995 and approximately $ 431,000 in 1994. 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. Eastern Edison and Montaup adopted FAS106, "Employers' Accounting for Post-Retirement Benefits Other Than Pensions," as of January 1, 1993. This standard establishes accounting and reporting standards for such post- retirement benefits as health care and life insurance. Under FAS106 the present value of future benefits is recorded as a periodic expense over employee service periods through the date they become fully eligible for benefits. With respect to periods prior to adopting FAS106, EUA elected to recognize accrued costs (the Transition Obligation) over a period of 20 years, as permitted by FAS106. The resultant annual expense, including amortization of the Transition Obligation and net of amounts capitalized and deferred, was approximately $3.6 million in 1996, $4.0 million in 1995, and $3.4 million in 1994. The total cost of Post-Retirement Benefits other than Pensions, including amounts related to the 1995 Voluntary Retirement Incentive Offer, for 1996, 1995 and 1994 includes the following components (In Thousands): 1996 1995 1994 Service cost $ 637 $ 565 $ 880 Interest cost 2,688 2,926 3,252 Actual return on plan assets (115) (388) (75) Amortization of transition obligation 1,955 1,965 2,026 Net other amortization & deferrals (721) (632) (50) Net periodic post-retirement benefit costs 4,444 4,436 6,033 Voluntary retirement incentive 470 Total post-retirement benefit costs $4,444 $ 4,906 $ 6,033 Assumptions: Discount rate 7.25% 8.25% 7.25% Health care cost trend rate-near-term 9.00% 11.00% 13.00% -long-term 5.00% 5.00% 5.00% Compensation increase rate 4.25% 4.75% 4.75% Rate of return on plan assets-union 8.50% 8.50% 8.50% - non-union 7.50% 5.50% 5.50% Reconciliation of funded status:
1996 1995 1994 (In Thousands) Accumulated post-retirement benefit obligation (APBO): Retirees ($19,864) $(23,223) $(20,227) Active employee fully eligible for benefits (1,728) (3,649) (4,116) Other active employees (6,031) (7,711) (9,255) Total (27,623) (34,583) (33,598) Fair Value of assets (primarily notes and bonds) 5,161 3,830 2,169 Unrecognized transition obligation 26,095 27,726 30,007 Unrecognized net (gain) loss (9,297) (2,142) (3,158) (Accrued) prepaid post-retirement benefit cost $5,664 $ (5,169) $ (4,580)
The discount rate and compensation increase rates used to determine post- retirement benefit obligations effective January 1, 1997, are 7.5% and 4.25%, and were used to calculate the funded status of Post-Retirement Benefits at December 31, 1996. Increasing the assumed health care cost trend rate by 1% each year would increase the total post-retirement benefit cost for 1996 by approximately $311,000 and increase the total accumulated post-retirement benefit obligation by approximately $3.0 million. Eastern Edison and Montaup have also established an irrevocable external Voluntary Employees' Beneficiary Association (VEBA) Trust Fund as required by the aforementioned regulatory decisions. Contributions to the VEBA fund commenced in March 1993 and contributions were made totaling approximately $2.9 million in 1996, $3.2 million in 1995, and $2.9 million during 1994, respectively. Long-Term Purchased Power Contracts: Montaup 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, 1996, the aggregate annual minimum commitments for such contracts are approximately $122 million in 1997, $116 million in 1998, $114 million in 1999, $111 million in 2000, $111 million in 2001, and will aggregate $1.0 billion for the ensuing years. In addition, the EUA System is required to pay additional amounts depending on the actual amount of energy received under such contracts. 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. 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 Eastern Edison 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 Company 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. Eastern Edison and Montaup 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 Eastern Edison and Montaup to notify liability insurers and to initiate claims. However, it is not possible at this time to predict whether liability, if any, will be assumed by, or can be enforced against, the insurance carrier in these matters. As of December 31, 1996, Eastern Edison and Montaup have incurred costs of approximately $800,000 in connection with the foregoing environmental matters and estimate that additional expenditures may be incurred through 1997 up to $130,000. As a general matter Eastern Edison and Montaup will seek to recover costs relating to environmental proceedings in their rates. Montaup is currently recovering certain of the incurred costs in its rates. Estimated amounts after 1998 are not now determinable since site studies which are the basis of these estimates have not been completed. As a result of the recoverability in current rates, and the uncertainty regarding both its estimated liability, as well as potential contributions from insurance carriers and other responsible parties, Eastern Edison and Montaup do not believe that the ultimate impact of the environmental costs will be material to their financial position and thus, no loss provision is required at this time. The Clean Air Act Amendments of 1990 (Clean Air Act) created new regulatory programs and generally updated and strengthened air pollution control laws. These amendments will expand the regulatory role of the EPA regarding emissions from electric generating facilities and a host of other sources. Montaup generating facilities were first affected in 1995, when EPA regulations took effect for facilities owned by Montaup. Montaup's coal-fired Somerset Unit No. 6 is utilizing lower sulfur content coal to meet the 1995 air standards. Eastern Edison does not anticipate the impact from the Amendments to be material to its financial position. In November of 1996, the EPA proposed to toughen the nation's ozone standards as well as the particulate matters standards. The effect that such rules will have on the EUA System cannot be determined by management at this time. On December 23, 1996, Eastern Edison, Montaup, the Massachusetts Attorney General and Division of Energy Resources reached a settlement in principle regarding electric utility industry restructuring in the State of Massachusetts. The proposed settlement includes a plan for emissions reductions related to Montaup's Somerset Station Units 5 and 6, and to Montaup's 50% ownership share of Canal Electric's Unit #2. The basis for sulfur dioxide (SO2) and nitrogen oxide (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 proposed settlement is expected to be filed with MDPU in March 1997. In April 1992, the Northeast States for Coordinated Air Use Management (NESCAUM), an environmental advisory group for eight Northeast states including Massachusett 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 Amendments. The NESCAUM recommendations are more restrictive than 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 per year or more of NOx. Rhode Island has also issued similar regulations requiring that RACT be implemented at all stationary sources potentially emitting 50 tons or more per year of NOx. Montaup has initiated compliance through, among other things, selective, noncatalytic reduction processes. 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 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. The 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 EMF, are continuing. On October 31, 1996, the National Academy of Sciences issued a literature review of all research to date, "Possible Health Effects of Exposure to Residential Electric and Magnetic Fields." Its most widely reported conclusion stated, "No clear, convincing evidence exists to show that residential exposures to EMF are a threat to human health." 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: 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 $4.8 million of the outstanding debt of these two companies. In addition, Montaup has a minimum rental commitment which totals approximately $12.7 million under a noncancellable transmission facilities support agreement for years subsequent to 1996. Other: In early 1997, ten plaintiffs brought suit 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 is $25 million in compensatory and punitive damages, plus exemplary damages and interest and costs. Each names between fifteen and twenty-eight defendants, including EUA. These complaints have been referred to the applicable insurance companies, and EUA is consulting with those insurers to determine the availability and extent of coverage. EUA cannot predict the ultimate outcome of this matter at this time. Report of Independent Accountants To the Directors and Shareholder of Eastern Edison Company and Subsidiary: We have audited the accompanying consolidated balance sheet and consolidated statement of capitalization of Eastern Edison Company and its subsidiary (the Company) as of December 31, 1996 and 1995, and the related consolidated statement of income, retained earnings and cash flows for each of the three years in the period ended December 31, 1996. 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 in accordance with generally accepted auditing standards. Those standards 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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 1996 and 1995, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1996 in conformity with generally accepted accounting principles. /s/Coopers & Lybrand L.L.P. Boston, Massachusetts March 5, 1997 EX-23 11 EXHIBIT 23-1.03 CONSENT OF INDEPENDENT ACCOUNTANTS Exhibit 23-1.03 Consent of Independent Accountants To the Trustees and Shareholders of Eastern Utilities Associates: We consent to the incorporation by reference in the registration statements of Eastern Utilities Associates on Forms S-4 and S-8 (File No. 33-50099 and 33- 49897, respectively) of our reports dated March 5, 1997, on our audits of the consolidated financial statements and financial statement schedule of Eastern Utilities Associates and subsidiaries as of December 31, 1996 and 1995, and for the years ended December 31, 1996, 1995 and 1994, which reports are incorporated by reference or included in this Annual Report on Form 10-K. /s/Coopers & Lybrand L.L.P. Boston, Massachusetts March 17, 1997 EX-27 12 EUA FDS
UT 0000031224 EASTERN UTILITIES ASSOCIATES 1000 12-MOS DEC-31-1996 DEC-31-1996 PER-BOOK 720079 212310 149098 175542 0 1257029 102180 217229 52404 371813 27035 6900 406337 51848 0 0 27512 0 0 0 365584 1257029 527068 10942 460285 471227 55841 16204 72045 39119 32926 2312 30614 33618 34035 115695 1.50 0
EX-27 13 BVE FDS
UT 0000012473 BLACKSTONE VALLEY ELECTRIC COMPANY 1000 12-MOS DEC-31-1996 DEC-31-1996 PER-BOOK 87414 46 17448 27405 0 132313 9203 17908 9121 36232 0 6130 35000 735 0 0 1500 0 0 0 52716 132313 136911 2156 126989 129145 7766 80 7846 3781 4065 289 3776 4589 3313 11143 0 0
EX-27 14 EECO FDS
UT 0000014407 EASTERN EDISON COMPANY 1000 12-MOS DEC-31-1996 DEC-31-1996 PER-BOOK 556528 16010 81311 121233 0 775082 72284 47206 120723 240213 27035 0 222402 2040 0 0 0 0 0 0 283392 775082 404808 16058 340736 356794 48014 3535 51549 18578 32971 1988 30983 34320 15233 72856 0 0
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