-----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, N7EChlFPio/bRbv74BUeO/3d6i26X83H2ARKfyo3djIpfVc9BTI5aHGtkK5954oG IMyKiBefWQ2hcVd8qBWZ2Q== 0000031224-96-000014.txt : 19960326 0000031224-96-000014.hdr.sgml : 19960326 ACCESSION NUMBER: 0000031224-96-000014 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 15 CONFORMED PERIOD OF REPORT: 19951231 FILED AS OF DATE: 19960322 SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: EASTERN UTILITIES ASSOCIATES CENTRAL INDEX KEY: 0000031224 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 041271872 STATE OF INCORPORATION: MA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K405 SEC ACT: 1934 Act SEC FILE NUMBER: 001-05366 FILM NUMBER: 96537757 BUSINESS ADDRESS: STREET 1: ONE LIBERTY SQ STREET 2: P O BOX 2333 CITY: BOSTON STATE: MA ZIP: 02109 BUSINESS PHONE: 6173579590 FILER: COMPANY DATA: COMPANY CONFORMED NAME: BLACKSTONE VALLEY ELECTRIC CO CENTRAL INDEX KEY: 0000012473 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 050108587 STATE OF INCORPORATION: RI FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K405 SEC ACT: 1934 Act SEC FILE NUMBER: 000-02602 FILM NUMBER: 96537758 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: ELECTRIC SERVICES [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: 96537759 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 1995 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 (FEE REQUIRED) For the fiscal year ended December 31, 1995 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 (NO FEE REQUIRED) 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 18, 1996: Eastern Utilities Associates Common Shares, $5 par value - $102,183,775 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 18, 1996: 20,436,755 Blackstone Valley Electric Company Common Shares Outstanding at March 18, 1996: 184,062 Eastern Edison Company Common Shares Outstanding at March 18, 1996: 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, 1995, are incorporated by reference into Part II. Portions of the Eastern Utilities Associates Proxy Statement dated March 27, 1996 are incorporated by reference into Part III. EASTERN UTILITIES ASSOCIATES BLACKSTONE VALLEY ELECTRIC COMPANY EASTERN EDISON COMPANY 1995 Annual Report on Form 10-K Table of Contents Table of Contents. . . . . . . . . . . . . . . . . . . . . . . .I GLOSSARY OF DEFINED TERMS. . . . . . . . . . . . . . . . . . . IV Item 1. BUSINESS . . . . . .. . . . . . . . . . . . . . . . . .1 System Overview. . . . . . . . . . . . . . . . . . . . . . . .1 General - Core Electric Business . . . . . . . . . . . . . . .1 Electric Utility Industry Restructuring . . . . . . . . .4 General - EUA Cogenex. . . . . . . . . . . . . . . . . . . . .6 Construction . . . . . . . . . . . . . . . . . . . . . . . . .9 Construction Program - EUA. . . . . . . . . . . . . . . .9 Construction Program - Blackstone . . . . . . . . . . . 10 Construction Program - Eastern Edison . . . . . . . . . 10 Fuel for Generation. . . . . . . . . . . . . . . . . . . . . 10 Nuclear Power Issues . . . . . . . . . . . . . . . . . . . 13 General . . . . . . . . . . . . . . . . . . . . . . . 13 Decommissioning . . . . . . . . . . . . . . . . . . . . 14 Yankee Atomic . . . . . . . . . . . . . . . . . . . . . 14 Maine Yankee . . . . . . . . . . . . . . . . . . . . . 15 Recent NRC Actions . . . . . . . . . . . . . . . . . . 15 Public Utility Regulation. . . . . . . . . . . . . . . . . . 15 Rates . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 FERC Proceedings. . . . . . . . . . . . . . . . . . . . 18 Massachusetts Proceedings . . . . . . . . . . . . . . . 19 Rhode Island Proceedings. . . . . . . . . . . . . . . . 21 Environmental Regulation . . . . . . . . . . . . . . . . . . 23 General . . . . . . . . . . . . . . . . . . . . . . . . 23 Electric and Magnetic Fields. . . . . . . . . . . . . . 24 Water Regulation. . . . . . . . . . . . . . . . . . . . 24 Air Regulation. . . . . . . . . . . . . . . . . . . . . 25 Environmental Regulation of Nuclear Power. . . . . . . . . . 27 Item 2. PROPERTIES . . . . . .. . . . . . . . . . . . . . . . 27 Power Supply . . . . . . . . . . . . . . . . . . . . . . . . 27 Other Property . . . . . . . . . . . . . . . . . . . . . . . 30 Item 3. LEGAL PROCEEDINGS . . . . . . . . . . . . . . . . . . 30 Rate Proceeding . . . . . . . . . . . . . . . . . . . . . . 30 Environmental Proceedings . . . . . . . . . . . . . . . . . 30 EUA WestCoast L.P. . . . . . . . . . . . . . . . . . . . . . 34 Other Proceedings. . . . . . . . . . . . . . . . . . . . . . 34 Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY-HOLDERS. .35 EXECUTIVE OFFICERS OF EASTERN UTILITIES ASSOCIATES . . . . . . 35 PART II Item 5. MARKET FOR EUA'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS . . . . . . . . . . . . . . . . . . . . . . . 36 Item 6. SELECTED FINANCIAL DATA. . . . . . .. . . . . . . . . 36 Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS . . . . . . . . . 37 Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. . . . . 37 Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES. . . . . . . . . 37 PART III Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF REGISTRANTS: Eastern Utilities Associates. . . . . . . . . . . . . . 37 Blackstone and Eastern Edison . . . . . . . . . . . . . 38 Item 11. EXECUTIVE COMPENSATION . . . . . .. . . . . . . . . . 39 Eastern Utilities Associates. . . . . . . . . . . . . . 39 Blackstone and Eastern Edison . . . . . . . . . . . . . 40 Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT. . . . . . . . . . . . . . . . . . . . . . 40 Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS. . . . 40 PART IV Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K . . . . . . . . . . . . . . . . . . . . . . 41 (a)(1) Financial Statements . . . . . . . . . . . . . . 41 (a)(2) Financial Statement Schedules . . . . . . . . . 41 (a)(3) Exhibits (*denotes filed herewith).. . . . . . . 41 (b) Reports on Form 8-K. . . . . . . . . . . . . . . . 54 Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . 55 Reports of Independent Accountants. . . . . . . . . . . . . . . 64 Consent of Independent Accountants . . . . . . . . . . . . . . 66 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 subsidiary 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 Montaup Montaup Electric Company Newport Newport Electric Corporation Registrants EUA, Blackstone and Eastern Edison Retail Subsidiaries Blackstone, Eastern Edison and Newport Non-Affiliated Companies Aquidneck Aquidneck Power Limited Partnership 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 DEP Massachusetts Department of Environmental Protection 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 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 KWH Kilowatthour GLOSSARY OF DEFINED TERMS (Cont'd) Other (continued) 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 is a corporation organized under the laws of the Commonwealth of Massachusetts in 1883, 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 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.) The holding company system of EUA, the Retail Subsidiaries, Montaup, EUA Service, EUA Cogenex, EUA Energy and EUA Ocean State 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 and EUA Ocean State. The Corporate Business is made up of EUA and EUA Service. General - Core Electric Business As of December 31, 1995, the number of regular employees in the core electric and corporate business units was 1,077. Blackstone had 126 regular non-union employees. Eastern Edison and Montaup had 344 regular employees. Labor bargaining unit contracts covering approximately 161 employees of Eastern Edison in the Fall River area and of Montaup, and 67 employees of Newport expire in June 1997, March 1998 and September 1996, respectively. Relations with employees are considered to be satisfactory. 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 voluntary retirement incentive, effective June 1, 1995, was offered to sixty-six professionals of the EUA System. Forty-nine of those eligible, including nine employees of Blackstone and twenty-two employees of Eastern Edison and Montaup, accepted the incentive and retired effective June 1, 1995. 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 731,000. At December 31, 1995, Core Electric Business served approximately 297,000 retail customers. Blackstone serves a territory of about 150 square miles in portions of northern Rhode Island with a population of approximately 206,000. At December 31, 1995, 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 456,000. At December 31, 1995, Eastern Edison served approximately 180,000 retail customers. For 1995, 1994 and 1993, the Core Electric Business accounted for approximately 86%, 87%, and 88%, respectively, of total operating revenues of the EUA System. The remaining balance of operating revenues during these periods were attributable to EUA Cogenex. Montaup supplies the Retail Subsidiaries with nearly 100% of each company's electric requirements. About 51% 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 153 MW Somerset facility located in Somerset, Massachusetts; (ii) Montaup's net entitlement of 257 MW from the 584 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 49% 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 5.94% to 41.67% 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 utilities within the retail territories served by the Retail Subsidiaries at this time. Federal law permits, however, certain federal facilities to by-pass the local utility and purchase power directly from another utility. It is probable that in the future retail competition could be imposed by legislative or regulatory action at the federal or state level. (See "Electric Utility Industry Restructuring" below). At the wholesale level, Montaup faces new sources of competition primarily 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 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 and increased FERC's power to order transmission access, resulting in FERC's 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). Competition at the wholesale level is likely to increase as a result of the FERC's pending action on its "Mega-NOPR" regarding open access to transmission and recovery of stranded costs. Two dockets, being considered jointly, were initiated by the FERC with the express purpose of promoting competition in the wholesale electric power industry. A final rule is expected during the first half of 1996, and will affect the EUA System primarily in the requirement to file and implement non-discriminatory open access transmission tariffs. Montaup anticipates filing the required tariffs in advance of the FERC's final rule-making order. Montaup will face increased competition in the wholesale generating 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. Across the country, including the states serviced by EUA's Retail Subsidiaries, there has been an increasing focus on competitive issues. Regulators in Massachusetts and Rhode Island are currently examining, among other things, issues related to incentive regulation and potential electric industry restructuring including retail wheeling (the transmission of power from one utility for sale by that system to retail customers of a different system). The timing and impact of these examinations on the financial condition of the utility industry in general and EUA's utility operations in particular are uncertain at this time. EUA will continue to monitor and participate in all regulatory investigations into the many issues surrounding this move to a competitive marketplace (see "Electric Utility Industry Restructuring" below). 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 a 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 through 1995 to look at its current structure and determine what will be done as the electric utility environment becomes increasingly competitive. Electric Utility Industry Restructuring: The electric industry is in a period of transition from a traditional rate regulated environment to a competitive marketplace. While competition in the wholesale electric market is not new, electric utilities are facing impending competition in the retail sector. In 1995, Eastern Edison, Blackstone and Newport participated with collaborative groups in their respective states consisting of other utilities, industrial users, environmental groups, governmental agencies and consumer advocates in submitting similar sets of interdependent principles with their respective state regulatory commissions addressing electric utility industry restructuring. These filings were intended to be statements of the consensus position by the signatories of the principles that should underlie any electric industry restructuring proposal and include but are not limited to principles addressing stranded cost recovery, unbundling of services and demand side management programs. Each set of principles was submitted on the condition they be approved in full by the respective Commissions. The RIPUC accepted all but one of the principles submitted by the Rhode Island Collaborative with minor modifications to certain language in others and added a new principle which supports negotiation (as opposed to litigation) to resolve conflicts as restructuring moves forward and directed the Rhode Island Collaborative to proceed with negotiations on the issues presented in the principles and to submit a progress report, which was submitted in February 1996. The one principle that was not accepted provided for subsidization of renewable energy sources. (See Rates, "Rhode Island Proceedings" for further discussion). In February 1996 a bill was introduced in the Rhode Island legislature that, if enacted, would allow customer choice of electricity supplier commencing January 1, 1998 for large industrial customers and phasing in all customers by January 1, 2001. The proposed legislation also provides for recovery of "stranded investments" through a transition charge initially set at three cents per KWH. EUA believes that development of the proposed legislation should have been conducted in a public forum so that all interested stakeholders could have participated. EUA believes that competition, if done right, can benefit customers; however, there are substantial issues about the proposed legislation which EUA is currently reviewing. The MDPU issued an order enumerating principles, similar to those submitted by the Massachusetts Collaborative, that describe the key characteristics of a restructured electric industry and provides for, among other things, customer choice of electric service providers, services, pricing options and payment terms, an opportunity for customers to share in the benefits of increased competition, full and fair competition in the generation markets and incentive regulation for distribution services where competition cannot exist. This order sets out principles for the transition from a regulated to a competitive industry structure and identifies conditions for the transition process which will require investor-owned utilities to unbundle rates, provide consumers with accurate price signals and allow customers choice of generation services. The order also provides for the principle of recovery of net, non-mitigable stranded costs by investor-owned utilities resulting from the industry restructuring. Each Massachusetts investor-owned utility is required to file restructuring proposals for moving from the current regulated industry structure to a competitive generation market. The schedule for the filing requirement is staggered. The initial group of utilities was required to file their proposals in February 1996. The second group is required to file within three months of the MDPU's orders on the first group of submissions. Eastern Edison Company filed its proposal, "Choice and Competition" (see below) with the first group of proposals and is awaiting MDPU review. (See Rates, "Massachusetts Proceedings" for further discussion). In January 1996, EUA unveiled its preliminary proposal for a restructured electric utility industry called "Choice and Competition" and began discussions with the Rhode Island and Massachusetts Collaboratives. The plan proposes, among other things: choice of power supplier by all customers as early as January 1998; open access transmission services; performance based rates for electric distribution services; all utility generation competing for power sales and; a transition charge allowing regional utilities the opportunity to recover, among other things, the costs of past commitments to nuclear and independent power. The company believes the plan, which requires participation by all New England parties, satisfies the principles adopted in both Rhode Island and Massachusetts, and provides a fair and equitable transition to a competitive electric utility marketplace for all parties. 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. 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 such as "Choice and Competition" could ultimately cause EUA's 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. 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, effective for fiscal year 1996. 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; therefore EUA Cogenex assesses the financial and technical risk of each customer and project. 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 is paid by the utility based on the reduction in the demand on the utility's system and may also receive a portion of the customers' savings by entering into energy services agreements of the type described above with those customers. 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. EUA Cogenex also operates a lighting services division, EUA Nova, and a controls division, EUA Day. 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 other mid-western states. Also in 1995, EUA Cogenex announced joint ventures with affiliates of the Allegheny Power System and Western Resources, Inc. to provide energy services in and around the geographic regions served by those companies. In early 1996, EUA Cogenex announced a proposed joint venture with Monenco-Agra of Canada to provide similar services in Canada. There are no seasonal factors that impact normal business operations of EUA Cogenex. As a result of its ownership by EUA, a registered holding company under the 1935 Act, EUA Cogenex is regulated by the SEC in matters related to financing and asset acquisitions. On February 15, 1995, the SEC issued an order lifting its previous requirement that EUA Cogenex earn more than 50% of its revenues in the New England/New York area. There are no current geographic restrictions on EUA Cogenex operations. At December 31, 1995, EUA Cogenex employed 253 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 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. Termination of any such DSM programs by one or more electric utilities in which EUA Cogenex participates could result in a reduction of EUA Cogenex's revenues. As of December 31, 1995, EUA Cogenex participated in six 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, 1995 1994 1993 (Thousands) Operating Revenues $ 79,499 $ 74,480 $ 66,912 Pre-tax Income $(13,885)(1) $ 7,266 $ 5,864 Net Earnings $ (7,904)(1) $ 4,171 $ 3,536 Total Assets $199,115 $ 211,310 $ 191,432 (1) 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, 1995 (Exhibit 13-1.03 filed herewith). Construction Construction Program - EUA: The EUA System's cash construction expenditures for the year ended December 31, 1995 were approximately $77.9 million. Planned cash construction expenditures for 1996, 1997 and 1998, as set forth below, are estimated to total $269.3 million. EUA SYSTEM CONSTRUCTION PROGRAM (Dollars in Thousands) 1996 1997 1998 3-Yr. Total Generation $ 20,443 $ 16,307 $ 9,128 $ 45,878 Transmission 1,240 942 1,016 3,198 Distribution 17,063 17,446 18,045 52,554 General (41) 1,071 1,106 2,136 Total Utility Construction Requirements 38,705 35,766 29,295 103,766 EUA Cogenex Capital Requirements 42,885 58,324 64,320 165,529 Total $ 81,590 $ 94,090 $ 93,615 $ 269,295 Construction Program - Blackstone: Blackstone's cash construction expenditures for the year ended December 31, 1995 were approximately $5.1 million, related primarily to its electric distribution system. Planned cash construction expenditures for 1996, 1997 and 1998, as set forth below, are estimated to total $13.5 million. BLACKSTONE CONSTRUCTION PROGRAM (Dollars in Thousands) 1996 1997 1998 3-Yr. Total Transmission $ 313 $ 368 $ 379 $ 1,060 Distribution 3,968 3,939 4,069 11,976 General 53 183 189 425 Total $ 4,334 $ 4,490 $4,637 $ 13,461 Construction Program - Eastern Edison: Eastern Edison's cash construction expenditures for the year ended December 31, 1995 were approximately $23.4 million. Cash construction expenditures of Eastern Edison and Montaup for 1996, 1997 and 1998 as set forth below, are estimated to total $78.8 million.
EASTERN EDISON CONSTRUCTION PROGRAM (Dollars in Thousands) 1996 1997 1998 3-Yr. Total Eastern Eastern Eastern Eastern Edison Montaup Edison Montaup Edison Montaup Edison Montaup Combined Generation $ $20,432 $ $16,254 $ $ 9,073 $ $45,759 $ 45,759 Transmission 290 366 174 159 180 209 644 734 1,378 Distribution 10,191 10,614 10,999 31,804 31,804 General 40 (580) 213 221 474 (580) (106) Total $10,521 $20,218 $ 11,001 $16,413 $11,400 $ 9,282 $32,922 $45,913 $ 78,835
Fuel for Generation The Retail Subsidiaries rely primarily on power purchased from Montaup to meet their electric energy requirements. 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 from time to time 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 1995, the EUA System's sources of energy, by fuel type, were as follows: 28% nuclear, 27% gas, 25% oil, 15% coal and 5% other. During 1995, Montaup had an average inventory of 63,544 tons of coal for its steam generating unit at the Somerset Station, the equivalent of 77 days' supply (based on average daily output at 80% capacity factor for the unit (see Item 2. PROPERTIES -- Power Supply)). The cost of coal averaged about $50.18 per ton in 1995 which is equivalent to oil at $12.16 per barrel. This was slightly more expensive than 1994 because 1995's value was measured on a dry weight basis and because it included a larger amount of compliant coal required for Massachusetts Clean Air Act testing and compliance. Montaup also maintained an average inventory of Nos. 2 and 6 oil of 6,690 barrels and 74,713 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 $21.97 per barrel and $15.98 per barrel in 1995, respectively. Montaup also maintained an average inventory of jet oil of 4,639 barrels at an average cost per barrel of $24.24 during 1995 for its two peaking units at the Somerset Station. Montaup has a one year purchase order effective through December, 1996 with a coal producer. Barge and rail agreements for coal transportation are also in place through 1996. The 1995 year-end coal inventory of approximately 102,285 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 June 30, 1996 with a unilateral option of extending it through December 1996. The current contracts permit up to 20% of fuel oil purchases in the spot market. Fuel prices are based on oil market posting at the time of delivery. For 1995, the cost of oil per barrel at Canal averaged $16.16. Canal and Montaup have entered into agreements with Algonquin Gas Transmission Company (Algonquin) for Algonquin to provide gas transmission facilities and services to the Canal facilities. Algonquin has finished the construction of the pipeline which will connect its existing system with the pipeline built by Canal and Montaup. Canal and Montaup have successfully placed a pipeline under the Cape Cod Canal which will bring gas to Canal Unit No. 2. Boiler modifications which will enable the unit to burn gas will begin in March, 1996 and are expected to be completed by the beginning of July, 1996. Gas will be burned at Canal along with No. 6 oil as the prices of each fuel dictate. In the future it is expected that gas supplies will be available in an interruptible basis from mid-March until mid-November. Montaup's costs of fossil and nuclear fuels for the years 1993 through 1995, together with the weighted average cost of all fuels, are set forth below: Mills* per KWH 1995 1994 1993 Nuclear . . . . . . . . . 6.3 6.1 7.5 Gas . . . . . . . . 14.3 14.1 15.1 Coal . . . . . . . . . 20.3 20.9 24.1 Oil . . . . . . . . . 30.2 27.1 25.5 All fuels . . . . . . . . . 16.7 14.5 15.5 *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 1995 averaged $1.11 per MBTU or approximately 9.4 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 Unit 3 and a 2.9% interest in Seabrook Unit 1. Northeast Utilities, the operator of the units, indicates that Millstone Unit 3 has sufficient on-site storage facilities which, with rack additions, can accommodate its spent fuel for the projected life of the unit. At the Seabrook Project, there is on-site storage capacity which, with rack additions, will be sufficient to at least the year 2011. The Energy Policy Act 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. 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 completely decontaminated of any residual radioactivity. The cost of such decommissioning, depending on the circumstances, could substantially exceed the owners' investment at the time of cancellation. 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 (see "Yankee Atomic," below). 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. Joint owners of nuclear projects are also 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. On February 28, 1991, EUA Power (now known as Great Bay Power Corporation), a 12.1% owner of the Seabrook Project and a former subsidiary of EUA, filed for protection under Chapter 11 of the Federal Bankruptcy Code. It conducted its business as a Debtor-in-Possession until November 23, 1994, at which time its Plan of Reorganization became effective and Great Bay Power emerged from Chapter 11. Decommissioning: Each of the three operating nuclear generating companies in which Montaup has an equity ownership interest (see Item 2. PROPERTIES -- Power Supply) has developed its estimate of the cost of decommissioning its unit and has 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, below). Montaup is recovering through rates its share of estimated decommissioning costs for Millstone Unit 3 and Seabrook Unit 1. Montaup's share of the current estimate of total costs to decommission Millstone Unit 3 is $19.2 million in 1995 dollars, and Seabrook Unit 1 is $12.5 million in 1995 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, 1995. 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 $10.1 million at December 31, 1995. Maine Yankee: Montaup owns 4% of the Common Stock of Maine Yankee. During the refueling- and-maintenance shutdown of the Maine Yankee Nuclear Generating plant that started in early February of 1995, Maine Yankee, the owner of the plant, detected an increased rate of degradation of the plant's steam generator tubes in excess of the number expected and started evaluating several courses of action. Although testing of all tubes revealed that approximately 40% of the tubes are free of defects, Maine Yankee decided to sleeve all of the tubes as a preventative safety measure. Sleeving involves the inserting of a tube of slightly smaller diameter into the defective tube, the sleeve is welded in place and acts as a new tube. Sleeving is a proven technology and must meet rigorous federal standards of safety and licensing. This sleeving project was completed in December 1995. Montaup's share of the sleeving project costs was approximately $1.6 million and was recovered through rates. In late 1995 technical issues were raised by anonymous allegations of inadequate safety analyses supporting two license amendments to increase the rated thermal power at which the Maine Yankee Plant could operate. The NRC initiated a special technical review of those safety analyses in December, 1995. In January 1996 the NRC issued an order limiting the power output of the Maine Yankee Plant to 90% of its rated maximum pending their review and approval of safety analyses. The Plant is currently operating at the 90% level. EUA cannot predict the ultimate outcome of this review. Recent NRC Actions: On January 29, 1996, the NRC notified Northeast Utilities, the operator of Millstone Unit Nos. 1, 2, and 3 that these units would be placed on the NRC "watch list." The "watch list" includes nuclear units which the NRC believes warrant additional regulatory scrutiny. On March 7, 1996, the NRC required Northeast Utilities to provide, within 30 days, specific information pertaining to Millstone Unit No. 3 and the Connecticut Yankee nuclear unit. The NRC stated that this information must be provided to determine whether or not the licenses for these units should be suspended, modified or revoked. Management cannot predict what, if any, further action the NRC might take. However, any shut-down of theses units would require Montaup to seek other sources of energy and increase its cost of power. 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. 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) with 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 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 General - Core Electric Business, "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, 1995, 62% of EUA's consolidated revenues were subject to the jurisdiction of FERC, 13% to that of the MDPU and 11% to that of the RIPUC. The remaining 14% of consolidated revenues are not subject to jurisdiction of utility commissions. For the twelve months ended December 31, 1995, 82.3% of Eastern Edison's consolidated revenues were subject to the jurisdiction of the FERC and 17.7% 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 (thousands of dollars):
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 - Eastern Edison MDPU - 92-148 14,9276/15/92 8,100 1/12/93 11.50 Rhode Island - Blackstone RIPUC - 2045 - Phase I 2,724 6/26/92 353 1/1/93 - Phase II 353 11/1/93 353 1/1/94 - Phase III 353 11/1/94 353 1/1/95 - Phase IV 152 10/23/95 152 1/1/96 - Newport RIPUC - 2045 - Phase I 1,250 6/26/92 417 1/1/93 - Phase II 417 11/1/93 417 1/1/94 - Phase III 417 11/1/94 417 1/1/95 - Phase IV 179 10/23/95 179 1/1/96 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. Reduced from $16,401,000 as originally filed. Rates approved for consumption of electricity on and after January 1, 1993. 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 the total FAS106 incremental tax deductible amount increased by 14.3% for the next seven years. This annual revenue requirement will be reduced to the 100% level in the year after the tenth year of the phase-in.
FERC Proceedings: On December 17, 1992, FERC issued a Statement of Policy regarding the recovery through rates of the cost of post-retirement benefits other than pensions (PBOP), as a result of FAS106 issued to address accounting procedures for these costs. The FERC's policy recognizes allowances for prudently incurred costs of such benefits of company employees when determined on an accrual basis that is consistent with the accounting principles set forth in FAS106. Furthermore, companies must agree to make cash deposits to an irrevocable external trust fund equal to the annual test period allowance for the cost of such benefits and they must maximize the use of income tax deductions for contributions to the trust fund. If tax deductions are not available for some portion of currently funded amounts, deferred income tax accounting must be followed for the tax effects of such transactions. Within three years of their adoption of FAS106, FERC regulated companies must also file a general rate change and seek inclusion of these costs in their rates. Companies may defer the jurisdictional portion of the difference between the costs determined pursuant to accounting principles previously followed and FAS106 accruals from the time they adopt FAS106 until they file the general rate case described above. Montaup deferred its incremental FAS106 expenses of approximately $400,000 and $1.4 million for 1994 and 1993, respectively. On May 21, 1994 Montaup filed a rate application with the 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 have been made and certified by the Commission 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. Montaup has requested that FERC allow the tariffs to become effective on April 21, 1996. Massachusetts Proceedings: In December 1994, the Massachusetts Department of Public Utilities 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 December 31, 1992, the MDPU issued its order in response to a $14.9 million (reduced from the originally filed $16.4 million) rate increase request of Eastern Edison. The $8.1 million rate relief granted represented 49% of Eastern Edison's original rate request filed on June 15, 1992 based on a 1991 test year. The new rates filed in compliance with the order became effective for sales subsequent to January 1, 1993. In authorizing the increase, the MDPU accepted a settlement proposal offered jointly by Eastern Edison and the Massachusetts Attorney General, the sole intervenor. The settlement stipulated the total revenue requirement which included an amortization of Hurricane Bob costs over a five-year period without a return on the unamortized amount. The settlement also reflected the recovery of the full tax deductible amount of post-retirement benefits other than pensions (FAS106 expenses), without any phasing-in of the increase over the previous ("pay-as-you-go") level. All FAS106 amounts recovered were placed in trusts permitted by the IRS to maximize tax deductibility and provide tax-free benefits to retirees. The depreciation rate and the common equity component of AFUDC were also specified. The composite rate for the depreciation calculation was set at 4.13%, up slightly from the 4.07% previously authorized. Solely for the purpose of calculating AFUDC, the common equity return component was set at 11.5%. 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. On September 20, 1994, the MDPU issued a notice of inquiry and order seeking comments on incentive regulation. 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 is specified, the MDPU stated the largest utilities should commence the incentive plan design process as soon as possible. EUA can not predict what effect, if any the MDPU's order will have on the EUA System. (See General - Core Electric Business, "Electric Utility Industry Restructuring" 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 Department 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; (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 Docked #96-24. A public hearing was held on March 6, 1996. EUA can not predict the outcome of this proceeding. 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. The RIPUC also ordered that all amounts recovered be placed in trusts permitted by the IRS which will maximize tax deductibility. In 1995, total FAS106 expenses for Blackstone and Newport, net of capitalized amounts were approximately $1.3 million and $0.8 million, respectively. 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. Discussions between the Navy and Newport electric and several other interested parties have been held in an attempt to reach a settlement. It is too early to tell if a settlement is likely. A second motion to stay was filed by the Navy on December 21, 1995. It is not possible to predict what effect, if any, the Court's decision will have on the EUA system. 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 Division 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 Division as a party, rather than a litigated proceeding before the Division 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. It is not possible to predict the outcome of this proceeding at this time. 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 (including procedures for operation and maintenance) for construction or modification of fossil fuel generating facilities receive prior approval from the DEP 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 Board. 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 and the Rhode Island Coastal Resource Management Council. 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 DEP, 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" (Brownfield's 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 Brownfield's 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 Brownfield's 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. 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. There is a bill pending in the Massachusetts legislature that would authorize the MDPU to examine the potential health effects of EMF. 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 DEP. 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, and the Rhode Island Wetland Act. The EPA, the Army Corps of Engineers, RIDEM, the Rhode Island Coastal Resources Management Council and the DEP are pursuing a non-degradation (no loss) policy for wetlands. Under the Massachusetts Water Management Act, the DEP 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. EPA, United States Coast Guard, RIDEM, and DEP 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, oxides of nitrogen and particulate matter. Montaup's Somerset Station is permitted to burn coal which results in sulfur dioxide 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 sulfur dioxide 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 will 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 sulfur dioxide and oxides of nitrogen. 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 sulfur dioxide emissions. Beginning in the year 2000, the EPA will issue 8.90 million sulfur dioxide allowances to utilities annually. The sulfur allowance program will not affect Montaup's Somerset Station until January 1, 2000. Massachusetts DEP regulations establish a statewide cap on sulfur dioxide emissions and require Montaup's facilities to meet an average emission rate of 1.2 pounds of sulfur dioxide per million BTU of fuel input by the end of 1994. Under federal standards, Montaup would not be required to meet this sulfur dioxide emission level until the year 2000 as a result of Title IV of the Clean Air Act. However, Massachusetts DEP 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 sulfur dioxide standard. Montaup is 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. Oxides of nitrogen are one of the precursors of ozone formation. Title I requires additional controls on industrial sources of oxides of nitrogen 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 oxides of nitrogen 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 DEP 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 oxides of nitrogen. 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 nitrogen oxides. Montaup has initiated compliance through, among other things, selective, noncatalytic reduction processes. 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 by 1995 which will outline limits and conditions necessary to comply with all applicable air requirements. The Clear 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, DEP issued Montaup an Administrative Completeness Determination and Application Shield for its Operating Permit Application. 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. 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. The effective date for the new radionuclide standards has been stayed as to nuclear generating units. 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 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 1995, 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 (Jepson in Jamestown and Eldred 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 through the year 2000. Montaup recovered approximately $12.8 million through rates in 1995 for its C&LM programs. C&LM is designed to (i) decrease existing energy demand and (ii) offset future load growth through conservation incentives, thereby minimizing future need for large capital investment in generating facilities. The all-time peak EUA System demand was approximately 931 MW experienced on July 27, 1995. EUA SYSTEM CAPABILITY GENERATING UNITS IN SERVICE AS OF DECEMBER 31, 1995
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 8.00 8.00 0.00 8.00 1978 ELDRED DIESEL NEWPORT ELECTRIC CORP. 100.00 8.25 8.25 0.00 8.25 SUBTOTAL: 171 0.00 171 JOINT OWNERSHIP: 1976 CANAL 2 NO. 6 OIL CANAL ELECTRIC COMPANY 50.00 584.00 292.00 35.00 257.00 1978 WYMAN 4 (YAR 4) NO. 6 OIL CENTRAL MAINE POWER CO. 2.63 619.25 16.28 0.00 16.28 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 1158.00 33.58 0.00 33.58 SUBTOTAL: 387.79 35.00 352.79 EQUITY OWNERSHIP: 1968 CONN. YANKEE NUCLEAR CONN. YANKEE ATOMIC POWER 4.50 583.20 26.24 0.00 26.24 1972 MAINE YANKEE NUCLEAR MAINE YANKEE ATOMIC POWER 3.59 880.00 31.61 0.00 31.61 1972 VERMONT YANKEE NUCLEAR VT. YANKEE NUCLEAR POWER 2.25 531.00 11.95 0.00 11.95 SUBTOTAL: 69.80 0.00 69.80 PURCHASED POWER: 1968 CANAL 1 NO. 6 OIL CANAL ELECTRIC COMPANY 25.00 557.00 139.25 0.00 139.25 1972 PILGRIM 1 NUCLEAR BOSTON EDISON COMPANY 11.00 668.97 73.59 0.00 73.59 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 13.64 110.00 15.00 0.00 15.00 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 26.27 57.10 15.00 0.00 15.00 1974 BEAR SWAMP GT1 HYDRO NEW ENGLAND POWER 5.94 286.38 17.50 0.00 17.50 1974 BEAR SWAMP GT2 HYDRO NEW ENGLAND POWER 5.94 286.38 17.50 0.00 17.50 1990 OSP 1 GAS OCEAN STATE POWER 28.00 287.00 80.36 0.00 80.36 1991 OSP 2 GAS OCEAN STATE POWER 28.00 281.00 78.68 0.00 78.68 1991 NEA GAS NORTHEAST ENERGY ASSOC. 8.62 333.43 28.74 0.00 28.74 SUBTOTAL: 513.70 0.00 513.70 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) ------------------------------ 1,191.29 LESS: UNIT CONTRACT SALES (MW) --------------------- 35.00 TOTAL NET SYSTEM CAPABILITY (MW) ------------------------------------- 1,156.29 REPRESENTS MONTAUP JOINT OWNERSHIP SHARE OF 1.9618% AND NEWPORT JOINT OWNERSHIP SHARE OF .6666%. "LIFE OF UNIT" PURCHASE CONTRACT. NEWPORT PURCHASED POWER ASSIGNED TO MONTAUP. FOR EACH UNIT, MONTAUP IS A POWER PURCHASER WITH 22% ENTITLEMENT AND A 6% ENTITLEMENT ASSIGNED FROM NEWPORT. (EUA OCEAN STATE HOLDS A 29.9% EQUITY INTEREST IN OCEAN STATE POWER PARTNERSHIP.) ENTITLEMENT % IS WEIGHTED AVERAGE OF PHASE I & II SHARES (40% PHASE I (4.01987%); 60% PHASE II (4.0842%)).
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 "Yankee Atomic" and "Maine Yankee.") 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 1995 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 1995 Annual Report (Exhibit 13-1.08 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, 1995, (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 DEP, 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 in the near future. 2. On July 14, 1987, the Commonwealth of Massachusetts (the Commonwealth) on behalf of the DEP 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 DEP 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 DEP regarding the Mendon Road site and another alleged coal gasification site discovered by the DEP 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 DEP for review and approval, but Blackstone has not received a response or DEP authorization to proceed with further studies or remedial action. On May 26, 1993, the DEP requested Blackstone to submit additional Phase I testing for the Mendon Road site which was completed and sent to the DEP on December 20, 1993. Meanwhile, Blackstone has contested the DEP'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 DEP'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 DEP 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 DEP 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 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 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. 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. 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. Blackstone has notified certain liability insurers and has filed claims with respect to the Mendon Road site. Blackstone reached final settlement with one such insurer for coverage of legal costs related to this proceeding and in January 1996 received payment of approximately $1.2 million. Blackstone is actively pursuing coverage from other carriers. 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 cyanide-contaminated 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. The EPA is planning to review the site to determine whether a further investigation and a hazard ranking should be performed. As previously discussed in item 2 above, on January 28, 1994, Blackstone filed a complaint (previously mentioned in paragraph 2) in the District Court seeking, inter alia, a declaratory judgment that Stone & Webster and Valley are responsible for owning and/or operating the Tidewater Plant and disposing and/or arranging for the disposal of coal gasification wastes at the Tidewater Plant site. 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. Blackstone and Valley have entered into an agreement to share the expenses of conducting the study and/or retaining an environmental energy firm to conduct a Phase II site study. 4. Montaup and EUA Service received a Notice of Responsibility on July 27, 1987, from the DEP for suspected hazardous material at a site owned by Montaup on Hortonville Road in Swansea, Massachusetts. EUA Service has contracted for and received an environmental site assessment for the property identifying the previous property owner as the party likely responsible for the deposit of suspected hazardous waste materials on the site. This assessment has been submitted to the DEP, identifying the previous property owner. Under the new Massachusetts Contingency Plan regulations, Montaup must take the initiative to complete investigative and remedial actions by August 1997. A site investigation was initiated in September 1995 as the first step in this process. 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 DEP that it had encountered oils and PCBs. On May 3, 1990, the DEP 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 DEP 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 DEP reclassifying the site from a Tier IA site to a Tier IB site was signed by Eastern Edison and submitted to DEP. That reclassification enables the site to be investigated and cleaned up under the guidance of a licensed site professional without DEP approval for each action taken. Cleanup activities were nearly completed at the site in 1995. The removal of storage tanks and excavation of PCB "hot spots" was accomplished. Backfilling and paving to cap areas of residual soil contamination are expected to commence in the spring of 1996. The total estimated cost of the cleanup including amounts already incurred, is anticipated to be approximately $550,000. 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 carrier 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, 1995, the EUA System has incurred costs of approximately $4.6 million (excluding the Mendon Road judgment) in connection with the foregoing environmental matters, substantially all of which relate to Blackstone. EUA estimates that additional expenditures (excluding the Mendon Road judgment) may be incurred through 1997 of up to $3.0 million of which approximately $2.5 and $0.5 million relate to Blackstone and Eastern Edison, respectively. 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 1997 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. EUA Cogenex, through its EUA WestCoast (WestCoast) L.P., had under development a cogeneration facility of approximately 1.5 MW. The cogeneration facility experienced numerous start-up delays and cost overruns. The host of the facility has taken the position that the energy services agreement between WestCoast and itself is terminated due to, among other things, failure to complete the project. WestCoast disagrees with the host's right to terminate, but has decided not to contest the host's purported termination. In June 1993, WestCoast filed a lawsuit against the contractors responsible for the design and construction of the facility, as well as the surety which issued a performance bond guaranteeing construction. Certain defendants in that action have filed cross-complaints against WestCoast and EUA Cogenex, seeking, among other things, approximately $300,000 for payments withheld by 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 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. EUA WestCoast has secured defense from insurance carriers for the claims made by the host. EUA Cogenex intends to vigorously prosecute its claims against the contractors, surety and host, and defend itself against any cross-complaints. EUA Cogenex cannot predict the ultimate resolution of this matter. As a result of EUA Cogenex's decision to discontinue cogeneration operations effective as of July 1, 1995, EUA Cogenex has recorded a reserve for its total investment in this project which is included in the one-time after-tax charge to earnings of approximately $10.5 million. Other Proceedings In December 1992, Montaup commenced a declaratory judgment action in which it sought to have the Massachusetts Superior Court determine its rights under the Power Purchase Agreement between it and Aquidneck Power Limited Partnership. In April 1995 Montaup filed a motion for summary judgement and in June 1995 the court granted Montaup's motion. In July, Aquidneck filed for appeal of the court's decision. Montaup, EUA and EUA Service intend to vigorously contest the appeal and continue to believe that Aquidneck's claims have no basis in law. On June 30, 1987, the MDPU commenced a proceeding for the purpose of investigating Eastern Edison's power planning process after rejecting a proposed Purchased Capacity Adjustment Clause. One of the purposes of this proceeding is to investigate the prudency of Eastern Edison's all-requirements contract with Montaup. No procedural dates have been set nor has any other activity occurred in this docket. EUA cannot predict the 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 18, 1996, are listed below along with their business experience during the past five years. Officers are elected annually by the Trustees at the meeting of Trustees next following the annual meeting of shareholders. The 1996 Annual Meeting of Shareholders is scheduled to be held on May 20, 1996. 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, 58 Comptroller since 1976, Assistant Secretary since Comptroller 1978, and Assistant Treasurer since April 1986. Chief Accounting Officer of EUA. John D. Carney, 51 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., 48 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, 55 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, 48 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, 55 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. Except as described below, 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. On February 28, 1991, EUA Power (now Great Bay Power), filed a voluntary petition with the United States Bankruptcy Court for the District of New Hampshire for protection under Chapter 11 of the Federal Bankruptcy Code. EUA Power, a wholly owned subsidiary of EUA prior to February 5, 1993, the date it redeemed all of its equity securities held by EUA, was organized solely for the purpose of acquiring an interest in the Seabrook Project and selling in the wholesale market its share of electricity generated by the project. EUA has no ownership interest in Great Bay Power. Messrs. Burns, Hebert, Pardus and Stevens, were officers or directors of EUA Power since its formation in 1986, resigned their positions effective December 30, 1992, with the exception of Mr. Stevens who resigned as the sole officer and director of Great Bay Power on November 22, 1994. 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, 1995 (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 1995 Annual Reports (Exhibit 13- 1.01 and 13-1.08, respectively, filed herewith). As of February 1, 1996 there were 12,161 EUA common shareholders of record. The closing price of EUA's Common Shares as reported by the Wall Street Journal on March 18, 1996 was $21.125. Item 6. SELECTED FINANCIAL DATA The information set forth under the caption "SELECTED CONSOLIDATED FINANCIAL DATA" included in EUA's Annual Report to Shareholders for the year ended December 31, 1995, (Exhibit 13-1.03 filed herewith) and the information set forth under the caption "SELECTED FINANCIAL DATA" included in the Annual Reports for the year ended December 31, 1995 for Blackstone and Eastern Edison (Exhibits 13-1.01 and 13-1.08, respectively, 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 9 through 20 in the 1995 EUA Annual Report to Shareholders, pages 3 through 8 in the 1995 Blackstone Annual Report and pages 3 through 9 in the 1995 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 22 through 37 in the 1995 EUA Annual Report to Shareholders, page 2 and pages 10 through 27 in the 1995 Blackstone Annual Report and, page 2 and pages 12 through 31 in the 1995 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 20, 1996, 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 18, 1996 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, 58* Vice President, Assistant Treasurer and Assistant Vice President Clerk/Assistant Secretary of Blackstone and Eastern Edison since April 1986. John D. Carney, 51* President and Director of Blackstone since April Director and President 1995; President and Director of Eastern Edison since January 1990. David H. Gulvin, 61 Senior Vice President of Blackstone and Eastern Senior Vice President Edison since April 1995; President of Blackstone 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, 46 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., 48* Treasurer since April 1986 and Secretary/Clerk Treasurer and since April 1995 of both Blackstone Secretary/Clerk and Eastern Edison. Michael J. Hirsh, 41 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, 45 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, 55* 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, 48* Executive Vice President and Director since March Director and Executive 1992 of both Blackstone and Eastern Edison. Vice President John R. Stevens, 55* 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 20, 1996 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 27, 1996, 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 Title of Class Beneficial Owner Beneficial Ownership of 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 20, 1996 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, 1995 (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, 1995. Blackstone Schedule II - Valuation and Qualifying Accounts for the three years ended December 31, 1995. (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 (Exhibit 10-4, Form 10-K of EUA for 1992, 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. 10-15.03* - Eastern Utilities Associates Employees' Savings Plan as amended and restated effective January 1, 1989 (including amendments through January 1, 1992). 10-16.03* - First Amendment to the Employees' Retirement Plan of Eastern Utilities Associates and Its Affiliated Companies dated December 21, 1994. 10-17.03* - First Amendment to Eastern Utilities Associates Employees' Savings Plan and Its Affiliated Companies dated December 21, 1994. - 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 18, 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 and October 1, 1990, (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). 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 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 - Guarantee Agreement dated as of November 5, 1981 between Bankers Trust Company, as Trustee of the Vernon Energy Trust, and Montaup relating to a nuclear fuel sales agreement and related transactions entered into by Vermont Yankee Nuclear Power Corporation (Exhibit 10-63, Form 10-K of EUA for 1981, File No. 1-5366). 10-25.05 - 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). 10-26.05 - 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). 10-27.05 - 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). 10-28.05 - 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). 10-29.05 - 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). 10-30.05 - 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). 10-31.05 - 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). 10-32.05 - 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). 10-33.05 - 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). 10-34.05 - 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). 10-35.05 - 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). 10-36.05 - 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). 10-37.05 - 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). *10-38.05 - Twenty-eighth Amendment to 10-14.05 dated September 15, 1992. *10-39.05 - Twenty-ninth Amendment to 10-14.05 dated May 1, 1993. *10-40.05 - Thirty-second Amendment to 10-14.05 dated September 1, 1995. - 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 1995, 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 1995, 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 1995, 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) and Newport Electric Corporation (Rhode Island). 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. None. 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 18, 1996 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 R. 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) /s/Russell A. Boss Trustee Russell A. Boss /s/Paul J. Choquette, Jr. Trustee Paul J. Choquette, Jr. March 18, 1996 /s/Peter S. Damon Trustee Peter S. Damon /s/Peter B. Freeman Trustee Peter B. Freeman /s/Larry A. Leibenow Trustee Larry A. Liebenow Trustee Jacek Makowski /s/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 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 18, 1996 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 18, 1996 /s/Robert G. Powderly Executive Vice President and Robert G. Powderly Director 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 18, 1996 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 (Principal Donald G. Pardus Executive Officer) /s/John R. Stevens Vice Chairman and Director John R. Stevens (Principal Financial Officer) /s/Richard M. Burns Vice President March 18, 1996 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 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, 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 For the Year Ended December 31, 1993: Allowance for Doubtful Accounts $603 $1,029 $255 $1,274 $613 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 Deduction End of Description of Period Expenses Accounts Describe Period 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 For the Year Ended December 31, 1993: Allowance for Doubtful Accounts $315 $650 $205 $1,012 $158 Recoveries of accounts previously written off. Principally Accounts Receivable written off. 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 36 of the 1995 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. Coopers & Lybrand L.L.P. Boston, Massachusetts March 5, 1996 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 1995 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. Coopers & Lybrand L.L.P. Boston, Massachusetts March 5, 1996 [This page left blank intentionally]
EX-10 2 EXHIBIT 10-14.03 EMPLOYEES' RETIREMENT PLAN OF EASTERN UTILITIES ASSOCIATES AND ITS AFFILIATED COMPANIES(1) Amended and Restated Effective January 1, 1989 Execution Copy December, 1994 (1) Prior to January 1, 1991 this Plan was known as the Employees' Retirement Plan of Eastern Utilities Associates and Its Subsidiary Companies. TABLE OF CONTENTS PREAMBLE Section ARTICLE I DEFINITIONS "Accrued Benefit" 1.1 "Active Participant" 1.2 "Actuarial Equivalent" 1.3 "Actuary" 1.4 "Affiliated Employer" 1.5 "Annuity Starting Date" 1.6 "Authorized Leave of Absence" 1.7 "Average Earnings" 1.8 "Beneficiary" 1.9 "Board" 1.10 "Code" 1.11 "Contingent Annuitant" 1.12 "Credited Service" or "Years of Credited Service" 1.13 "Early Retirement Date" 1.14 "Earnings" 1.15 "Effective Date" 1.16 "Employee" 1.17 "Employer" 1.18 "Employment Date" 1.19 "ERISA" 1.20 "Fiduciary" 1.21 "Fund", "Trust" or "Trust Fund" 1.22 "Group Annuity Contract" 1.23 "Hour of Service" 1.24 "Inactive Participant" 1.25 "Normal Form" 1.26 "Normal Retirement Age" 1.27 "Normal Retirement Date" 1.28 "One Year Break in Service" 1.29 "Parental Absence" 1.30 "Participant" 1.31 "Participating Employer" 1.32 "Plan" 1.33 "Plan Year" 1.34 "Postponed Retirement Date" 1.35 "Prior Participant Account" 1.36 "Reemployment Date" 1.37 "Retired Participant" 1.38 "Retirement Annuity" 1.39 "Retirement Benefit" 1.40 "Retirement Board" 1.41 "Service Termination Date" 1.42 "Social Security Benefit" 1.43 "Spouse" 1.44 "Trust" 1.45 "Trustee" 1.46 "Year of Eligibility Service" 1.47 "Year of Vesting Service" 1.48 ARTICLE II SERVICE AND PARTICIPATION Eligibility Requirements 2.1 Years of Service 2.2 Years of Credited Service 2.3 Postponed Retirement or Reemployment After Benefits Commence 2.4 Suspension of Benefits 2.5 Service With a Former Employer 2.6 Service With Newport Electric Corporation 2.7 Transfers 2.8 ARTICLE III NORMAL RETIREMENT BENEFIT Normal Retirement Benefit 3.1 Minimum Accrued Benefit 3.2 Maximum Benefit 3.3 Continuing Employment 3.4 ARTICLE IV EARLY RETIREMENT DATE AND EARLY RETIREMENT BENEFIT Early Retirement Date 4.1 Early Retirement Benefit 4.2 Minimum Benefit 4.3 ARTICLE V POSTPONED RETIREMENT DATE AND POSTPONED RETIREMENT BENEFIT Postponed Retirement Date 5.1 Postponed Retirement Benefit 5.2 Death Prior to Postponed Retirement Date 5.3 Death Following Commencement of Retirement Benefit 5.4 ARTICLE VI TERMINATION OF EMPLOYMENT Non-Vested Termination 6.1 Vested Termination 6.2 Early Payment 6.3 Prior Participant Account 6.4 ARTICLE VII DEATH BENEFITS Surviving Spouse Benefit For Death Occurring On or After Early Retirement Date 7.1 Pre-Retirement Surviving Spouse Benefit For Death of Active or Inactive Participant Occurring Before Age 55 7.2 Death Benefits After Retirement Benefits Have Commenced 7.3 ARTICLE VIII PAYMENT OF RETIREMENT BENEFITS Automatic Payment Forms 8.1 Election of Optional Forms 8.2 Joint and Survivor Option 8.3 Life Annuity Option 8.4 General Provisions 8.5 Involuntary Cash-Out Provision 8.6 Restrictions on Distributions 8.7 Increased Payments With Respect to Certain Retired Members 8.8 ARTICLE IX RETIREMENT BOARD Responsibility for Plan and Trust Administration 9.1 Retirement Board 9.2 Agents of the Retirement Board 9.3 Retirement Board Procedures 9.4 Administrative Powers of the Retirement Board 9.5 Benefit Claims Procedures 9.6 Certification of Benefits 9.7 Designation of Actuary 9.8 Reliance on Reports and Certificates 9.9 Other Retirement Board Powers and Duties 9.10 Compensation of Retirement Board 9.11 Member's Own Participation 9.12 Liability of Retirement Board Members 9.13 Indemnification 9.14 ARTICLE X FUNDING AND CONTRIBUTIONS Establishment of Fund 10.1 Contribution to the Fund; Plan Expenses 10.2 Contributions Conditional 10.3 Employee Contributions 10.4 ARTICLE XI FIDUCIARY RESPONSIBILITIES Basic Responsibilities 11.1 Actions of Fiduciaries 11.2 Fiduciary Liability 11.3 ARTICLE XII AMENDMENT AND TERMINATION Right to Amend or Terminate 12.1 Partial Termination 12.2 Vesting and Distribution of Funds Upon Termination 12.3 Determination of Funds Upon Termination 12.4 Restriction on Benefits 12.5 Right to Accrued Benefits 12.6 ARTICLE XIII GENERAL PROVISIONS Plan Voluntary 13.1 Payments to Minors and Incompetents 13.2 Non-Alienation of Benefits 13.3 Evidence of Survival 13.4 Use of Masculine and Feminine; Singular and Plural 13.5 Merger, Consolidation, or Transfer 13.6 Leased Employees 13.7 Construction of Agreement 13.8 ARTICLE XIV TOP HEAVY PROVISIONS General Rule 14.1 Vesting Provisions 14.2 Minimum Benefit Provisions 14.3 Limitation on Benefits 14.4 Top-heavy Plan Definition 14.5 Key Employee 14.6 Non-Key Employee 14.7 ADDENDUM PREAMBLE Effective January 1, 1957, Eastern Utilities Associates (the "Employer") established a defined benefit retirement plan referred to as the Employees' Retirement Plan of Eastern Utilities Associates and Its Subsidiary Companies (the "Plan"). The Plan has been amended from time to time thereafter and is now being amended and restated effective January 1, 1989. The Plan is intended to provide Eligible Employees with periodic income after retirement. A Trust Agreement (the "Trust") has been adopted by the Employer and forms a part of this Plan. Effective December 31, 1990, this Plan was merged into the Newport Electric Corporation Pension Plan, the merged plan being known as the Employees' Retirement Plan of Eastern Utilities Associates and Its Affiliated Companies. The provisions of the Plan, including the Addendum attached hereto, shall govern the participation of Employees of both Eastern Utilities Associates and Newport Electric Corporation. It is intended that the Plan, as amended and restated herein, will continue to meet the requirements for qualification under Section 401(a) of the Internal Revenue Code of 1986 (the "Code") as amended from time to time and that the Trust shall continue to be exempt from taxation as provided under Code Section 501(a). As such, the Plan contains provisions required by the Tax Reform Act of 1986 and other pertinent laws and regulations. Except as otherwise specifically and expressly provided herein: (a) the provisions of this Plan shall apply only to individuals who are Eligible Employees after December 31, 1988; (b) a former Employee's eligibility for and amount of benefits, if any, payable to or on behalf of such former Employee, shall be determined in accordance with the provisions of the Plan in effect when his employment terminated. The benefit payable to or on behalf of a Participant included under the Plan in accordance with the following provisions shall not be affected by the terms of any amendment to the Plan adopted after such Participant's employment terminates, unless the amendment expressly provides otherwise. ARTICLE I DEFINITIONS The following words and phrases when used in the Plan shall have the meanings indicated in this Article I unless a different meaning is plainly required by the context: 1.1 "Accrued Benefit" shall mean the amount of monthly Retirement Benefit determined under Article III payable in the Normal Form beginning at a Participant's Normal Retirement Date or, if applicable, beginning on his Postponed Retirement Date and determined in accordance with Article V. The Accrued Benefit shall not be less than the minimum amount determined under Section 3.2. 1.2 "Active Participant" shall mean an Eligible Employee who has become covered under the Plan under Section 2.1(a) or (c). 1.3 "Actuarial Equivalent" shall mean a benefit of equivalent value to another benefit, determined on the following bases and subject to the factors set forth in Appendix A: (a) for lump sum payments made pursuant to Section 6.4 or 8.6, the applicable mortality rate under the UP 1984 Mortality Table and the interest rate, either immediate or deferred, which would be used by the Pension Benefit Guaranty Corporation for purposes of determining the present value of a benefit on plan termination and which is in effect on the first day of the Plan Year in which the distribution takes place; (b) for all other purposes: (i) Mortality: 1971 TPF&C Forecast Mortality with a six-year age setback (ii)Interest: 8% annual 1.4 "Actuary" shall mean an actuary who meets the standards and qualifications established by the Joint Board for the Enrollment of Actuaries, or an actuarial firm that employs such individuals, as selected by the Retirement Board from time to time. 1.5 "Affiliated Employer" shall mean any corporation which is a member of a controlled group of corporations (as defined in Code Section 414(b)) which includes the Employer; any trade or business (whether or not incorporated) which is under common control (as defined in Code Section 414(c)) with the Employer; any organization (whether or not incorporated) which is a member of an affiliated service group (as defined in Code Section 414(m)) which includes the Employer; and any other entity required to be aggregated with the Employer pursuant to regulations under Code Section 414(o). 1.6 "Annuity Starting Date" shall mean the first day of the first period for which a benefit is payable to the Participant (or to the Spouse in the case of death before Retirement Benefits commence) under the Plan. 1.7 "Authorized Leave of Absence" shall mean any absence authorized by an Employer under the Employer's standard personnel practices, provided that all persons under similar circumstances are treated alike in the granting of such Authorized Leave of Absence, and provided further that the Participant returns or retires within the period specified in the Authorized Leave of Absence. An absence due to service in the Armed Forces of the United States shall be considered an Authorized Leave of Absence provided that the Employee complies with all of the requirements of federal law in order to be entitled to reemployment and provided further that the Employee returns to employment with the Employer or an Affiliated Employer within the period provided by such law. 1.8 "Average Earnings" shall mean, on any date of determination, the average of a Participant's Earnings for the 60 (48 effective July 1, 1992) consecutive calendar months of employment in the 120-month period ending on the date of determination for which his aggregate Earnings were the highest. In the case of a Participant who has not received Earnings for 60 (48 effective July 1, 1992) consecutive calendar months of employment in the aforementioned 120-month period, Average Earnings means the average of his Earnings during all of his months of employment during such 120-month period, not to exceed a total of 60 (48 effective July 1, 1992) months. Notwithstanding the foregoing, a Participant's Accrued Benefit shall be determined on the basis of Average Earnings as calculated in (a) or (b) below, whichever results in the greater benefit: (a) The Accrued Benefit shall be determined on the basis of a Participant's Average Earnings, as limited pursuant to Section 1.15, as of his termination of employment; or (b) The Accrued Benefit shall be equal to (i) plus (ii) below where: (i) is the Participant's Accrued Benefit determined as of December 31, 1988, without regard to the Earnings limitation set forth in Section 1.15; and (ii) is the Participant's Accrued Benefit for periods of service after December 31, 1988, with his Earnings for such periods subject to the limitations set forth in Section 1.15. 1.9 "Beneficiary" shall mean the individual designated by a Participant to receive payments upon the death of the Participant prior to his retirement, subject to the spousal consent requirements set forth in Section 8.5(c). Death benefits which become payable under Article VII before Retirement Benefits may only be paid to a Participant's Spouse. 1.10 "Board" shall mean the Board of Trustees of Eastern Utilities Associates. 1.11 "Code" shall mean the Internal Revenue Code of 1986, as amended from time to time and any regulations issued thereunder. Reference to any Code Section shall include any successor provision thereto. 1.12 "Contingent Annuitant" shall mean the person designated by the Participant to receive lifetime monthly benefit payments in the event of the Participant's death after Retirement Benefits have started as provided under the joint and survivor payment forms in Section 8.3. If the Participant is married on the date Retirement Benefits are to commence, the Contingent Annuitant is his Spouse, unless a waiver meeting the requirements of Section 8.5(c) provides for the designation of a Contingent Annuitant who is not the Spouse. 1.13 "Credited Service" or "Years of Credited Service" shall mean the Participant's period of service determined in accordance with Article II. 1.14 "Early Retirement Date" shall mean the date on which a Participant becomes eligible to retire with an early retirement benefit under the Plan, as determined in accordance with Article IV. 1.15 "Earnings" shall mean with respect to any Plan Year the regular basic remuneration paid to the Employee by the Employer for services rendered plus any pre-tax contributions made at the Participant's election to a qualified cash or deferred arrangement as defined in Code Section 401(k) or a cafeteria plan as defined in Code Section 125 sponsored by the Employer or a Participating Employer. Earnings shall exclude any pay for overtime and any bonuses or special pay, or the Employer's cost for any public or private employee benefit plan including this Plan. Effective for Plan Years commencing after December 31, 1988, Earnings shall not include any amount in excess of $200,000, or such higher amount ($150,000 for Plan Years beginning on or after January 1, 1994) as permitted under Code Section 401(a)(17) and regulations thereunder. In determining the Earnings of an Employee for purposes of the Code Section 401(a)(17) limitation, the rules of Code Section 414(q) shall apply; provided, however, that in applying such rules the term "family" shall include only the Spouse of the Employee and any lineal descendants of the Employee who have not attained age 19 before the close of the Plan Year. If the Earnings of the Employee exceeds the Code Section 401(a)(17) limitation, then the Code Section 401(a)(17) limitation shall be pro rated among the Earnings of the Employee and his family (as determined under this Section prior to the application of the Code Section 401(a)(17) limitation) in proportion to each such individual's Earnings (as determined under this Section prior to the application of the Code Section 401(a)(17) limitation). 1.16 "Effective Date" shall mean January 1, 1989 for this restatement. The original effective date of the Plan is January 1, 1957. 1.17 "Employee" shall mean a common-law employee of the Employer or an Affiliated Employer. 1.18 "Employer" shall mean Eastern Utilities Associates, a voluntary association formed under a Declaration of Trust dated April 2, 1928, as amended, under the laws of the Commonwealth of Massachusetts, or its successor or successors. 1.19 "Employment Date" shall mean the first day on which an Employee is credited with an Hour of Service. 1.20 "ERISA" shall mean the Employee Retirement Income Security Act of 1974 as amended from time to time. References to any section of ERISA shall include any successor provision thereto. 1.21 "Fiduciary" shall mean any person who exercises any discretionary authority or discretionary control respecting the management of the Plan, assets held under the Plan, or disposition of Plan assets; who renders investment advice for a fee or other compensation, direct or indirect, with respect to assets held under the Plan or has any authority or responsibility to do so; or who has any discretionary authority or discretionary responsibility in the administration of the Plan. Any person who exercises authority or has responsibility of a fiduciary nature as described above shall be considered a Fiduciary under the Plan. 1.22 "Fund", "Trust" or "Trust Fund" shall mean the cash and other investments of the Plan, and income attributable thereto, held and administered by the Trustee in accordance with the Trust Agreement. 1.23 "Group Annuity Contract" shall mean the group annuity contract issued by John Hancock Mutual Life Insurance Company to Fall River Electric Light Company with respect to certain Employees of the Fall River Electric Light Company who are now Employees of Eastern Edison Company, the group annuity contract issued by The Equitable Life Assurance Society of the United States to Brockton Edison Company with respect to certain Employees of Brockton Edison Company who are now Employees of Eastern Edison Company, the group annuity contract issued by The Equitable Life Assurance Society of the United States to Montaup Electric Company with respect to certain Employees of Montaup Electric Company, the group annuity contract issued by The Equitable Life Assurance Society of the United States to Blackstone Valley Gas and Electric Company with respect to certain Employees of Blackstone Valley Electric Company, and the group annuity contract issued by State Mutual Life Assurance Company with respect to certain Employees of Newport Electric Corporation. 1.24 "Hour of Service" shall mean: (a) Each hour for which an Employee is directly or indirectly paid or entitled to payment by the Employer and any Affiliated Employer for the performance of duties; (b) Each hour for which an individual is directly or indirectly paid or entitled to payment by the Employer and any Affiliated Employer (including payments made or due from a trust fund or insurer to which the Employer or Affiliated Employer contributes or pays premiums) on account of a period of time during which no duties are performed (irrespective of whether the employment relationship has terminated) due to periods of vacation, holidays, illness, incapacity, disability, layoff, jury duty, military duty, or leave of absence, provided that: (i) No more than 501 Hours of Service shall be credited under this paragraph (b) to an Employee on account of any single continuous period during which the Employee performs no duties; and (ii) Hours of Service shall not be credited under this paragraph (b) to an Employee for a payment which solely reimburses the Employee for medically related expenses incurred by the Employee or which is made or due under a plan maintained solely for the purpose of complying with applicable workers' compensation, unemployment compensation or disability insurance laws; and (c) Each hour not already included under paragraph (a) or (b) above for which back pay, irrespective of mitigation of damages, is either awarded or agreed to by the Employer or by an Affiliated Employer, provided that crediting of Hours of Service under this paragraph with respect to periods described in paragraph (b) above shall be subject to the limitation therein set forth. The number of Hours of Service to be credited under paragraph (b) or (c) above on account of a period during which an Employee performs no duties, and the Plan Years to which Hours of Service shall be credited under paragraphs (a), (b), or (c) above shall be determined by the Retirement Board in accordance with Sections 2530.200b-2(b) and (c) of the Regulations of the U.S. Department of Labor. To the extent not credited above, Hours of Service shall also be credited based on the customary work week of the Employee for periods of military duty (as required by applicable law) and Authorized Leave of Absence. 1.25 "Inactive Participant" shall mean a former Active Participant, or, if applicable, his Beneficiary, who is no longer an Eligible Employee but who is entitled to a benefit under the Plan. 1.26 "Normal Form" shall mean a monthly annuity payable to a Participant commencing on his designated Annuity Starting Date and ending with the payment due for the month in which his death occurs. 1.27 "Normal Retirement Age" shall mean the attainment of age 65. 1.28 "Normal Retirement Date" shall mean the first day of the month coincident with or next following the Participant's Normal Retirement Age. 1.29 "One Year Break in Service" shall mean, for purposes of Years of Eligibility and Vesting Service, a computation period (as defined below) during which an Employee is credited with less than 501 Hours of Service. A computation period for the purposes of Years of Eligibility Service shall mean a 12-consecutive month period of employment commencing on an Employee's Employment Date (or Reemployment Date, if applicable) and each anniversary date thereof. A computation period for the purposes of Years of Vesting Service shall mean a 12-consecutive month period of employment commencing on the later of an Employee's Employment Date and his attainment of age 18 and each anniversary date thereof. In the event an Employee incurs a One Year Break in Service and is later reemployed on a date that does not coincide with an anniversary date of his vesting service computation period, he shall be credited with a partial Year of Vesting Service for hours credited during the balance of that computation period. 1.30 "Parental Absence" shall mean an Employee's absence from work which has commenced for any of the following reasons: (a) the pregnancy of the Employee; (b) the birth of the Employee's child; (c) the adoption of a child by the Employee; or (d) the need to care for the Employee's child immediately following its birth or adoption. 1.31 "Participant" shall mean an Active Participant currently participating in the Plan pursuant to Article II or an Inactive Participant. 1.32 "Participating Employer" shall mean Eastern Utilities Associates and any Affiliated Employer adopting this Plan and which has been authorized by the Board to participate in this Plan. 1.33 "Plan" shall mean the Employees' Retirement Plan of Eastern Utilities Associates and Its Affiliated Companies as set forth in this document and as it may be amended from time to time. 1.34 "Plan Year" shall mean the calendar year. 1.35 "Postponed Retirement Date" shall mean the date after his Normal Retirement Date on which a Participant elects to retire, as determined in accordance with Article V. 1.36 "Prior Participant Account" shall mean Employer Contributions made on behalf of a Participant prior to July 1, 1973, together with interest thereon as provided in Article III. 1.37 "Reemployment Date" shall mean the day an Employee returns to work and is credited with an Hour of Service following a One Year Break in Service, a Service Termination Date or an Authorized Leave of Absence from the Employer or an Affiliated Employer. 1.38 "Retired Participant" shall mean a former Employee who is receiving a Retirement Benefit or a former Employee who has received a lump sum Retirement Benefit pursuant to Section 8.6. 1.39 "Retirement Annuity" shall mean the annual amount of the annuity purchased under the Group Annuity Contract as provided by that contract at Normal Retirement Date, prior to any reduction as the result of a provision for Retirement Benefit being payable to a Contingent Annuitant; provided that if the Participant elected not to become a member under the Group Annuity Contract when he was first eligible, his Retirement Annuity shall be computed as the amount of Retirement Annuity at Normal Retirement Date which would have been payable had he elected to become a member when he was first eligible. 1.40 "Retirement Benefit" shall mean either: (a) a lump sum payment made pursuant to Section 8.6, or (b) an annual pension paid in monthly installments. For purposes of Section 8.8, Retirement Benefit shall mean an annual pension paid in monthly installments to a Participant who retired from active service: (a) on or after the attainment of age 61 and completion of five or more Years of Vesting Service, or (b) on or after meeting the requirements for Special Early Retirement described in Section 4.4, or (c) after the attainment of age 55, but before meeting the requirements of (a) and (b) above, with Board approval 1.41 "Retirement Board" shall mean the persons appointed pursuant to Article IX to administer the Plan. 1.42 "Service Termination Date" shall mean the earliest of the following: (a) the date on which the Employee resigns, is discharged, or retires from employment with the Employer and all Affiliated Employers; (b) the date the Employee dies; (c) except as provided below, the first anniversary of the date on which the Employee is laid off, starts an Authorized Leave of Absence, or is absent from work for any other reason other than a Parental Absence on or after January 1, 1985; or (d) effective January 1, 1985, the second anniversary of the date on which the Employee commenced a Parental Absence, if such Employee has not yet returned to work with the Employer or an Affiliated Employer. Notwithstanding subsection (c) above, an Employee who is on an Authorized Leave of Absence due to military service in the armed forces of the United States of America shall not incur a Service Termination Date with respect to such military duty providing he returns to employment with the Employer or an Affiliate within the time prescribed by law for reinstatement of employment rights. Similarly, if an Authorized Leave of Absence is granted for reasons other than military duty and the period of such authorized leave is more than 12 months, a Service Termination Date shall not occur if the Employee returns to work within the time period specified in such Authorized Leave of Absence. If such individual does not return to employment with the Employer or an Affiliated Employer within the time period specified in the Authorized Leave of Absence, a Service Termination Date shall occur on the date on which the Authorized Leave of Absence began. 1.43 "Social Security Benefit" shall mean, in the case of any vested Inactive Participant, the annual primary old-age insurance amount which the Participant would be entitled to receive commencing on the first day of the month next following his social security retirement date (as defined in Section 216(l)) under Title II of the Social Security Act as in effect on the date the Participant retires or otherwise terminates employment, computed on the assumption that the Participant will subsequently receive no income before Social Security Retirement Age, which would be treated as wages for purposes of the Social Security Act. In the case of a Retirement Benefit payable to an Active Participant who retires prior to his Normal Retirement Date, Social Security Benefit shall mean the annual primary old-age insurance amount to which the Participant would first become entitled under Title II of the Social Security Act as in effect on the date the Participant retires if the Participant earns no income after retirement and applies for primary old-age insurance benefits to commence at age 62 or actual retirement if later. In the case of a Retirement Benefit payable to an Active Participant who retires on or after his Normal Retirement Date, Social Security Benefit shall mean the annual primary old-age insurance amount to which the Participant is entitled to receive under Title II of the Social Security Act as in effect on the date the Participant retires if the Participant earns no income after retirement and applies for primary old-age insurance benefits to commence at his actual date of retirement if later. 1.44 "Spouse" shall mean the legal spouse to whom a Participant is married on the Annuity Starting Date under applicable state law. However, if the Participant should die before his Annuity Starting Date, then the Spouse shall be the legal spouse to whom the Participant was married on the Participant's date of death. 1.45 "Trust" shall mean the agreement or agreements governing the investment of Plan assets as amended from time to time, entered into between the Employer and the Trustee to carry out the purpose of the Plan. 1.46 "Trustee" shall mean the trustee or trustees duly appointed by the Board. 1.47 "Year of Eligibility Service" shall mean the period of an Employee's employment with a Participating Employer considered for the purposes of determining his eligibility to participate in the Plan pursuant to Section 2.1. An Employee's Eligibility Service is determined in accordance with Article II. 1.48 "Year of Vesting Service" shall mean the period of an Employee's employment considered for the purposes of determining his vested interest in his Accrued Benefit. An Employee's Vesting Service is determined in accordance with Article II. ARTICLE II SERVICE AND PARTICIPATION 2.1 Eligibility Requirements. (a) Each Employee on January 1, 1989 who was an Active Participant under the Plan on December 31, 1988, shall continue to be an Active Participant on January 1, 1989. (b) Each Employee hired prior to January 1, 1988 and on or after his 64th birthday, shall become an Active Participant on the later of January 1, 1988 and the first day of the month coincident with or next following the date he satisfies the requirements set forth in paragraph (c) below. (c) Each other Employee shall become an Active Participant on the first day of the month coincident with or next following the date he satisfies the following requirements: (i) he is employed by a Participating Employer; (ii) he has completed one Year of Eligibility Service; (iii) he has attained age 21; (iv) he is neither a "leased employee" as defined in Code Section 414(n)(2) nor a temporary employee as defined by the Employer; and (v) he is not a member of a collective bargaining unit, unless participation in the Plan has been negotiated for and agreed to in writing by the representatives of the Participating Employer and the collective bargaining agent. 2.2 Years of Service. (a) (i) Years of Eligibility Service shall determine an Employee's eligibility to participate in the Plan under Section 2.1. An Employee shall accrue one Year of Eligibility Service during a "computation period" in which he is credited with at least 1,000 Hours of Service. For the purposes of this Section 2.2, a "computation period" shall be as defined in Section 1.29 with respect to years of Eligibility Service. (ii) If an Employee fails to earn one Year of Eligibility Service, incurs a One Year Break in Service, and is subsequently reemployed by the Employer or an Affiliated Employer, his Reemployment Date shall be considered his Employment Date for the purpose of applying the above computation period rules. (iii) If an Employee earns one Year of Eligibility Service and subsequently terminates employment, he shall become a Participant on the earliest applicable date set forth in Section 2.1, provided his Reemployment Date occurs prior to his incurring five consecutive One Year Breaks in Service and he otherwise meets the participation requirements of Section 2.1 or he is vested in his Accrued Benefit pursuant to Section 6.2. If such an Employee incurs five or more One Year Breaks in Service and he is not vested in his Accrued Benefit pursuant to Section 6.2, his Reemployment Date shall be considered his Employment Date for the purposes of applying the above computation period rules. (b) Years of Vesting Service shall determine a Participant's vested right in retirement benefits accrued under the Plan, except that at Normal Retirement Date, an Active Participant shall be fully vested in his Accrued Benefit, irrespective of his Years of Vesting Service. (i) Subject to the One Year Break in Service rule under subparagraph (ii), the transfer provisions of Section 2.8 and the Addendum, one Year of Vesting Service shall be credited to an Employee for each "computation period" during which he is credited with at least 1,000 Hours of Service. For the purposes of this paragraph (b)(i), a "computation period" shall be as defined in Section 1.29 with respect to Years of Vesting Service. (ii) If an Employee incurs a One Year Break in Service, he shall not lose his Years of Vesting Service accumulated before such break provided: (A) he was vested in his Accrued Benefit under the Plan prior to his One Year Break in Service, or (B) his number of consecutive One Year Breaks in Service does not exceed five. Such earlier period of vesting service shall be restored pursuant to this subparagraph upon completion of a Year of Vesting Service subsequent to the Employee's Reemployment Date. Notwithstanding the foregoing, in no event shall an Employee's Years of Service hereunder be less than his Years of Service as determined in accordance with the terms of the Plan as in effect immediately prior to January 1, 1989. 2.3 Years of Credited Service. Credited Service is used in the calculation of an Eligible Employee's Accrued Benefit under Section 3.1. Subject to the One Year Break in Service provisions in Section 2.2(b) and the transfer provisions of Section 2.8, an Eligible Employee shall accrue Credited Service as follows: (a) One Year of Credited Service shall be credited to an Eligible Employee for each full calendar year between Employment Date and Service Termination Date while a Participant, except as otherwise provided below. (b) For any calendar year in which employment is interrupted or for which the individual is not an Eligible Employee for the entire year, a fractional Year of Credited Service calculated to the nearest 1/12th shall be credited to an Eligible Employee for each calendar month during which he earns Hours of Service as a Participant. (c) Credited Service earned prior to a One Year Break in Service shall be reinstated pursuant to the provisions of Sections 2.2(b)(ii) by substituting "Years of Credited Service" for "Years of Vesting Service" thereunder. Such reinstatement of prior Credited Service shall be effective, however, upon completion of a Year of Credited Service subsequent to the Eligible Employee's Reemployment Date. In the event a Participant terminates employment, receives a distribution of his Prior Participant Account and is later reemployed, upon completion of a Year of Credited Service subsequent to his Reemployment Date, the portion of his Accrued Benefit which is the Actuarial Equivalent of such Prior Participant Account shall be reinstated provided that he repays to the Plan the amount distributed to him plus interest at the rate of 2% per annum computed from the date of payment. Such repayment of the Prior Participant Account, plus interest, must be made before the earlier of: (i) the fifth anniversary of the Participant's Reemployment Date; and (ii) the date the Participant incurs five consecutive One Year Breaks in Service. If such a Participant does not make such repayment of the amount distributed within the aforementioned period of time, in no event shall the portion of his Accrued Benefit which is the Actuarial Equivalent of his Prior Participant Account shall be reinstated hereunder. (d) Credited Service shall only be granted hereunder for any period of time during which an individual is in a class of Employees which is eligible to participate in the Plan; except that for an Employee who was hired prior to January 1, 1989, Credited Service shall be granted for any period of time on and after such Employee's attainment of age 21 provided he otherwise satisfied the requirements of Sections 2.1(b) and (c). (e) Credited Service shall not include any period of Parental Absence. Notwithstanding the foregoing, in no event shall a Participant's years of Credited Service hereunder be less than his years of Credited Service as determined in accordance with the terms of the Plan as in effect immediately prior to January 1, 1989. 2.4 Postponed Retirement or Reemployment After Benefits Commence. If an Employee works beyond his Normal Retirement Date or if a Retired Participant returns to work with a Participating Employer after Retirement Benefits had become payable to him, the following rules shall apply: (a) if he is a Retired Participant returning to work and he is an Eligible Employee, he shall become an Active Participant on his Reemployment Date; if he is an Active Participant continuing to work he shall remain an Active Participant as long as he is an Eligible Employee; (b) (i) if he has attained Normal Retirement Age and his Retirement Benefit had not yet commenced because of continued employment, such benefit shall be postponed upon proper notification, during any calendar month in which he is scheduled to complete 80 or more Hours of Service. Retirement Benefits shall commence as herein-after provided if the Employee is thereafter scheduled to complete less than 80 Hours of Service in any calendar month; (ii) if he has attained Normal Retirement Age at the time of his reemployment with a Participating Employer, all retirement benefits shall be suspended, upon proper notification, during each Plan Year for which he is scheduled to work 1,000 Hours of Service and shall be resumed not later than the first day of the first Plan Year thereafter in which he is scheduled to complete less than 1,000 Hours of Service; (iii) if he has not attained Normal Retirement Age at the time of his reemployment with a Participating Employer, all Retirement Benefits shall automatically cease upon such reemployment and his benefit shall be recomputed upon his subsequent retirement; (iv) any benefits payable upon a Participant's subsequent retirement shall be reduced by the Actuarial Equivalent value of any early retirement benefits he had previously received. (c) he shall be eligible for additional Years of Vesting Service and Years of Credited Service as a result of his reemployment or continued employment in accordance with the provisions of the Plan; (d) if he shall die during the period of subsequent or continuing employment, death benefits, if any, shall be payable only in accordance with the provisions of Article VII. 2.5 Suspension of Benefits. (a) During the first calendar month in which an Employee's benefits are suspended pursuant to Section 2.4 for any period commencing after Normal Retirement Date, the Retirement Board shall deliver to the Employee, by personal delivery or first class mail, a notice setting forth a description of the specific reasons why benefit payments are being suspended, a general description of the Plan provisions relating to the suspension of benefits, a copy of the Plan provisions relating to the suspension of benefits, the statement that applicable Department of Labor Regulations may be found in Section 2530.203-3 of ERISA, a description of the procedures set forth in the Plan for obtaining a review of the suspension of benefits, and a description of any notice procedure (including any forms which must be filed by the Employee) as a prerequisite for the Employee's obtaining the resumption or commencement of benefit payments. In any event, the Retirement Board shall adopt rules conforming in all respects to the requirements of Section 2530.203-3 of ERISA relating to suspension of benefits. 2.6 Service With a Former Employer. (a) Any Participant who: (i) rendered service in the employ of another utility company or a similar company, or a company or corporation engaged to furnish advisory or supervisory services to any such companies, and (ii) received a bona fide offer of employment from the Employer prior to the termination of his employment with such other company: (A) shall be credited under the Plan with all Years of Credited Service with such other employer rendered since the first day of the month coincident with or next following the date he completed one year of such service and attained the 21st anniversary of his birth; and (B) shall be deemed to have been in the employ of the Employer during all such service with the former employer from the date of original employment, or from the date of restoration to such service in the event of an interruption in such service, for the purposes of determining his eligibility for membership and his vested rights under the Plan. (b) Except for purposes of determining the amount of the spouse's death benefit under Article VII, the Retirement Benefit provided under this Plan for any Participant who has been credited with Years of Credited Service under paragraph (a) of this Section 2.6 shall be reduced by the lesser of: (i) the full amount of any pension or retirement income which he is, or would have been but for his own action, entitled to receive under the plan of his former employer, or (ii) the amount the Participant would have accrued under this Plan, based on his Years of Credited Service credited under said paragraph (a) and his Average Earnings as of the date of termination of employment with his former employer. In no event, however, will a Participant's Retirement Benefit hereunder be less than the benefit he would have been entitled to on the basis of his employment solely with the Employer. For the purpose of computing Equivalent Actuarial Values, the appropriate factors listed in the Appendix shall be applied after the determination of such reduced Retirement Benefit. 2.7 Service With Newport Electric Corporation. Any Employee who transfers his employment from Newport Electric Corporation to the Employer on or after December 31, 1990, shall be deemed to have been in the employ of the Employer for all periods of employment with Newport Electric Corporation for the purposes of determining such Employee's Years of Eligibility Service, Vesting Service and Credited Service hereunder. 2.8 Transfers. Any individual who ceases to be an Eligible Employee by reason of employment with an Affiliated Employer or a change in employment classification, either prior to or subsequent to commencement of his participation in this Plan, shall be credited with Years of Service during such period of employment pursuant to Sections 2.2, solely for purposes of vesting and eligibility for benefits. Such Participant shall be entitled only to benefits under the provisions of the Plan as in effect while he is eligible to participate in the Plan. Credited Service shall only be earned for periods during which the Employee is eligible to participate in the Plan. 2.9 Termination of Participation. A Participant's membership in the Plan shall terminate if his employment with the Employer terminates other than by reason of retirement under the Plan; provided, however, that the Participant shall not be deprived of any vested benefit to which he may be entitled under Article VI. Membership shall be continued during a period while on an Authorized Leave of Absence from service approved by the Employer or an Affiliated Employer or during a period while he is not an Employee as herein defined but is in the employ of the Employer or an Affiliated Employer, but in any case of interruption to service during which a Participant receives a payment of his Prior Participant Account his membership in the Plan and his benefits thereunder shall be in accordance with the provisions of Section 2.3. In no event while a Participant is on an Authorized Leave of Absence, shall he be retired under the Plan unless the absence commenced on or after his Normal Retirement Date or unless it commenced after he reached the 55th anniversary of his birth. ARTICLE III NORMAL RETIREMENT BENEFIT 3.1 Normal Retirement Benefit. Subject to the minimum benefit provisions under Section 3.2 and the maximum benefit limitations under Section 3.3, the amount of monthly Retirement Benefit on the life annuity basis as described in Section 8.4 to which a Participant is entitled to receive beginning on his Normal Retirement Date is equal to the sum of (a) less (b) plus (c) less (d) below: (a) (i) 1.6% of the Participant's Average Earnings multiplied by (ii) his Years of Credited Service up to 35 such years. (b) (i) 1.2% of the Participant's Social Security Benefit multiplied by (ii) his Years of Credited Service up to 35 such years. (c) (i) .75% of the Participant's Average Earnings, multiplied by (ii) his Years of Credited Service in excess of 35 such years, but not more than 40 such years. (d) his Retirement Annuity. In no event shall a Participant's Retirement Benefit hereunder be decreased as a result of any increase in his Social Security Benefit which becomes effective subsequent to his actual retirement or other termination of employment. Unless otherwise provided under the Plan, each Section 401(a)(17) Employee's Accrued Benefit under this plan will be the greater of the accrued benefit determined for the employee under (e) or (f) below: (e) the Employee's Accrued Benefit determined with respect to the benefit formula applicable for the Plan Year beginning January 1, 1994, as applied to the Employee's total Years of Credited Service taken into account under the Plan, or (f) the sum of: (i) the Employee's Accrued Benefit as of December 31, 1993, frozen in accordance with Section 1.401(a)(4)-13 of the regulations, and (ii) the Employee's Accrued Benefit determined under the benefit formula applicable for the Plan Year beginning January 1, 1994, as applied to the Employee's Years of Credited Service credited to the Employee for Plan Years beginning on or after January 1, 1994. A Section 401(a)(17) Employee means an employee whose current Accrued Benefit as of January 1, 1994, is based on Earnings for a year beginning prior to January 1, 1994, that exceeded $150,000. The Participant's Retirement Benefit shall be paid pursuant to Article VIII. 3.2 Minimum Accrued Benefit. (a) For a Participant who is a "super highly compensated employee" (an individual described under Code Section 414(q)(1)(A) or (B)) for calendar year 1989, the Accrued Benefit payable at Normal Retirement Date hereunder shall not be less than such Participant's Accrued Benefit on December 31, 1988 under the terms of the Plan on such date; Further, in no event shall Retirement Benefits for any such "super highly compensated" Retired Participant be paid from the Trust Fund for amounts that would have been payable for the period January 1, 1989 through June 30, 1991, had such benefits not been frozen pursuant to Model Amendment IID under Internal Revenue Service Notice 88-131, as adopted by the Employer effective December 31, 1988. As a result of the revocation of Model Amendment IID, effective July 1, 1991, Retirement Benefits for the "super highly compensated" Retired Participants attributable to the period from January 1, 1989 through June 30, 1991 shall be payable from the Trust Fund for periods on and after July 1, 1991 only. (b) For any other individual who was a Participant after December 31, 1988, the Accrued Benefit payable at Normal Retirement Date shall not be less than the Accrued Benefit of such Participant determined on December 31, 1988 under the terms of the Plan in effect immediately prior to January 1, 1989. (c) Notwithstanding the foregoing, in no event shall the benefit hereunder for any Participant who was a Participant under the Newport Electric Corporation Pension Plan as in effect immediately prior to January 1, 1991, be less than the benefit accrued to such Participant under the terms of the Newport Electric Corporation Pension Plan as in effect immediately prior to January 1, 1991. 3.3 Maximum Benefit. Effective January 1, 1987, notwithstanding any other provision of the Plan to the contrary, a Participant's annual retirement benefit under the Plan and any other defined benefit pension plan of an Employer or an Affiliated Employer may not exceed the lesser of (a) or (b) below, except as provided in (c) below, provided that if the applicable limits described below are adjusted for increases in the cost of living as provided in rules and regulations adopted by the Secretary of the Treasury after a Retirement Benefit is in pay status, benefit payments to a Retired Participant or his Beneficiary, if applicable, shall be increased automatically to the maximum extent permitted under the revised limits. This increase shall occur only to the extent that it would not cause the benefit to exceed the benefit to which the Retired Participant or Beneficiary would have been entitled in the absence of the limits of this Section 3.3: (a) The lesser of (i) or (ii) below, but subject to subparagraphs (iii) through (x) below: (i) 100% of his average compensation in the three consecutive highest paid calendar years while a Participant in the Plan. (ii) $90,000 (as adjusted for increases in the cost of living as provided in rules and regulations adopted by the Secretary of the Treasury). (iii) In the case where a benefit is payable prior to the Participant's Social Security Retirement Age (defined below), the dollar limitation in subsection (ii) above shall be adjusted so that it is the actuarial equivalent of an annual benefit of $90,000 (as adjusted for increases in the cost of living as provided in rules and regulations adopted by the Secretary of the Treasury), beginning at the Social Security Retirement Age, multiplied by an adjustment factor, as prescribed by the Secretary of the Treasury. The adjustment provided for in the preceding sentence shall be made in such manner as the Secretary of the Treasury may prescribe which is consistent with the reduction for old-age insurance benefits commencing before the Social Security Retirement Age under the Social Security Act. For purposes of determining actuarial equivalence hereunder, the interest assumption shall not be less than the greater of 5% per year or the underlying rate used to determine the reduction of benefits for early payment under the Early Retirement provisions of Section 4.2. (iv) In the case where a benefit commences after a Participant has attained Social Security Retirement Age, the dollar limitation in subsection (ii) above shall be adjusted so that it is the actuarial equivalent of an annual benefit of $90,000 (as adjusted for increases in the cost of living as provided in rules and regulations adopted by the Secretary of the Treasury) beginning at the Social Security Retirement Age, multiplied by an adjustment factor as prescribed by the Secretary of the Treasury. For purposes of determining actuarial equivalence hereunder, the interest assumption shall not be greater than the lesser of 5% per year or the rate specified in Section 1.3. (v) If a Participant has completed less than ten years of participation in the Plan, the Participant's Accrued Benefit shall not exceed the dollar limit in subsection (ii) above as adjusted by multiplying such amount by a fraction, the numerator of which is the Participant's number of years (or part thereof) of participation in the Plan, and the denominator of which is ten. (vi) If a Participant has completed less than ten Years of Vesting Service, the limitations described in Code Sections 415(b) (1)(B) and 415(b)(4) shall be adjusted by multiplying such amounts by a fraction, the numerator of which is the Participant's number of Years of Vesting Service (or part thereof), and the denominator of which is ten. (vii) In no event shall subsections (v) and (vi) above reduce the limitations provided under Code Sections 415(b)(1) and (4) to an amount less than one-tenth of the applicable limitation (as determined without regard to this section). To the extent provided by the Secretary of the Treasury, subsections (v) and (vi) above shall be applied separately with respect to each change in the benefit structure of the Plan. (viii) Unless subsection (vi) applies to a Participant, the limits of subsections (i) and (ii) above shall be deemed met if: (A) the annual benefit payable to the Participant from this Plan and all other qualified defined benefit plans of the Employer does not exceed $10,000; and (B) the individual has never participated in a qualified defined contribution plan sponsored by the Employer or an Affiliated Employer. (ix) Except in the case where a benefit is payable pursuant to Section 8.1(a) or 8.3(a), with the Participant's Spouse as the Contingent Annuitant, if a benefit is payable in a benefit form other than a life annuity, the amount otherwise determined under this subparagraph (a) shall be the Actuarial Equivalent of the amount payable as a life annuity. For this purpose, the interest rate assumption shall not be less than the greater of 5% or the rate specified in Section 1.3. (x) For purposes of this Section 3.3, Social Security Retirement Age shall be as defined in Code Section 415(b)(8). (b) In the case of a Participant who has participated in a defined contribution plan maintained by an Employer or an Affiliated Employer, the amount determined pursuant to subparagraph (a) above shall be multiplied by 1.40 in the event (a)(i) applies or by 1.25 in the event (a)(ii) applies and shall further be multiplied by a fraction equal to one minus a fraction with a numerator equal to (i) below and a denominator equal to (ii) below: (i) The sum of the annual additions made to the Participant's account under all defined contribution plans maintained by the Employer and its Affiliated Employers, where the annual additions are equal to the sum of (A) Employer contributions allocated to the Employee's account, (B) any forfeitures allocated to the Employee's account, (C) the portion of the Employee's after-tax contributions made prior to January 1, 1987, that represented the lesser of one-half of such contributions or the amount of such contributions in excess of 6% of his compensation, (D) all Employee after-tax contributions made after December 31, 1986, and (e) amounts described in Code Sections 415(l)(1) and 419(A)(d)(2). (ii) The sum for each calendar year of the Participant's employment with an Employer or an Affiliated Employer of the lesser of (A) 1.4 multiplied by 25% of the Participant's compensation for the calendar year, or (B) 1.25 multiplied by $30,000, as adjusted for increases in the cost of living as provided under rules and regula- tions adopted by the Secretary of the Treasury. (c) If, in any limitation year, the benefit under this Plan exceeds the lesser of (a) or (b) above, then appropriate reductions shall first be applied to the Participant's Accrued Benefit under this Plan in order to reduce such benefit to the lesser of (a) or (b). For the purpose of this paragraph, an Affiliated Employer shall be determined by assuming the phrase "more than 50%" is substituted for the phrase "at least 80%" wherever it appears in Code Section 1563, as it may be amended from time to time and limitation year shall mean Plan Year. 3.4 Continuing Employment. The retirement of any Participant under this Article III shall not become effective while he is in the employment of an Employer or an Affiliated Employer, except as provided in Section 2.4. If an Employee continues to work for the Employer or an Affiliated Employer beyond his Normal Retirement Date, the provisions of Article V and Article VIII shall be applicable. ARTICLE IV EARLY RETIREMENT DATE AND EARLY RETIREMENT BENEFIT 4.1 Early Retirement Date. A Participant may retire prior to his Normal Retirement Date on the first day of any month coincident with or next following his attainment of age 55 and his completion of five or more Years of Vesting Service. If a Participant intends to retire early under this Article IV, he must file a written notice of his intent with the Retirement Board. The date of his retirement must be stated in the notice. The date on which a Participant retires under this Paragraph 4.1 shall be his Early Retirement Date. 4.2 Early Retirement Benefit. Subject to the minimum benefit provisions of Sections 3.2 and 4.3 and the maximum benefit limitations of Section 3.3, a Participant who retires on an Early Retirement Date may elect to receive either an immediate Retirement Benefit or a deferred Retirement Benefit as indicated below. The monthly amount of the Retirement Benefit payable in the Normal Form shall be equal to either (a) or (b) below, as applicable. (a) Early Payment. If the Participant terminates on an Early Retirement Date and elects to commence payment of Retirement Benefits prior to his Normal Retirement Date, the amount of the benefit shall be equal to his Accrued Benefit reduced by the appropriate factor in the Appendix. Such reduction shall be applied to the Retirement Benefit determined pursuant to the provisions of Section 3.1(a), (b) and (c). The value of the Retirement Annuity payable to such Participant shall be subject to the early retirement factors under the Group Annuity Contract. (b) Deferred Payment. If the Participant terminates on an Early Retirement Date and elects to defer payment of his Retirement Benefit to his Normal Retirement Date, the amount of his monthly Retirement Benefit on the life annuity basis (described in Section 8.4) shall be equal to his Accrued Benefit. 4.3 Minimum Benefit. In no event shall the early retirement income payable under this Plan be less than the Accrued Benefit determined under the provisions of the Plan immediately before the adoption of this amended and restated Plan, adjusted to reflect early receipt based on the early retirement reduction factors specified in the Plan as of such date. 4.4 Special Early Retirement. Notwithstanding Sections 4.1 and 4.2, effective July 1, 1991, an Active Participant who has attained age 55 and whose attained age plus completed Years of Vesting Service equal at least 85, may retire on a Special Early Retirement Date and elect to commence payment of his Retirement Benefits prior to his Normal Retirement Date, the amount of his benefit shall be equal to his Accrued Benefit reduced by the appropriate Special Early Retirement factor in the Appendix. ARTICLE V POSTPONED RETIREMENT DATE AND POSTPONED RETIREMENT BENEFIT 5.1 Postponed Retirement Date. The Postponed Retirement Date of a Participant will be the day of his actual retirement after his Normal Retirement Date. 5.2 Postponed Retirement Benefit. (a) If a Participant attained age 70-1/2 prior to January 1, 1988 or if his Postponed Retirement Date occurs during or prior to the end of the calendar year in which he attained age 70-1/2, his Accrued Benefit under Section 3.1 shall be determined and payable as of his Postponed Retirement Date. (b) If a Participant's Postponed Retirement Date has not occurred by the end of the calendar year in which he attains age 70-1/2 and Retirement Benefits must commence pursuant to Section 8.6(b), then his Retirement Benefit shall be his Accrued Benefit calculated pursuant to Article III as of the close of the calendar year in which he attains age 70-1/2. For subsequent required distributions, his Accrued Benefit shall be recalculated at the end of each calendar year thereafter until his actual Postponed Retirement Date or his date of death. Recalculation of the Accrued Benefit is described in the following subparagraph (c). Once Retirement Benefits commence under this Section 5.2, a Participant may not elect a different form of payment, Beneficiary or Contingent Annuitant for any additional Accrued Benefit which is calculated hereunder, except in the event of death of the Beneficiary or a divorce of the Participant. (c) The recalculation of the Participant's Accrued Benefit under Section 5.2(b) shall be performed as follows: (i) a new Accrued Benefit shall be calculated using the Participant's Average Earnings, Years of Credited Service, and Social Security Benefit at the close of the calendar year; (ii) the new Accrued Benefit as determined under (i) above shall be reduced by the Actuarial Equivalent value of the Retirement Benefit payments previously received by the Participant during months in which Retirement Benefits would have been suspended pursuant to Section 2.4, provided that the resulting benefit shall not be less than the benefit the Participant is receiving before it is recalculated under (i) above. (d) Notwithstanding any provision of this Plan to the contrary, all distributions made hereunder shall be made in accordance with the requirements of Code Section 401(a)(9) and regulations thereunder, including the incidental death benefit requirements of Treasury Regulation 1.401(a)(9)-2. The provisions of this section override any distribution options under the Plan if inconsistent with the requirements of Code Section 401(a)(9). (e) Postponed Retirement Benefits hereunder shall commence to the Participant upon the earlier of (i) his Postponed Retirement Date, or (ii) if required pursuant to Section 8.6(a), the April 1 following the calendar year in which he has attained age 70-1/2. The Participant's Postponed Retirement Benefit shall be paid pursuant to Article VIII. 5.3 Death Prior to Postponed Retirement Date. If a Participant dies after his Normal Retirement Date, but prior to commencement of his Retirement Benefit, his Spouse shall be entitled to benefits under the Plan in accordance with Article VII in the amount which would have been payable to his Spouse had his benefits commenced on the first day of the month coincident with or next preceding his death in the form described in Section 7.1. 5.4 Death Following Commencement of Retirement Benefits. If a Participant dies while actively employed and after his Retirement Benefit has commenced pursuant to Section 5.2, any death benefit payable with respect to any additional accrual he may be entitled to as a result of his continued employment shall be paid in the same form as in effect when such Retirement Benefits originally commenced. ARTICLE VI TERMINATION OF EMPLOYMENT 6.1 Non-Vested Termination. Effective January 1, 1989, a Participant whose employment is terminated with the Employer and all Affiliated Employers prior to: (a) his completion of five Years of Service subsequent to his attainment of age 18, and (b) the complete or partial termination of the Plan with respect to such Participant, shall have no vested interest in his Accrued Benefit and shall not be entitled to receive a Retirement Benefit from the Plan. Upon the Service Termination Date of a Participant who has no vested right to his Accrued Benefit, the entire value of his vested benefit hereunder shall be deemed to be distributed to him. In the event such Participant is credited with an Hour of Service before incurring five consecutive One Year Breaks in Service following his Service Termination Date, his vested benefit previously deemed to be distributed to him hereunder will be deemed repaid to the Plan. 6.2 Vested Termination. Effective January 1, 1989, an Employee shall have a nonforfeitable right to his Accrued Benefit upon the earliest of the following events: (a) his completion of five Years of Service subsequent to his attainment of age 18, and (b) the complete or partial termination of the Plan with respect to such Participant. An Inactive Participant who is no longer an Employee shall be entitled to receive a deferred Retirement Benefit commencing on his Normal Retirement Date in an amount equal to his Accrued Benefit. For purposes of determining such Accrued Benefit, only the provisions of the Plan in effect at the time of the Participant's Service Termination Date shall be considered. The Participant's Retirement Benefit shall be paid pursuant to Article VIII. 6.3 Early Payment. In lieu of the deferred benefit described in Section 6.2, an Inactive Participant who has a nonforfeitable right to his Accrued Benefit may elect in writing to receive a reduced benefit commencing on the first day of any month between his 55th birthday and his Normal Retirement Date. If the Participant elects to receive his Retirement Benefit before his Normal Retirement Date, his Accrued Benefit shall be reduced by the appropriate factor in the Appendix. The Participant's Retirement Benefit shall be paid pursuant to Article VIII. 6.4 Prior Participant Account. A vested Participant whose employment terminates for reasons other than death prior to his eligibility for early retirement under Section 4.1 may elect to receive his Prior Participant Account, plus interest, as determined on his termination of employment at the rate of 2% per annum once per year as of December 31, or, in the case of earlier termination of employment as of the end of the month preceding such termination on the basis of the balance in such account as of the preceding December 31 or at any time following his termination of employment and prior to commencement of payment of his Retirement Benefit, if any, by filing a written application with the Retirement Board. Upon payment of the Prior Participant Account, the Participant's deferred Retirement Benefit shall be reduced by the Actuarial Equivalent value of such account. In the event a Participant has no vested interest in his Accrued Benefit and the value of his Participant Account is $3,500 or less, payment of his Participant Account shall be subject to the provisions of Section 8.6. ARTICLE VII DEATH BENEFITS 7.1 Immediate Surviving Spouse Benefit For Death Occurring On or After Age 55. If an Active or an Inactive Participant who has completed at least five Years of Vesting Service and attained age 55 prior to his termination of employment dies, a monthly Retirement Benefit shall be payable to his surviving Spouse. The amount of the benefit is the amount that would have been payable to the Spouse as Contingent Annuitant had the Participant retired on the date of his death with an immediate benefit payable subject to early payment reduction under Article IV under the 100% Joint and Survivor annuity form described in Article VIII with his Spouse as Contingent Annuitant. Unless Section 8.6 applies, such Spouse's benefit shall commence on the first day of the month next following the Participant's date of death and continue for the surviving Spouse's lifetime. If the involuntary cash-out provisions of Section 8.6 are operative, a monthly death benefit which becomes due hereunder but which has not yet commenced shall be paid in one lump sum amount to the Spouse in lieu of all other benefits under the Plan. 7.2 Pre-Retirement Surviving Spouse Benefit For Death Of Active or Inactive Participant Occurring Before Age 55. (a) If an Active Participant who has completed ten Years of Vesting Service dies after his 50th birthday but before age 55, a monthly Retirement Benefit shall be payable to his surviving Spouse. The amount of such benefit is the amount that would have been payable to the Spouse as Contingent Annuitant had: (i) the Participant terminated employment with the Employer and all Affiliated Employers on the day before his death and elected Retirement Benefits to begin on the first day of the month coincident with or next following his date of death, and (ii) his Accrued Benefit had been payable in the 100% Joint and Survivor annuity form described in Article VIII with his Spouse as Contingent Annuitant, multiplied by the appropriate factor below: Participant's Age at Nearest Birthday Factor 50.35 51.38 52.41 53.44 54.47 Unless Section 8.6 applies, such Spouse's benefit under this paragraph (a) shall be payable commencing on the first day of the month coincident with or next following his date of death and shall continue for the surviving Spouse's lifetime. (b) If an Active Participant who has completed at least five Years of Vesting Service dies prior to age 55, a monthly Retirement Benefit shall be payable to his surviving Spouse. The amount of such benefit is the amount that would have been payable to the Spouse as Contingent Annuitant: (i) had the Participant terminated employment with the Employer and all Affiliated Employers on the day before his death and elected Retirement Benefits to begin at the later of age 50 or his date of death; and (ii) shall be equal to 50% of the Member's Accrued Benefit multiplied by the appropriate factor in the Appendix, as though the Participant had survived to the later of age 50 or his date of death and had elected the 50% Joint and Survivor Annuity form described in Article VIII with his Spouse as Contingent Annuitant. Such amount shall be multiplied by the appropriate factor set forth in (a)(ii) above. Unless Section 8.6 applies, such Spouse's benefit under this paragraph (b) shall be payable commencing on the first day of the month coincident with or next following the later of the date the Participant would have attained age 50 and his date of death and shall continue for the surviving Spouse's lifetime. (c) If an Inactive Participant who was vested in his Accrued Benefit as of his termination of employment dies prior to age 55, a monthly Retirement Benefit shall be payable to his surviving Spouse. The amount of such benefit shall be 50% of the amount of the Inactive Participant's Accrued Benefit that he would have been entitled to receive in the form of a 50% Joint and Survivor Annuity and elected Retirement Benefits to commence at age 55. Unless Section 8.6 applies, such Spouse's benefit under this paragraph (c) shall be payable commencing on the first day of the month coincident with or next following the date the Participant would have attained age 55. If the involuntary cash-out provisions of Section 8.6 are operative, a monthly death benefit which becomes due hereunder but which has not yet commenced shall be paid in one lump sum amount to the Spouse in lieu of all other benefits. 7.3 Death Benefits After Retirement Benefits Have Commenced. If a Participant dies at any time after Retirement Benefits have begun, death benefits, if any, shall be strictly dictated by the form of payment in which such Retirement Benefit was being paid. 7.4 Prior Participant Account. If a participant dies before Retirement Benefits have begun and provided that no benefit is payable to his surviving Spouse, the value of his Participant Account, determined at his date of death in the same manner as described in Section 6.4, shall be payable in a single sum to his Beneficiary. ARTICLE VIII PAYMENT OF RETIREMENT BENEFITS 8.1 Automatic Payment Forms. Unless the involuntary cash-out provisions of Section 8.6 apply, the automatic or normal form of Retirement Benefit shall be as described in this Section 8.1. A Participant may, however, elect an optional form of Retirement Benefit in accordance with Section 8.2. (a) A Participant who has a Spouse on the Annuity Starting Date shall receive a reduced retirement income which shall be the Actuarial Equivalent of the Retirement Benefit to which he would be entitled under the Plan if he had no Spouse, payable monthly commencing on the first day of the month coincident with or next following the date his retirement occurs, and if he shall die prior to such Spouse, continuing to the Spouse at 50% of the reduced amount and ending with the payment due for the month in which the death of the Spouse occurs. (b) A Participant who does not have a Spouse on the Annuity Starting Date shall receive the Retirement Benefit to which he is entitled under the Plan, payable monthly commencing on the first day of the month coincident with or next following the date his retirement occurs and ending with the payment due for the month in which his death occurs. Notwithstanding anything to the contrary hereunder, upon cessation of payments of the retirement Benefit or other benefit payable to or on account of any retired Participant or his Spouse, any excess of the value of the Participant's Participant Account (as determined pursuant to Section 6.4) at the date of retirement or prior death over the total benefit payments made to him or on his behalf shall be paid in one sum to the beneficiary designated by the person last in receipt of such Retirement Benefit or other benefit, or if no such beneficiary is living, to the legal representative of such person. 8.2 Election of Optional Forms. At least 30 days, but not more than 90 days, prior to an Annuity Starting Date, a Participant may elect an optional form of payment for his Retirement Benefit as may be available under Section 8.3 or 8.4. Such election will not take effect unless the Participant's Spouse consents to the election if required under Section 8.5(c). The Retirement Board shall make an election form available to each such eligible Participant. Such form shall describe in plain language the terms and conditions of the normal form of payment described in Section 8.1 and the optional forms of benefit and shall provide for election of optional forms of benefit and a benefit commencement date. The completed election form must be returned to the Retirement Board within the 90 day period ending on the designated Annuity Starting Date. In addition, the form will provide a description of the Participant's right to reinstate coverage under the normal form of benefit described in Section 8.1 prior to his Annuity Starting Date by revoking an election of an optional form of benefit. If a Participant files a subsequent election form prior to the date benefits commence, the prior form shall be of no effect. If no election has been made at the expiration of the election period, Retirement Benefits will be payable in accordance with Section 8.1. Election of optional forms of benefits under the following Sections 8.3 and 8.4 shall be subject to the restrictions of Section 8.5. Any such election, whenever made, may be altered, amended, or revoked by the Participant prior to the date when the first payment of his retirement income would normally be made, provided he gives notice in writing to the Retirement Board. The Retirement Board may, on a uniform and nondiscriminatory basis, provide for such other election periods as comply with regulations issued under Code Sections 401(a)(11) and 417. Subject to the provisions of Section 8.5, the Retirement Board may defer a Participant's Annuity Starting Date for a period of up to 90 days if the Retirement Board determines that the deferral is desirable in order to provide for an orderly election procedure, provided that retroactive payment shall be made for any Retirement Benefits which would have been paid in the absence of the deferral. 8.3 Joint and Survivor Option. Subject to the spousal consent requirements outlined in Section 8.5(c): (a) A Participant may elect, by submitting an election form to the Retirement Board, to have his Retirement Benefit converted to the Actuarial Equivalent of the normal form under Section 8.1 and paid monthly during his life with the provision that after his death, any percentage from 50% through 100% of such reduced Retirement Benefit will be payable to his Contingent Annuitant during the remaining life of such Contingent Annuitant. (b) If a Participant elects the Joint and Survivor Option and his Contingent Annuitant dies before such Participant's benefit actually commences and the Participant does not change his election in accordance with Section 8.2, his Retirement Benefit shall be paid under the normal form under Section 8.1. (c) If a Participant elects the Joint and Survivor Option and dies before benefits commence to be paid to him, his Beneficiary will not be entitled to any rights or benefits under the Plan, except as provided under Article VII. (d) If a Participant elects the Joint and Survivor Option and his Contingent Annuitant dies before his death, but after the retirement of such Participant, such Participant will continue to receive the reduced Retirement Benefit payable to him in accordance with such option. Notwithstanding the foregoing, however, in the event the Contingent Annuitant dies before the Participant and within one year of the date on which payments commenced under the Joint and Survivor Annuity option, the Participant's Retirement Benefit shall be increased on the first day of the month following such Contingent Annuitant's death to the amount which would have been payable to him under the Life Annuity Option described in Section 8.4) for the balance of his lifetime. 8.4 Life Annuity Option. Subject to Section 8.5(c), a Participant may elect, by submitting an election form to the Retirement Board, to have his Retirement Benefit paid in the normal form under Section 8.1(b). The normal form provides for monthly payments during the Participant's life, ending with the payment due for the month in which his death occurs. 8.5 General Provisions. (a) Notwithstanding any other provisions of the Plan, distribution of benefits to Participants who attain age 70-1/2 in 1988 or 1989 will commence on April 1, 1990. Distribution to Participants who attain age 70-1/2 in 1990 and calendar years thereafter will commence by the April 1 following the year in which age 70-1/2 is attained. Distribution to Participants who attained age 70-1/2 prior to January 1, 1988 will be deferred until the April 1 of the year next following the close of the calendar year in which the Participant retires; provided, however, that distribution of benefits to an Employee who owns 5% or more of the outstanding stock of the Employer may not be deferred beyond the April 1 following the calendar year in which he attains age 70-1/2. In any event, distributions hereunder shall be made in accordance with Code Section 401(a)(9) and regulations thereunder, including Treasury Regulations 1.401(a)(9)-2. Such regulations and applicable rulings or announcements, including any grandfather provisions delaying the effective date of Code Section 401(a)(9) are hereby incorporated by reference. (b) Upon the death of a Participant any remaining interest he may have in the Plan shall be distributed within the later of five years after his death or after the death of his Beneficiary, unless another form of payment was already in effect at the time of his death, in which case benefits may be made in accordance with such form of payment. Benefits may not be immediately distributed prior to the Participant's Normal Retirement Date unless the Participant consents in writing, except as provided in Section 8.6. Anything in this Article VIII to the contrary notwithstanding, no method of distribution shall be made under this Article which would result in payment of benefits over a period longer than the joint life expectancy of the Participant and his Beneficiary/Contingent Annuitant or which would otherwise violate the incidental death benefit requirements of Code Section 401(a)(9) and regulations issued thereunder. (c) If a married Participant elects to receive his Retirement Benefit in any form other than the normal form for married individuals as described in Section 8.1(a) or under the Joint and Survivor annuity form described in Section 8.3 with his Spouse as the Contingent Annuitant, then such election shall no take effect unless either: (i) the Participant's Spouse consents in writing to such election and the Spouse's consent acknowledges the effect of such election and is witnessed by a notary public or Plan representative, or (ii) it is established to the satisfaction of the Retirement Board that the Participant has no Spouse, or that the Spouse's consent cannot be obtained because the Spouse cannot be located, or because of such other circumstances as may be prescribed in regulations issued pursuant to Code Section 417. (d) It is the intent of the Plan that all benefits be paid promptly when due. In the absence of any inability to determine the amount of benefit payable or the eligibility for a benefit due to the lack of adequate information on date of birth of Participant or Spouse, the first benefit shall be paid no later than the 60th day after the close of the latest Plan Year in which: (i) the Participant attains age 65; (ii) the Participant reaches the 10th anniversary of his date of commencement of participation in the Plan, or (iii) the Participant's Service Termination Date occurs. 8.6 Involuntary Cash-Out Provision. If the Actuarial Equivalent present value of any Retirement Benefit, inclusive of a Participant's Prior Participant Account, is $3,500 or less and the benefit has not yet commenced, the Retirement Board shall distribute a lump sum payment of such Actuarial Equivalent present value to the appropriate individual as soon as practicable following the Participant's Service Termination Date, in lieu of all other benefits hereunder. 8.7 Restrictions on Distributions. This Section 8.7 shall apply to the amount of Benefits under this Plan for any Participant who is considered a Restricted Participant as defined hereunder. Such Benefits shall be limited to an amount equal to the payments that would have been made on behalf of the Restricted Participant under the life annuity form of payment described in Section 8.4 that is the Actuarial Equivalent of the Restricted Participant's Accrued Benefit under the Plan. For purposes of this Section 8.7, the term Restricted Participant shall mean all highly compensated employees as defined in Code Section 414(q) and highly compensated former employees. In any one Plan Year, the total number of Participants whose benefits are subject to restriction under this Section 8.7 is hereby limited by the Plan to a group of not less than 25 highly compensated employees and highly compensated former employees with the greatest Earnings. For purposes of this Section 8.7, the term Benefit shall include Retirement Benefit provided by the Plan plus loans in excess of the amounts set forth in Code Section 72(p)(2)(A), any periodic income, any withdrawal values payable to a living Participant and any death benefits not provided for by insurance on the Participant's life. The limitations set forth in this Section 8.7 shall not restrict the current payment of the full amount of Retirement Benefit provided by the Plan if: (a) after payment to a Restricted Participant of all of the Benefits described above, the value of Plan assets equals or exceeds 110% of the value of current liabilities, as defined in Code Section 412(l)(7), (b) the value of the Benefits described above for a Restricted Participant is less than 1% of the value of current liabilities, as defined in Code Section 412(l)(7), or (c) the value of the Restricted Participant's benefits does not exceed three thousand five hundred dollars ($3,500). 8.8 Increased Payments With Respect to Certain Retired Members. (a) Commencing July 1, 1981, the amount of all Retirement Benefits, including Contingent Annuitant benefits and Spouse's death benefits payable with respect to a Participant who had died prior to January 1, 1980, were increased by 1% for each full 12- month period elapsed between the effective date of the benefit and December 31, 1980. In the case of a Participant who had retired or died prior to July 1, 1973, there was an additional increase of 15%. The minimum increase payable hereunder shall be $10 per month. (b) Commencing January 1, 1984, the amount of all Retirement Benefits being paid to Participants who retired prior to August 15, 1983, including Contingent Annuitant benefits and Spouse's death benefits being paid as of that date, were increased by 7%. The minimum increase payable hereunder shall be $10 per month. (c) Commencing January 1, 1987, the amount of all Retirement Benefits being paid to Participants who retired prior to June 15, 1987, including Contingent Annuitant benefits and Spouse's death benefits being paid as of that date, were increased by 5%. The minimum increase payable hereunder shall be $10 per month. (d) Commencing July 1, 1992, the amount of all Retirement Benefits being paid to Participants who retired under the Plan between July 1, 1987 and June 30, 1992, including Contingent Annuitant benefits and Spouse's death benefits being paid as of that date were increased by 4%. Commencing July 1, 1992, the amount of all Retirement Benefits being paid to Participants who retired under the Plan prior to July 1, 1987, including Contingent Annuitant benefits and Spouse's death benefits being paid as of that date, were increased by 8%. The minimum increase hereunder shall be $10 per month. 8.9 Direct Rollover Provision. (a) This Section 8.9 shall apply to distributions made on or after January 1, 1993. Notwithstanding any provision of the Plan to the contrary that would otherwise limit a distributee's election under this Section 8.9, a distributee may elect, at the time and in the manner prescribed by the Retirement Board to have any portion of an eligible rollover distribution paid directly to an eligible retirement plan specified by the distributee in a direct rollover. (b) Definitions. (i) Eligible rollover distribution: An eligible rollover distribution is any distribution of all or any portion of the balance to the credit of the distributee, except that an eligible rollover distribution does not include: any distribution that is one of a series of substantially equal periodic payments (not less frequently than annually) made for the life (or life expectancy) of the distributee or the joint lives (or the joint life expectancies) of the distributee and the distributee's designated beneficiary, or for a specified period of ten or more years; any distribution to the extent such distribution is required under Code Section 401(a)(9); and the portion of any distribution that is not includible in gross income (determined without regard to the exclusion for net unrealized appreciation with respect to Employer securities). (ii) Eligible retirement plan: An eligible retirement plan is an individual retirement account described in Code Section 408(a), an individual retirement annuity described in Code Section 408(b), an annuity plan described in Code Section 403(a) or a qualified trust described in Code Section 401(a), that accepts the distributee's eligible rollover distribution. However, in the case of an eligible rollover distribution to the surviving Spouse, an eligible retirement plan is an individual retirement account or individual retirement annuity. (iii) Distributee: A distributee includes an Employee or former Employee. In addition, the Employee's or former Employee's surviving Spouse and the Employee's or former Employee's Spouse or former Spouse who is the alternate payee under a qualified domestic relations order, as defined in Code Section 414(p), are distributees with regard to the interest of the Spouse or former Spouse. (iv) Direct rollover: A direct rollover is a payment by the Plan to the eligible retirement plan specified by the distributee. ARTICLE IX RETIREMENT BOARD 9.1 Responsibility for Plan and Trust Administration. The Employer shall save the sole authority to appoint and remove the Trustee, any investment manager which may be provided for under the Trust, and to amend or terminate, in whole or in part this Plan or the Trust. The Employer, through its Retirement Board, shall have the responsibility for the administration of this Plan, which is specifically described in this Plan and the related Trust Agreement. The Employer shall be the "named fiduciary" for purposes of the Code and ERISA. 9.2 Retirement Board. The Plan shall be administered by the Employer through the Retirement Board which is appointed by the Board of Trustees. The Retirement Board shall consist of five or more members who are officers of any Participating Employer or any affiliate or subsidiary and who are appointed by and serve at the pleasure of the Board of Trustees. Any member of the Retirement Board may resign by delivering his written resignation to the Board and the Secretary of the Retirement Board. 9.3 Agents of the Retirement Board. The Retirement Board may delegate specific responsibilities to other persons as the Retirement Board shall determine. The Retirement Board may authorize one or more of their number, or any agent, to execute or deliver any instrument or to make any payment in their behalf. The Retirement Board may employ and rely on the advice of counsel, accountants, the Actuary, and such other persons as may be necessary in administering the Plan. 9.4 Retirement Board Procedures. The Retirement Board may adopt such rules as it deems necessary, desirable, or appropriate. All rules and decisions of the Retirement Board shall be uniformly and consistently applied to all Participants in similar circumstances. When making a determination or calculation, the Retirement Board shall be entitled to rely upon information furnished by a Participant, Spouse or Beneficiary, the Employer, the legal counsel of the Employer, the Actuary, or the Trustee. The Retirement Board may act at a meeting or in writing without a meeting. The Retirement Board shall elect one of its members as chairman, appoint a secretary, who may or may not be a Retirement Board member, and advise the Trustee of such actions in writing. The secretary shall keep a record of all meetings and forward all necessary communications to the Employer, the Trustee or the Actuary. The Retirement Board may adopt such bylaws and regulations as it deems desirable for the conduct of its affairs. All decisions of the Retirement Board shall be made by the vote of the majority including actions in writing taken without a meeting. 9.5 Administrative Powers of the Retirement Board. The Retirement Board may from time to time establish rules for the administration of the Plan. Except as otherwise herein expressly provided, the Retirement Board will have the exclusive right and discretionary authority, to the fullest extent provided by law, to interpret the Plan and decide any matters arising hereunder in the administration and operation of the Plan, and any interpretations or decisions so made will be conclusive and binding on all persons having an interest in the Plan; provided, however, that all such interpretations and decisions will be applied in a uniform and non-discriminatory manner to all Employees. The Retirement Board shall have no right to modify any provisions of the Plan as herein set forth. 9.6 Benefit Claims Procedures. All claims for benefits under the Plan shall be in writing and shall be submitted to the Retirement Board member designated as Retirement Board Secretary by the Retirement Board. If any application for payment of a benefit under the Plan shall be denied, the Retirement Board shall notify the claimant within 90 days of such application setting forth the specific reasons therefore and shall afford such claimant a reasonable opportunity for a full and fair review of the decision denying his claim. If special circumstances require an extension of time for processing the claim, the individual will be furnished with a written notice of the extension prior to the termination of the initial 90-day period. In no event shall such extension exceed a period of 90 days from the end of such initial period. The extension notice shall indicate the special circumstances requiring an extension of time and the date by which the Retirement Board expects to render its decision. Notice of such denial shall set forth, in addition to the specific reasons for the denial, the following: (a) reference to pertinent provisions of the Plan; (b) such additional information as may be relevant to the denial of the claim; (c) an explanation of the claims review procedure; and (d) notice that such claimant may request the opportunity to review pertinent Plan documents and submit a statement of issues and comments. Within 60 days following notice of denial of his claim, upon written request made by any claimant for a review of such denial to the Retirement Board Secretary, the Retirement Board shall take appropriate steps to review its decision in light of any further information or comments submitted by such claimant. The Retirement Board shall render a decision within 60 days after the claimant's request for review and shall advise said claimant in writing of its decision on such review, specifying its reasons and identifying appropriate provisions of the Plan. If special circumstances require an extension of time for processing, a decision will be rendered as soon as possible, but not later than 120 days after receipt of a request for the review. If the extension of time for review is required because of special circumstances, written notice of the extension shall be furnished to the claimant prior to the commencement of the extension. If the decision is not furnished within such time, the claim shall be deemed denied on review. The decision on review shall be in writing and shall include specific reasons for the decision, written to the best of the Retirement Board's ability in a manner calculated to be understood by the claimant without legal or actuarial counsel, as well as specific references to the pertinent Plan provisions on which the decision is based. In the event of continued disagreement, the claimant may thereafter appeal to the Employer, whose decision is final. 9.7 Certification of Benefits. Subject to the provisions of this Plan, it will be the duty of the Retirement Board to compute and certify to the Trustees the amount of Retirement Benefit payable hereunder to any Participant, Spouse, Beneficiary or Contingent Annuitant. 9.8 Designation of Actuary. The Retirement Board will designate an Actuary to make all actuarial calculations required in connection with the Plan. 9.9 Reliance on Reports and Certificates. The Employer (or the Retirement Board if so designated by the Employer) will be entitled to rely conclusively upon all tables, valuations, certificates, opinions, and reports which may be furnished by the Actuary, or any accountant, controller, counsel, or other person who is employed or engaged for such purposes and shall exercise the authority and responsibility as it deems appropriate to comply with all of the legal and governmental regulations affecting this Plan. 9.10 Other Retirement Board Powers and Duties. The Retirement Board shall have such duties and powers as may be necessary to discharge its duties hereunder, including, but not by way of limitation, the following: (a) to prescribe written procedures to be followed by Participants, Spouses, Contingent Annuitants and Beneficiaries filing applications for benefits; (b) to prepare and distribute, in such manner as the Retirement Board determines to be appropriate, information explaining the Plan; (c) to receive from the Employer and from Participants such information as shall be necessary for the proper administration of the Plan; (d) to furnish the Employer, upon request, such annual reports with respect to the administration of the Plan as are reasonable and appropriate; (e) to receive and review the periodic valuation of the Plan made by the Actuary; and (f) to receive, review and keep on file (as it deems convenient or proper) reports of benefit payments by the Trustee and reports of disbursements for expenses directed by the Retirement Board. The Retirement Board shall have no power to add to, subtract from or modify any of the terms of the Plan, or to change or add to any benefits provided by the Plan, or to waive or fail to apply any requirements of eligibility for a retirement benefit under the Plan. 9.11 Compensation of Retirement Board. No member of the Retirement Board who is an Employee will receive any compensation for his services as such, but will be reimbursed for reasonable expenses incident to the performance of such services. The reimbursement of expenses shall be paid in whole or in part by the Employer, and any expenses not paid by the Employer shall be paid by the Trustee out of the principal or income of the Trust Fund. 9.12 Member's Own Participation. No member of the Retirement Board may act, vote, or otherwise influence a decision of the Retirement Board specifically relating to his own participation under the Plan. 9.13 Liability of Retirement Board Members. No member of the Retirement Board will be liable for any act of omission or commission except as provided by federal law. 9.14 Indemnification. The Board of Trustees of the Employer, the Retirement Board and the individual members thereof shall be indemnified by the Employer and not the Trust Fund against any and all expenses, costs, and liabilities arising by reason of any act or failure to act, unless such act or failure to act is judicially determined to be gross negligence or willful misconduct. ARTICLE X FUNDING AND CONTRIBUTIONS 10.1 Establishment of Fund. The Fund shall be held and administered by the Trustee in accordance with the terms of the Trust. The Fund shall hold all contributions made by the Employer and earnings and other income attributable thereto. All benefits payable under the Plan shall be disbursed from the Fund. 10.2 Contributions to the Fund; Plan Expenses. The Employer will contribute to the Fund such sums and at such times as may be determined by the Board in accordance with the funding method and policy to be established by the Board which are consistent with Plan objectives. The Board, in consultation with the Actuary and the Retirement Board, shall have the right to change the method of funding, subject only to any contractual restrictions of the existing method of funding. Forfeitures arising from termination of service will be used to reduce Employer contributions and will not be applied to increase any benefits under the Plan. Except as provided in Section 10.3 and Article XII, all contributions when made to the Fund and all property and assets of the Fund, including income from investments and from all other sources, will be retained for the exclusive benefit of Participants, Spouses, Contingent Annuitants and Beneficiaries included in the Plan and will be used to pay benefits provided hereunder or to pay expenses of administration of the Plan and the Fund to the extent not paid by the Employer. 10.3 Contributions Conditional. Each Employer contribution to the Plan is expressly conditioned on its deductibility. If any Employer contribution is deemed to be nondeductible or made by the Employer by a mistake of fact, such contribution shall be returned to the Employer within one year of the date of the disallowance of such deduction or the date the contribution was made to the Fund, respectively. 10.4 Employee Contributions. No Employee will be required or permitted to make any contributions under this Plan. ARTICLE XI FIDUCIARY RESPONSIBILITIES 11.1 Basic Responsibilities. Any Fiduciary under the Plan, whether specifically designated or not, shall: (a) discharge all duties solely in the interest of Participants, Spouses, Contingent Annuitants and Beneficiaries and for the exclusive purpose of providing benefits and defraying reasonable administrative expenses under the Plan; (b) discharge his responsibilities with the care, skill, prudence, and diligence a prudent man would use in similar circumstances; and (c) conform with the provisions of the Plan. No person who is ineligible by law will be permitted to serve as Fiduciary. 11.2 Actions of Fiduciaries. Any Fiduciary: (a) may serve in more than one fiduciary capacity with respect to the Plan; (b) may employ one or more persons to render advice with regard to or to carry out any responsibility that such Fiduciary has under the Plan; and (c) may rely upon any discretion, information, or action of any other Fiduciary, acting within the scope of its responsibilities under the Plan, as being proper under the Plan. 11.3 Fiduciary Liability. No Fiduciary shall be personally liable for any losses resulting from his action except as provided by federal law. Each Fiduciary shall have only the authority and duties which are specifically allocated to him, shall be responsible for the proper exercise of his own authority and duties, and shall not be responsible for any act or failure to act of any other Fiduciary. ARTICLE XII AMENDMENT AND TERMINATION 12.1 Right to Amend or Terminate. The Employer, with the written approval of the Board, reserves the right to amend, modify, suspend, or terminate the Plan in whole or in part at any time. No amendment will be effective unless the Plan, as so amended, is for the exclusive benefit of Participants, Spouses, Contingent Annuitants and Beneficiaries, and no amendment will deprive any Participant without his consent of any benefit to which he was previously entitled, provided that any and all amendments may be made which are necessary to maintain the qualification of the Plan under the Code and provided further that such amendments may be retroactively effective. The Plan shall not be automatically terminated by any Employer's acquisition by or merger or consolidation into any other corporation. In the event of a reorganization, consolidation, dissolution or merger of an Employer, the Plan can be continued by the successor, and in such event the successor shall be substituted for such Employer and shall assume all of the Plan liabilities and all of the powers, duties and responsibilities of such Employer under the Plan. 12.2 Partial Termination. Upon a partial termination of the Plan with respect to a group of Participants, as determined by a ruling of the Internal Revenue Service as to which all rights to appeal have expired, the Employer shall direct the Actuary to determine the proportionate share of the assets for Participants affected by such partial termination. After such proportionate share has been determined, the Trustees shall segregate the assets of the Fund allocable to such group of Participants for payment of benefits in accordance with the provisions of Section 12.3. 12.3 Vesting and Distribution of Funds Upon Termination. Upon termination of the Plan by the Employer, in whole or in part, all affected Participants will become fully vested and entitled to their Accrued Benefits under the Plan. In such event, the assets in the Fund (or the portion of the Fund determined in accordance with Section 12.2) will be allocated pursuant to Regulations as follows: (a) There shall first be credited to each Participant who was receiving retirement income or who was eligible to receive retirement income at least three years prior to the date of Plan termination and to each Spouse and Beneficiary who was receiving retirement income or who was eligible to receive retirement income at least three years prior to the date of Plan termination an amount which will provide for him the amount of retirement income then accrued to him under the Plan, but not in excess of the benefit insured by the Pension Benefit Guaranty Corporation. (b) There shall next be credited to each Participant who was receiving retirement income or who was eligible to receive retirement income on the date of Plan termination and to each Spouse and Beneficiary who was receiving retirement income or who was eligible to receive retirement income on the date of Plan termination an amount which will provide for him the amount of retirement income then accrued to him under the Plan, but not in excess of the benefit insured by the Pension Benefit Guaranty Corporation. (c) There shall next be credited to each other Participant who, on the date on which the Plan shall terminate, is eligible for Retirement Benefits in accordance with Article VI an amount which will provide for him the amount of the retirement income then accrued to him under the Plan, but not in excess of the benefit insured by the Pension Benefit Guaranty Corporation. (d) There shall next be credited to each other Participant who would be entitled to additional retirement income in accordance with (a), (b), and (c) above, were such additional income not in excess of the amount insured by the Pension Benefit Guaranty Corporation, an amount which will provide for him the amount of retirement income then accrued to him under the Plan. (e) There shall next be credited to each other Participant an amount which will provide for him the amount of retirement income then accrued to him under the Plan. Allocation in any of the above classes shall be adjusted for any allocation made to the same Participant under a prior class. 12.4 Determination of Funds Upon Termination. (a) The application of the Fund on the foregoing basis shall be calculated as of the date on which the Plan shall terminate. When the calculation shall be completed, the respective interest in the Fund will be distributed to or on behalf of the respective Participants, Spouses and Beneficiaries under the Plan in the order stated in Section 12.3 only after the Employer has sent written notice to the Trustee, that all of the applicable requirements governing the termination of qualified retirement plans have been, or are being complied with or that appropriate authorizations, waivers, exemptions or variances have been, or are being, obtained. (b) If the assets in the Fund on the date the Plan is terminated are not sufficient to provide in full the amounts required within classes (a), (b), (c), and (d) of Section 12.3, any benefit in excess of $10,000 paid within a 12-month period during the 36- month period immediately preceding the date of termination of the Plan to a Participant, Spouse or Beneficiary who owns 10% or more of the outstanding voting stock of any Employer may be deemed a part of the Fund for purposes of allocation. (c) If the assets are not sufficient to provide in full for the amounts required for a class in the order listed in Section 12.3, the balance of the assets shall be allocated to each member of a class in the proportion which his amount bears to the total amount in such class. (d) Distribution upon termination of the Plan may be in the form of an annuity contract, cash, or securities or other assets in kind as determined by the Retirement Board in a uniform nondiscriminatory manner and applicable to all Participants. (e) Any funds remaining after the satisfaction of all liabilities to Participants, Spouses and Beneficiaries under the Plan shall be returned to the Employer. 12.5 Restriction on Benefits. In the event of plan termination, the benefit of any highly compensated employee as defined in Code Section 414(q) and highly compensated former employee is limited to a benefit that is nondiscriminatory under Code Section 401(a)(4). 12.6 Right to Accrued Benefits. Any other provision of the Plan notwithstanding, upon termination or partial termination of the Plan, the right of each Participant to benefits accrued to the date of such termination or partial termination to the extent then funded or to the extent guaranteed by the Pension Benefit Guaranty Corporation shall be nonforfeitable. ARTICLE XIII GENERAL PROVISIONS 13.1 Plan Voluntary. Although it is intended that the Plan shall be continued and that contributions shall be made as herein provided, this Plan is entirely voluntary on the part of each Employer and the continuance of this Plan and the payment of contributions hereunder are not to be regarded as contractual obligations of any Employer, and no Employer guarantees or promises to pay or to cause to be paid any of the benefits provided by this Plan. Each person who shall claim the right to any payment or benefit under this Plan shall be entitled to look only to the Fund for any such payment or benefit and shall not have any right, claim, or demand therefore against any Employer, except as provided by federal law. The Plan shall not be deemed to constitute a contract between any Employer and any Employee or to be a consideration for, or an inducement for, the employment of any Employee by any Employer. Nothing contained in the Plan shall be deemed to give any Employee the right to be retained in the service of any Employer or to interfere with the right of any Employer to discharge or to terminate the service of any Employee at any time without regard to the effect such discharge or termination may have on any rights under the Plan. 13.2 Payments to Minor and Incompetents. If any Participant, Spouse or Beneficiary entitled to receive any benefits hereunder is a minor or is deemed by the Retirement Board or is adjudged to be legally incapable of giving valid receipt and discharge for such benefits, they will be paid to such person or institution as the Retirement Board may designate or to the duly appointed guardian. Such payment shall, to the extent made, be deemed a complete discharge of any liability for such payment under the Plan. 13.3 Non-Alienation of Benefits. No amount payable to, or held under the Plan for the account of, any Participant shall be subject in any manner to anticipation, alienation, sale, transfer, assignment, pledge, encumbrance, or charge, and any attempt to so anticipate, alienate, sell, transfer, assign, pledge, encumber, or charge the same shall be void; nor shall any amount payable to, or held under the Plan for the account of, any Participant be in any manner liable for his debts, contracts, liabilities, engagements, or torts, or be subject to any legal process to levy upon or attach, except as may be provided under a qualified domestic relations order as defined in Code Section 414(p). The Retirement Board shall establish a procedure to determine the status of a judgement, decree or order as a qualified domestic relations order and to administer Plan distributions in accordance with qualified domestic relations orders. Such procedure shall be in writing, shall include a provision specifying the notification requirements enumerated in Code Section 414(p), shall permit an alternate payee to designate a representative for receipt of communications from the Retirement Board and shall include such other provisions as the Retirement Board shall determine, including provisions describing the interest rate to be used in making present value determinations as well as provisions required under regulations promulgated by the Secretary of the Treasury. 13.4 Evidence of Survival. If the Retirement Board, or the Trustees with the assistance of the Retirement Board, cannot make payment of any amount to, or on behalf of, a Participant within five years after such amount becomes payable because the identity or whereabouts of such Participant cannot be ascertained, the Retirement Board, at the end of such five-year period, may direct that all unpaid amounts which would have been payable to or on behalf of such Participant be paid to the legal Spouse of the Participant if found and living at such time, or if such legal Spouse cannot be found or is not living at such time, in equal shares to such of the children of the Participant who can be found and are living at such time, or if none of such children can be found or if none are living at such time, to such other relative or relatives of the Participant as the Retirement Board may deem proper. 13.5 Use of Masculine and Feminine; Singular and Plural. Wherever used in this Plan, the masculine gender will include the feminine gender and the singular will include the plural, unless the context indicates otherwise. 13.6 Merger, Consolidation, or Transfer. In the event that the Plan is merged or consolidated with any other plan, or should the assets or liabilities of the Plan be transferred to any other plan, each Participant shall be entitled to a benefit immediately after such merger, consolidation, or transfer if the Plan should then terminate equal to or greater than the benefit he would have been entitled to receive immediately before such merger, consolidation, or transfer if the Plan had then terminated. 13.7 Leased Employees. Any individual who performs services for the Employer and who, by application of Code Section 414(n)(2) and regulations issued pursuant thereto, would be considered a "leased employee", shall, for purposes of the requirements enumerated in Code Section 414(n)(3), be considered an Employee of the Employer with regard to services performed after December 31, 1986. When the total of all leased employees constitutes less than 20% of the Employer's non-highly compensated work force within the meaning of Code Section 414(n)(5)(c)(ii), however, a "leased employee" shall not be considered an Employee of the Employer if the organization from which the individual is leased maintains a qualified safe harbor plan (as defined in Code Section 414(n)(5)) in which such individual participates. "Leased employees" who are deemed to be Employees of the Employer for purposes of this Section 13.7 shall not be eligible to participate in the Plan unless specifically provided for in Article II. 13.8 Construction of Agreement. This Plan shall be administered, construed, and enforced according to the laws of the Commonwealth of Massachusetts; provided, however, wherever applicable, the provisions of ERISA shall govern and in such event the laws of the United States of America shall be applied and to the extent necessary, its courts shall have competent jurisdiction. ARTICLE XIV TOP-HEAVY PLAN PROVISIONS 14.1 General Rule. For any Plan Year for which this Plan is a "top-heavy plan" as defined in Section 14.5, any other provisions of the Plan to the contrary notwithstanding, the Plan shall be subject to the following provisions: (a) The vesting provisions of Section 14.2. (b) The minimum benefit provisions of Section 14.3. (c) The limitation on benefits set by Section 14.4. 14.2 Vesting Provisions. Each Participant who (i) has completed at least an Hour of Service during any Plan Year in which the Plan is top- heavy and (ii) has completed the number of Years of Vesting Service specified in the following table, shall have a nonforfeitable right to the percentage of his Accrued Benefit specified as follows: Nonforfeitable Percentage Years of Vesting Service of Accrued Benefit Less than 1 0% 1 but less than 220% 2 but less than 340% 3 but less than 460% 4 but less than 580% 5 or more 100% If the Plan ceases to be "top-heavy", each Participant with three or more Years of Service, whether or not consecutive, shall have the right to elect to remain under the vesting schedule hereunder or to have the vesting provisions of Section 6.2 be applicable. Each such Participant shall have the right to elect the applicable schedule within 60 days after the day the Participant is issued written notice by the Retirement Board, or as otherwise provided in accordance with regulations issued under the provision of the Code, relating to changes in the vesting schedule. For all other Participants, the vesting provisions of Section 6.2 shall be applicable once the Plan ceases to be "top heavy". This provision shall not cause a Participant's vested percentage to be reduced. 14.3 Minimum Benefit Provisions. Each Participant who (i) is a "non-key employee" (as defined in Section 14.7) and (ii) has completed 1,000 Hours of Service in any Plan Year shall be entitled to an annual retirement income equal to 2% of the Participant's average annual Compensation in the "testing period" multiplied by his Years of Service during which the Plan is top heavy, up to a maximum of 20%. For purposes of this Section 14.3, "testing period" means the period of five consecutive Years of Vesting Service during which the Participant had the highest aggregate Earnings, provided that Earnings for any Plan Year after the close of the Plan Year in which the Plan was last top-heavy shall be disregarded. 14.4 Limitation on Benefits. In the event that the Employer also maintains a defined contribution plan providing contributions on behalf of Participants in this Plan, one of the two following provisions shall apply: (a) If for the Plan Year this Plan would not be a "top-heavy plan" (as defined in Section 14.5) if "90 percent" were substituted for "60 percent," then the minimum benefit described in Section 14.3 means the lesser of 3% of average annual Earnings in the "testing period" multiplied by the Participant's Years of Service during which the Plan is "top heavy", up to a maxi- mum of 30%. (b) If for the Plan Year this Plan would continue to be a "top-heavy plan" (as defined in Section 14.5) if "90 percent" were substituted for "60 percent," then the denominator of both the defined contribution plan fraction and the defined benefit plan fraction shall be calculated as set forth in Section 3.3(b) for such Plan Year by substituting "1.0" for "1.25" in each place such figure appears, except with respect to any individual for whom there are no Employer contributions, forfeitures or voluntary contributions allocated or any accruals for such individual under the defined benefit plan. 14.5 Top-heavy Plan Definition. This Plan shall be a "top-heavy plan" for any Plan Year if, as of the determination date, the present value of the Accrued Benefits under the Plan for Participants (including former Participants) who are "key employees" (as defined in Section 14.6) exceeds 60 percent of the present value of Accrued Benefits for all Participants (excluding former "key employees"), or if this plan is required to be in an aggregation group which for such Plan Year is a "top-heavy group." For purposes of this Article XIV, (a) "Determination date" means for any Plan Year the last day of the immediately preceding Plan Year (except that for the first Plan Year the determination date means the last day of such Plan Year). (b) Present value of Accrued Benefits shall be determined as of the most recent valuation date that is within the 12-month period ending on the determination date and as described under the Code. (c) "Aggregate of the Accounts" shall mean the sum of (i) the Accounts determined as of the most recent Valuation Date that is within the 12-month period ending on the determination date, and (ii) the adjustment for contributions due as of the determination date, and as described in the regulations under the Code. (d) "Aggregation group" means the group of plans, if any, that includes both the group of plans that are required to be aggregated and the group of plans that are permitted to be aggregated. (i) The group of plans that are required to be aggregated (the "required aggregation group") includes: each plan of the Employer in which a key employee is a participant, including collectively-bargained plans; and each other plan of the Employer including collectively-bargained plans, which enables a plan in which a key employee is a participant to meet the requirements of the Code prohibiting discrimination as to contributions or benefits in favor of Employees who are officers, shareholders or the highly compensated or prescribing the minimum participation standards. (ii) The group of plans that are permitted to be aggregated (the "permissive aggregation group") includes the required aggregation group plus one or more plans of the Employer that is not part of the required aggregation group and that the Retirement Board certifies as constituting a plan within the permissive aggregation group. Such plan or plans may be added to the permissive aggregation group only if, after the addition, the aggregation group as a whole continues not to discriminate as to contributions or benefits in favor of officers, shareholders or the highly- compensated and to meet the minimum participation standards under the Code. (e) "Top-heavy group" means the aggregation group, if as of the applicable determination date, the sum of the present value of the cumulative accrued benefits for "key employees" under all defined benefit plans included in the aggregation group plus the aggregate of the accounts of "key employees" under all defined contribution plans included in the aggregation group exceeds 60% of the sum of the present value of the cumulative accrued benefits for all employees, excluding former "key employees," under all such defined benefit plans plus the aggregate accounts for all employees, under such defined contribution plans. If the aggregation group that is a top-heavy group is a required aggregation group, each plan in the group will be top-heavy. If the aggregation group that is a top-heavy group is a permissive aggregation group, only those plans that are part of the required aggregation group will be treated as top-heavy. If the aggregation group is not a top-heavy group, no plan within such group will be top-heavy. (f) In determining whether this Plan constitutes a "top-heavy plan", the Retirement Board shall make the following adjustments in connection therewith: (i) When more than one plan is aggregated, the Retirement Board shall determine separately for each plan as of each plan's determination date the present value of the accrued benefits or account balance. The results shall then be aggregated by adding the results of each plan as of the determination dates for such plans that fall within the same calendar year. (ii) In determining the present value of the Accrued Benefit or the amount of the account of any Employee, such present value or account shall include the dollar value of the aggregate distributions made to such Employee under the applicable plan during the five-year period ending on the determination date, unless reflected in the value of the accrued benefit or account balance as of the most recent valuation date. Such amounts shall include distributions to Employees which represented the entire amount credited to their accounts under the applicable plan. (iii) Further, in making such determination, such present value or such account shall include any rollover contribution (or similar transfer), as follows: (a)If the rollover contribution (or similar transfer) is initiated by the Employee and made to or from a plan maintained another employer the plan providing the distribution shall include such distribution in the value of such account; the plan accepting the distribution shall not include such distribution in the value of such account unless the plan accepted it before December 31, 1983. (b) If the rollover contribution (or similar transfer) is not initiated by the Employee or made from a plan maintained by another employer the plan accepting the distribution shall include such distribution in the present value or such account, whether the plan accepted the distribution before or after December 31, 1983; the plan making the distribution shall not include the distribution in the present value or such account. (iv) Further, in making such determination, in any case where an individual is a "non-key employee" (as defined in Section 14.7) with respect to an applicable plan, but was a "key employee" with respect to such plan for any prior plan year, any Accrued Benefit and any account of such Employee shall be altogether disregarded. For this purpose, to the extent that a key employee is deemed to be a "key employee" if he met the definition thereof within any of the four preceding plan years, this provision shall apply following the end of such period of time. (v) Further, in making such determination, the accrued benefit of an Employee other than a Key Employee shall be determined under (i) the method, if any, that uniformly applies for accrual purposes under all plans maintained by the Employer and its Affiliated Employers, or (ii) if there is no such method, as if such benefit accrued not more rapidly than the slowest accrual rate permitted under the fractional accrual rule of Section 411(b)(1)(C) of the Code. 14.6 Key Employee. The term "key employee" means any Employee or former Employee who would be considered a key employee under Section 416(i)(1) of the Code excluding any individual who has not performed services for the Employer or any of its Affiliated Employers during the five-year period ending on a particular "determination date". 14.7 Non-Key Employee. The term "non-key employee" means any Employee (and any beneficiary of an Employee) who is not a "key employee". An individual who has not performed services for the Employer or any of its Affiliated Employers during the five-year period ending on a particular "determination date", however, shall not be considered a "non-key employee". IN WITNESS WHEREOF, the Employer has caused this instrument to be executed by its officers thereunto duly authorized and its corporate seal to be hereunto affixed, as of the 21 day of December, 1994. EASTERN UTILITIES ASSOCIATES By /s/John R. Stevens John R. Stevens President ATTEST: /s/ William F. O'Connor William F. O'Connor Secretary (CORPORATE SEAL) ADDENDUM NUMBER ONE TO THE EMPLOYEES' RETIREMENT PLAN OF EASTERN UTILITIES ASSOCIATES AND ITS AFFILIATED COMPANIES The provisions set forth in the Plan document shall govern participation in the Plan and the calculation of benefits. The following provisions outlined in this Addendum shall set forth the rules specifically relating to participation and benefit accruals for employees of Newport Electric Corporation who are considered Employees hereunder as a result of the merger of this Plan into the Newport Electric Corporation Pension Plan effective as of January 1, 1991. To the extent not specifically indicated otherwise in the Addendum, the provisions of the Plan shall be applicable with respect to Employees who are employed by Newport Electric Corporation. I. DEFINITIONS A.0.0 "Actuarial Equivalent" shall mean, for the purpose of determining benefits described in this Addendum Number One, a benefit of equivalent value to another benefit determined on the basis of the factors set forth in Appendix B attached hereto. A.1.0 "Average Monthly Earnings" shall mean, other than for the purpose of determining a Participant's Death Benefit and Termination Benefit, the average of the Employee's Monthly Earnings received for the 60 consecutive calendar months of employment, or, in the case of a Participant who becomes or continues to be employed by the Employer on or after January 1, 1987, the 36 consecutive calendar months of employment, of his greatest compensation in the 120-month period immediately preceding his retirement or any earlier date on which he becomes entitled to an immediate or deferred benefit under the Plan, excluding from such five or three year period, as the case may be, any period of absence which does not cause a One Year Break in Service (for vesting purposes) and for which he does not receive Monthly Earnings and any period of service which is excluded from his Credited Service. In the case of a Participant who has not received Monthly Earnings for 60 (or 36, if applicable) consecutive calendar months of employment in the aforementioned 120-month period, Average Monthly Earnings means the average of his Monthly Earnings during all of his months of employment during such 120-month period, not to exceed a total of 60 (or 36, if applicable) months. A.1.1 "Average Annual Earnings" shall mean for purposes of determining a Participant's Death Benefit and Termination Benefit: (a) with respect to an Employee's service completed prior to January 1, 1972, "Average Annual Earnings" means the average of a Participant's compensation received during calendar years 1968, 1969 and 1970. (b) with respect to each calendar year of an Employee's Credited Service completed on and after January 1, 1972, "Average Annual Earnings" means 12 times the average of the Participant's Monthly Earnings received during the calendar year. A.1.2 "Death Benefit" shall mean, with respect to each Participant who has qualified for such benefit in accordance with the further provisions of this Addendum, an amount equal to the sum of (a) and (b), where it (a) is 2.5% of his Average Annual Earnings up to $3,000 plus 5% of his Average Annual Earnings over $3,000 for each year of Credited Service completed prior to January 1, 1972; plus (b) 3.75% of his Average Annual Earnings up to $6,000 plus 5% of his Average Annual Earnings over $6,000 for each year of Credited Service completed on and after January 1, 1972. A.1.3 "Interest". Each Participant's Death Benefit and Termination Benefit will be credited with interest at the rate of 3% until January 1, 1976, and 5% thereafter, compounded annually, from the January 1 next following the date such benefit is accrued to the first day of the month in which such benefits are withdrawn, or the Participant's date of retirement if earlier, provided, however, that if the Participant's date of retirement is his Early Retirement Date, his Death Benefit will be credited with interest to the first day of the month in which the earlier of his death or Annuity Starting Date occurs. A.1.4 "Monthly Earnings" shall mean an Employee's Earnings as payable on a monthly basis. If an Employee customarily completes less than 2,080 Hours of Service in a Plan Year, his Earnings for a Plan Year shall be deemed to be his Total Monthly Earnings received for the Plan Year multiplied by a fraction, the numerator of which is 2,080 and the denominator of which is his actual Hours of Service for the Plan Year, not in excess of 2,080. The Employee's Monthly Earnings shall be deemed to be 1/12th of such amount. A.1.5 "Termination Benefit" shall mean, with respect to each Participant who has qualified for such benefit in accordance with the further provisions of this Addendum, an amount equal to the sum of (a), (b) and (c), where it (a) is 2.5% of his Average Annual Earnings up to $3,000 plus 5% of his Average Annual Earnings over $3,000 for each year of Credited Service completed prior to January 1, 1972; plus (b) 3.75% of his Average Annual Earnings up to $6,000 plus 5% of his Average Annual Earnings over $6,000 for each year of Credited Service completed on and after January 1, 1972 and prior to January 1, 1982; plus (c) 3.75% of his Average Annual Earnings up to the maximum amount subject to tax under the Federal Insurance Contributions Act in each calendar year after December 31, 1981 (for calendar years commencing after December 31, 1990, the amount subject to old-age, survivors and disability insurance under the Federal Insurance Contribu- tions Act) plus 5% of his Average Annual Earnings in excess of such maximum amount during his Credited Service after December 31, 1981. II. SERVICE A.2.0 Years of Service. (a) One Year of Service shall be credited to an Employee for each Plan Year during which he is credited with at least 1,000 Hours of Service. (b) Subject to Section 2.2 of the Plan, Years of Service shall not include the following periods of employment: (i) Years of Service prior to September 1, 1974, if such years would have been disregarded pursuant to the break in service rules as in effect immediately prior to such date; (ii) Years of Service credited prior to January 1, 1971, unless the Employee is credited with at least three Years of Service after December 31, 1970; (iii) Years of Service prior to a One Year Break in Service unless the Employee is credited with a Year of Service subsequent to his return to employment; (iv) Years of Service disregarded under the terms of the Plan as in effect on December 31, 1985, with respect to a One Year Break in Service that occurred prior to January 1, 1986. (c) For the purposes of this Addendum, a One Year Break in Service shall mean a Plan Year during which an Employee is credited with less than 501 Hours of Service. (d) For the purpose of determining an Employee's eligibility to participate in the Plan, a Year of Service shall mean a "computation period" during which an Employee is credited with at least 1,000 Hours of Service. A computation period for eligibility purposes is initially the 12-month period beginning on an Employee's Employment Date. If an Employee does not complete a Year of Service during his initial computation period, then computation period shall mean the first Plan Year commencing on or after an Employee's first anniversary of employment and each Plan Year thereafter. (e) In the event that an Employee earns a Year of Service for eligibility purposes and incurs a One Year Break in Service, such service shall be recognized hereunder provided his Years of Service for vesting purposes for the same period are recognized pursuant to the break in service rules set forth in Section 2.2 of the Plan. A.2.1 Credited Service. (a) A Participant shall be credited with a year of Credited Service for each Plan Year in which he is credited with at least 2,080 Hours of Service. (b) For the purposes of determining Credited Service under this Addendum, the following periods of service will be disregarded: (i) All service completed prior to the date the Employee completed One Year of Service for eligibility purposes. (ii) All service disregarded in computing the Employee's Years of Service for vesting purposes. (iii) Any period of lay-off from employment in excess of six months. (iv) Service performed by the Employee with respect to which he received a distribution of his entire non- forfeitable Accrued Benefit in an amount not more than $3,500 upon termination of his participation in the Plan, unless the Employee had received a distribution in an amount less than the present value of his Accrued Benefit and upon again becoming a Participant, elects to repay to the Plan the full amount of his distribution with interest, and makes the full repayment, with interest at the rate prescribed by Section 411(a)(7)(C) of the Code, within 5 years of his date of reemployment. (v) Service performed by the Employee with respect to which he elected to receive a distribution of his Termination Benefit which was not less than the present value of his non-forfeitable Accrued Benefit upon termination of his participation in the Plan, unless the Employee, upon again becoming a Participant, elects to repay to the Plan the full amount of his distribution with interest, and makes the repayment with interest at the rate prescribed by Section 411(a)(7)(C) of the Code, within the next 12 months. (vi) Service performed by the Employee while he is in a class of employees not eligible to participate under this Plan. (c) If, upon termination of his participation in the Plan, an Employee elected to receive a distribution of his Termination Benefit which was less than the present value of his non-forfeitable Accrued Benefit, and he again becomes a Participant, the portion of his Accrued Benefit based on Credited Service prior to such distribution shall be multiplied by a fraction, the numerator of which is a portion of the present value of his non-forfeitable Accrued Benefit at the time of such termination of participation which was not distributed to him and the denominator of which is the Present Value of his non-forfeitable Accrued Benefit at the time of such termination of participation, unless the Employee, upon again becoming a Participant, elects to repay the Plan the full amount of his distribution with interest, and makes the repayment with interest at the rate prescribed by Section 411(a)(7)(C) of the Code before the earlier of: (i) the fifth anniversary of the Participant's Reemployment Date; and (ii) the date the Participant incurs five consecutive One Year Breaks in Service. (d) Except for the year in which an Employee initially becomes a Participant (or again becomes a Participant upon a rehire) or for the year in which a Participant retires, if a Participant completes less than 1,000 Hours of Service in a Plan Year he shall receive no Credited Service for that year. If, in the Plan Year in which an Employee initially becomes a Participant (or again becomes a Participant upon a rehire) or in which a Participant retires, a Participant completes less than 2,080 Hours of Service or, if in any other Plan Year, he completes 1,000 or more Hours of Service but less than 2,080 Hours, his Credited Service for such year shall be obtained by dividing his Hours of Service for such year by 2,080 and by rounding the resulting quotient up to the next highest tenth of a year, if such quotient is not an even multiple of a tenth of a year. A.3.1 Eligibility Requirements. (a) Any Employee of Newport Electric Corporation who is not eligible to participate in the Newport Electric Corporation Pension Plan on December 31, 1990, shall, subject to the eligibility requirements set forth in Section 2.1, become an Active Participant of the Plan. Such Employee shall not be eligible for any benefits described in this Addendum, but shall, pursuant to the foregoing provisions and the transfers provisions in Article II of the Plan, receive credit for his employment with Newport Electric Corporation. (b) Any Employee of Newport Electric Corporation hired on or after December 31, 1991, shall become an Active Participant of the Plan pursuant to Section 2.1 of the Plan. Such Employee shall not be subject to the provisions of this Addendum. (c) Notwithstanding the foregoing provisions, any Employee of Newport Electric Corporation who is a member of a collective bargaining agreement shall participate in the Plan, subject to the provisions of this Addendum and the applicable terms of the collective bargaining agreement. (d) Any other Employee of Newport Electric Corporation who is an Active Participant of the Newport Electric Corporation Pension Plan on December 31, 1990, shall participate in the Plan effective January 1, 1991 subject to the provisions of this Addendum and any applicable collective bargaining agreement. A.4.1 Transfers. In the event that an Employee of Newport Electric Corporation who is an Active Participant of the Newport Electric Corporation Pension Plan transfers employment to the Employer, such Active Participant shall cease to accrue any benefits pursuant to this Addendum and shall be eligible for and participate in the Plan pursuant to the provisions thereof; provided, however, if such Active Participant is a member of a collective bargaining unit, the terms of his participation shall be subject to the terms of the collective bargaining agreement. A.5.1 Normal Retirement Benefit. Subject to the minimum benefit provisions under this paragraph and the maximum benefit limitations under Section 3.3 of the Plan, the amount of monthly Retirement Benefit on the life annuity basis as described in Section 8.4 of the Plan to which a Participant is entitled to receive on his Normal Retirement Date is equal to: (a) 1.42% of the Participant's Average Monthly Earnings, multiplied by (b) the Participant's years of Credited Service. In no event shall a Participant's Retirement Benefit be less than the Retirement Benefit he accrued under the provisions of the Newport Electric Corporation Pension Plan as in effect on December 31, 1975. A.6.1 Early Retirement Benefit. (a) An Active Participant who either has attained age 55 or has completed 30 Years of Service may retire after satisfying such requirement and prior to his Normal Retirement Date, such date being his Early Retirement Date. (b) If the Active Participant has attained age 62 on his Early Retirement Date, the Retirement Benefit commencing on his Early Retirement Date shall be equal to his Accrued Benefit determined as of such date. (c) If the Active Participant has not attained age 62 on his Early Retirement Date but has attained age 55 and the sum of his age and Years of Service equals at least 85, the Retirement Benefit commencing on his Early Retirement Date shall be equal to his Accrued Benefit determined as of such date. (d) If the Active Participant has completed 30 Years of Service but has not attained age 55 on his Early Retirement Date, his retirement annuity shall be deferred to commence on the first day of the month coincident with or next following the date the Participant attains his 55th birthday and shall be equal to his Accrued Benefit determined as of his Early Retirement Date. Such Participant may, however, elect to have his retirement annuity commence on the first day of any calendar month between his Early Retirement Date and the first day of the month coincident with or next following his 55th birthday in an amount of Actuarial Equivalent Value to his Accrued Benefit commencing on the first day of the month coincident with or next following his 55th birthday. Such Actuarial Equivalent Value shall be calculated on the basis of the applicable factors in the Appendix. (e) If the Participant has attained age 55 but has not attained age 62 on his Early Retirement Date and the sum of his age and Years of Service does not equal at least 85, his Retirement Benefit shall be deferred to commence on his Normal Retirement Date and shall be equal to his Accrued Benefit determined as of his Early Retirement Date. Such Participant may, however, elect to have his Retirement Benefit commence on the first day of any calendar month between his Early Retirement Date and his Normal Retirement Date. In the event of such election, the Participant's Retirement Benefit shall be equal to the product of (i) and (ii) below; where: (i) equals the monthly amount of his Accrued Benefit determined as of his Early Retirement Date, and (ii) equals the percentage determined from the schedule below: Number of Years Benefit Commencement Date Precedes Normal Retirement Date Percentage 10 75% 9 78 8 81 7 84 6 87 5 90 4 94 3 or less 100 If the number of years by which the commencement date of the Retirement Benefit precedes Normal Retirement Date is not an integer, the percentage is determined by linear interpolation between the percentages for the two nearer integral number of years. (f) Notwithstanding any provision of the Plan and this Addendum Number One to the contrary, any reduction for a participant who is eligible for an annuity under a Group Annuity Contract applied to a Participant's Retirement Benefit as a result of his early retirement hereunder shall be applied in the same manner as described in Section 4.2. A.7.1 Postponed Retirement Benefit. If a Participant retires on a Postponed Retirement Date, he shall be entitled to a Retirement Benefit equal to the greater of (a) and (b) below: (a) his Accrued Benefit determined as of his Postponed Retirement Date; and (b) his Accrued Benefit determined as of his Normal Retirement Date increased by an amount which is Actuarially Equivalent in value to the monthly payments he would have received during the period between his Normal and Postponed Retirement Dates. A.8.1 Vested Termination. (a) A Participant who terminates employment with all Participating Employers prior to his Early Retirement Date shall be entitled to a paid-up monthly retirement annuity commencing on the date which otherwise would be his Normal Retirement Date in the amount which can be provided with his Termination Benefit with Interest. Each such Participant will be entitled to an additional monthly annuity to be provided for such Participant on his Normal Retirement Date in such amount as is necessary to provide a total monthly annuity equal to the Participant's Accrued Benefit as of his date of termination of employment or One Year Break in Service, if sooner. (b) (i) A vested Participant shall have the right to elect to receive (A) a lump sum payment equal to his Termination Benefit with Interest as of the date he terminated employment, or (B) a paid-up monthly retirement annuity in an amount which can be provided with his Termination Benefit with Interest in the form of the normal form of annuity described in Section 8.1 of the Plan. Notwithstanding the foregoing, however, an election by a married Participant of the lump sum or of an annuity in the normal form under Section 8.1(b) of the Plan shall be subject to spousal consent rules outlined in Section 8.5 of the Plan. Payment shall be made as soon as practicable following the Participant's termination of employment. An election to receive a Retirement Benefit pursuant to this paragraph shall be made within the 90-day period preceding payment and shall be made following the receipt by the Participant of the notice described in Section 8.2 of the Plan. (ii) In addition to the Termination Benefit, the Participant will receive, commencing on his Normal Retirement Date, a monthly Retirement Benefit, if any, equal to his Accrued Benefit (determined as of his termination of employment or One Year Break in Service, if sooner) reduced by the Actuarial Equivalent Value of his Termination Benefit with Interest. Such Actuarial Equivalent Value shall be computed on the basis of the 1979 George B. Buck Mortality Table for males rated back one year and an interest rate of seven percent per year. (c) If a vested Participant either incurs a One Year Break in Service or terminates his employment, and he had not reached the age or completed the service requirement for early retirement, he may elect to receive his benefit at any time after the first day of the month coincident with or next following his 55th birthday and prior to his Normal Retirement Date and receive a monthly Retirement Benefit in an amount equal to the product of his Accrued Benefit as of his date of termination of employment multiplied by the appropriate percentage from the schedule below: Number of Years Annuity Starting Date Precedes Normal Retirement Date Percentage 10 75.0% 9 78.0 8 81.0 7 84.0 6 87.0 5 90.0 4 94.0 3 95.0 2 97.0 1 98.5 0 100.0 A.9.1 Permanent and Total Disability Benefit. (a) A Participant shall be considered to be permanently and totally disabled if he is unable to engage in any gainful activity by reason of a medically determinable physical or mental impairment which can be expected to result in death or has lasted, or can be expected to last, for a continuous period of not less than 12 months, and shall be conditioned upon the Participant receiving disability benefits from the Social Security Administration. A Participant who has applied for disability benefits under the Social Security Act will be deemed eligible for such benefits pending disposition of his application by the Social Security Administration. (b) A Participant who incurs a permanent and total disability as defined in paragraph (a) above may elect to retire at any time prior to his Normal Retirement Date, with such date being known as his Disability Retirement Date. (c) A Participant who retires on a Disability Retirement Date shall be eligible to receive a Retirement Benefit commencing on his Normal Retirement Date. The amount of his monthly disability payments will be equal to his Accrued Benefit based on his Average Monthly Earnings and Credited Service computed as if he had continued in service until his Normal Retirement Date with Monthly Earnings equal to his last rate of Monthly Earnings immediately prior to his becoming permanently and totally disabled. In lieu of the benefit commencing on his Normal Retirement Date, the Participant may elect to receive monthly disability payments commencing on an Early Retirement Date which shall be the first day of any calendar month on or after his attainment of age 55. Such monthly amount shall be equal to his Accrued Benefit computed as if he had continued in service to his Early Retirement Date, multiplied by the applicable Early Retirement percentage for the number of years that the Annuity Starting Date precedes his Normal Retirement Date, as set forth in Paragraph A.6.1 of this Addendum. In the event of the death, prior to the commencement of disability benefit payments, a benefit shall be payable to his surviving Spouse in accordance with Paragraph A.10 of this Addendum, provided that the Participant became so disabled after his attainment of age 55 or after his completion of five Years of Service. If such deceased Participant is not survived by a Spouse or if he became permanently or totally disabled prior to age 55 and prior to five Years of Service, a Death Benefit shall be payable in accordance with Paragraph A.10(e) of this Addendum. In computing the amount of the Death Benefit, it shall be assumed that the Participant continued in service to his date of death with Monthly Earnings equal to his last rate of Monthly Earnings immediately prior to his becoming permanently and totally disabled. A.10.0 Pre-Retirement Death Benefits. (a) In the case of the death of a married Participant who (whose): (i) dies while in the employ of a Participating Employer on or after August 23, 1984 after he has attained age 55 or has completed at least five Years of Service, or (ii) retired with a deferred Early Retirement Benefit, or (iii) employment was terminated on or after January 1, 1976 but before August 23, 1984 after the completion of 10 Years of Service and who dies on or after January 1, 1986, or (iv) employment was terminated on or after August 23, 1984 after he had become vested in his Accrued Benefit, but in each case before his Annuity Starting Date, a Spouse benefit will be payable to his surviving Spouse for life, provided that the Spouse shall have been married to the Participant during the one-year period preceding his death. (b) The spouse benefit shall commence on what would have been the Participant's Normal Retirement Date. However: (i) if the Participant dies in active service or while accruing service under Paragraph A.9.1 of this Addendum after having met the requirements for early retirement, or after retiring early but before payments commence, or in active service on or after January 1, 1988 after completing 10 or more Years of Service, the Spouse may elect to begin receiving payments as of the first day of any month following the Participant's date of death and prior to what would have been his Normal Retirement Date; and (ii) in the case of the death of any other Participant prior to attaining his Normal Retirement Date, the Spouse may elect to begin receiving payments as of the first day of any month following what would have been the Participant's 55th birthday (or following his date of death, if later) and prior to what would have been his Normal Retirement Date. (c) The spouse benefit shall be equal to: (i) in the case of the death of an Active Participant who is in the employ of a Participating Employer on or after January 1, 1988 and who has completed 10 Years of Service, 1/2 of the Participant's Accrued Benefit as of the date of his death, reduced by 1/8% for each month in excess of 60 that the Spouse is younger than the Participant; and (ii) in the case of any other Participant, the amount of benefit the Spouse would have received if the Retirement Benefit to which the Participant was entitled at his date of death had commenced on his Normal Retirement Date in the form of a Joint and Survivor Option (with a continuation of an amount equal to 50% of the Participant's adjusted benefit to his Spouse upon death) and the Participant had died immediately thereafter, provided, however, if the Spouse elects to commence payment prior to the Participant's Normal Retirement Date, the Spouse benefit shall be determined on the basis of the amount of Retirement Benefit to which the Participant would have been entitled if he had requested benefit commencement at that earlier date, reduced in accordance with Paragraph A.6.1 or A.8.1 of this Addendum, as applicable. If prior to his Annuity Starting Date a Participant has elected an optional form of retirement benefit which provides for monthly payments to his Spouse for life in an amount equal to at least 50% but not more than 100% of the monthly amount payable under the option for the life of the Participant, the Spouse benefit shall be determined on the basis of the amount of benefit the Spouse would have received if the benefit to which the Participant was entitled at his date of death had commenced on the date elected by the Spouse in the optional form of benefit elected by the Participant, if the resulting benefit provides the Spouse with a greater benefit than that provided under clause (i) or (ii) above, as the case may be. (d) In lieu of the monthly benefit provided under the foregoing subparagraphs of this Paragraph A.10.0, the deceased Participant's Spouse may elect to receive the amount of the Participant's Death Benefit as of the date of his death. In addition, a reduced monthly benefit shall be paid to the Spouse, which shall be equal to the benefit computed under subparagraph (c) above, reduced by an annuity of Actuarial Equivalent Value to the Death Benefit. Such Actuarial Equivalent Value shall be computed on the basis of the UP- 1984 Mortality Table rated back three years and interest rates specified by the Pension Benefit Guaranty Corporation as applicable to pension plans terminated as of the date of the Participant's death. (e) Except as provided under any optional form of annuity elected by the Participant, upon a Participant's death (for whom a Spouse benefit as described in the above subparagraphs is not in effect), his Beneficiary or his estate, if no named Beneficiary survives him, will be entitled to a payment of his Death Benefit with Interest to the first day of the month in which the earlier of his death or Retirement Date occurred, reduced by the sum of any monthly retirement payments the Participant may have received prior to his death. However, if such Partici- pant's retirement date is his Early Retirement Date, his Death Benefit will be credited with Interest to the first day of the month in which the earlier of his death or the commencement date of his retirement annuity occurred. A.11.0 Optional Forms of Payment. (a) Prior to an Annuity Starting Date, a Participant may elect, pursuant to the applicable provisions of the Plan, an optional form of payment for his Retirement Benefit as may be available under Article VIII of the Plan and this Paragraph A.11.0 of this Addendum. (b) Contingent Annuitant Option. (i) A Participant may elect, by submitting an election form to the Committee, to have his Retirement Benefit converted to the Actuarial Equivalent of the normal form under Section 8.1 of the Plan and paid monthly during his life with the provision that after his death, 50%, 66-2/3% or 100% of such reduced Retirement Benefit will be payable to his Contingent Annuitant during the remaining life of such Contingent Annuitant. (ii) If a Participant elects the Contingent Annuitant Option and his Contingent Annuitant dies before such Participant's benefit actually commences and the Participant does not change his election in accordance with Section 8.2, his Retirement Benefit shall be paid under the normal form under Section 8.1. (iii) If a Participant elects the Contingent Annuitant Option and dies before benefits commence to be paid to him, his Beneficiary will not be entitled to any rights or benefits under the Plan, except as provided under Article VII of the Plan or Paragraph A.10.0 of this Addendum. (iv) If a Participant elects the Contingent Annuitant Option and his Beneficiary dies before his death, but after the retirement of such Participant, such Participant will continue to receive the reduced Retirement Benefit payable to him in accordance with such option. (c) Life Annuity With 120 Monthly Guaranteed Payment Period Option. A Participant may elect, by submitting an election form to the Committee, to have his Retirement Benefit paid as a life annuity (as described in Section 8.4 of the Plan) but guaranteed for a period of 120 months, with the provision that if the Participant dies before payment of the guaranteed installments, payment of any remaining installments shall be paid to his Beneficiary. Upon the death of such Beneficiary before all remaining guaranteed payments have been made, such remaining payments shall be paid in an Actuarial Equivalent lump sum value to the estate of the Beneficiary. In the event that the Beneficiary is not an individual or if the Participant so elected, the Actuarial Equivalent lump sum value of any guaranteed payments remaining as of the Participant's date of death will be paid to the Beneficiary in lieu of the continuation of payments. If the Participant dies on or after his Normal Retirement Date, but prior to his Annuity Starting Date, his Beneficiary will be paid the present value of the (120, whichever is elected) monthly payments certain computed as of the date of death as if his Retirement Benefit were to commence to him on his date of death. If the Participant dies prior to his Normal Retirement Date or Annuity Starting Date, if earlier, his election of this option will be inoperative. (d) Social Security Adjustment Option. (This option may be elected only if the Participant's Annuity Starting Date precedes his 62nd birthday.) (i) Under this option the Participant will receive increased retirement annuity payments payable between his Annuity Starting Date and his Social Security Commencement Date and the amount of his retirement annuity payments payable on and after his Social Security Commencement Date will be reduced, taking into consideration the benefit it is expected he will receive commencing on his Social Security Retirement Date under the Social Security Act, so as to provide level retirement benefits during his lifetime. This option may be elected only if the application of subparagraph (ii), below, results in a yearly retirement annuity which is at least $60 more than the yearly amount of Old Age Insurance Benefit used in subparagraph (ii). The Social Security Commencement Date shall be the first day of the month in which a Participant attains his 62nd birthday. (ii) The increased monthly amount of retirement annuity payments payable between the Participant's Annuity Starting Date and his Social Security Commencement Date shall be equal to the sum of (A) the monthly amount of retirement annuity otherwise payable to the Participant if this election were not in effect, as determined under Paragraph A.6.1 of this Addendum, and (B) the percentage, determined from the table below, of the monthly amount of the Old Age Insurance Benefit which it is expected the Participant will be entitled to receive commencing on his Social Security Commence- ment Date under the Social Security Act. Social Security Adjustment Option Percentages Age Nearest Birthday on Retirement Date Percentage 55 50.7% 56 55.6 57 61.0 58 67.1 59 73.9 60 81.5 61 90.2 62 100.0 (iii) The reduced monthly amount of retirement annuity payments payable on and after the Participant's Social Security Commencement Date shall be equal to the excess of (A) the increase monthly amount of the retirement annuity payments payable to the Participant until his Social Security Commencement Date, and (B) the monthly amount of Old Age Insurance Benefit which it is expected the Participant will be entitled to receive commencing on his Social Security Commencement Date under the Social Security Act, as assumed for the purposes of subparagraph (ii). ADDENDUM NUMBER TWO TO THE EMPLOYEES' RETIREMENT PLAN OF EASTERN UTILITIES ASSOCIATES AND ITS AFFILIATED COMPANIES CERTAIN CHANGES WITH RESPECT TO EMPLOYEES OF NEWPORT ELECTRIC CORPORATION WHO ARE COVERED BY THE TERMS OF A COLLECTIVE BARGAINING AGREEMENT The provisions set forth in the Plan document shall govern participation in the Plan and the calculation of benefits. The foregoing provisions outlined in this Addendum Number Two shall set forth certain provisions relating specifically to employees of Newport Electric Corporation (hereinafter referred to as NEC) covered by the terms of a collective bargaining agreement and who are considered Employees hereunder as a result of the merger of this Plan into the Newport Electric Corporation Pension Plan (hereinafter referred to as the NEC Plan) effective as of January 1, 1991. These provisions reflect changes agreed to in the collective bargaining agreement applicable to the period September 2, 1991 through September 1, 1993 between NEC and the Brotherhood of Utility Workers of New England, Inc. Local 335 (hereinafter referred to as the Bargaining Agreement). B.1.0 Participation and Application of Plan Provisions. Each NEC employee covered by the terms of the Bargaining Agreement who became a Participant in the Plan on or prior to September 2, 1991, pursuant to Section 2.01 of the NEC Plan document, shall continue to be subject to the terms and provisions of the NEC Plan document, but as modified pursuant to Sections B.1.1 through B.1.4 below. Each NEC employee covered by the terms of the Bargaining Agreement who has not become a Participant in the Plan on or prior to September 2, 1991, pursuant to Section 2.01 of the NEC Plan document, shall become a Participant of the Plan pursuant to Section 2.1 of this Plan and shall be subject to all of the terms and provisions of this Plan rather than the NEC Plan document. B.1.1 Termination Benefit. The Termination Benefit described in Section A.1.5 of this Plan shall cease to accrue effective September 2, 1991 with respect to any NEC employee covered by the Bargaining Agreement. Any such employee who has accrued a Termination Benefit as of September 2, 1991 shall continue to retain such Benefit, subject to the vesting rules with respect thereto, and such accrued Termination Benefit shall be credited with interest pursuant to Section A.1.3 of this Plan. B.1.2 Death Benefit.1 The Death Benefit described in Section A.1.2 of this Plan is eliminated effective September 2, 1991 with respect to any NEC employee covered by the Bargaining Agreement. B.1.3 Special Rules for Contingent Annuitant Annuity.1 In the case of a NEC employee covered by the Bargaining Agreement who commences receiving benefits on or after September 2, 1991 in the form of a contingent annuity option as described in Section A.11.0(b) of this Plan and whose contingent annuitant predeceases the retired employee within one year after benefits commence, the amount payable under the contingent annuitant option shall be increased on the first of the month following the contingent annuitant's death to the amount which would have been payable to the retired employee as a single life annuity and such amount shall be payable to the retired employee for the balance of his lifetime. B.1.4 Pre-Retirement Spouse Benefit May Commence On or After Participant's 50th Birthday. In the case of the death of a married Participant occurring after September 2, 1991 and prior to age 55, the Participant's spouse may elect to receive the pre-retirement spouse benefit described in Section 3.04 of the NEC Plan document commencing as of the first day of any month following the later of the Participant's date of death or the date the Participant would have attained age 50. In the event payment of the spouse benefit commences prior to the date the Participant would have attained age 55, the amount of the spouse benefit shall be determined as the product of (i) the amount which would have been payable to the spouse under the 50% contingent annuitant option had the Participant died at age 65 with his spouse designated as the contingent annuitant, and (ii) the factor determined according to the following table: Participant's Nearest Birthday at Time Pre-Retirement Spouse Benefit Commences Factor 50 .35 51 .38 52 .41 53 .44 54 .47 Except as modified pursuant to this Section B.1.4, the pre-retirement spouse benefit described in the NEC Plan document shall continue to apply. ADDENDUM NUMBER THREE TO THE EMPLOYEES' RETIREMENT PLAN OF EASTERN UTILITIES ASSOCIATES AND ITS AFFILIATED COMPANIES APPLICATION OF PLAN TO NON-UNION EMPLOYEES OF NEWPORT ELECTRIC CORPORATION The provisions set forth in the Plan document shall govern participation in the Plan and the calculation of benefits. The following provisions outlined in this Addendum Number Three shall set forth certain provisions relating specifically to certain non-union employees of Newport Electric Corporation (hereinafter referred to as NEC) who are considered Employees hereunder as a result of the merger of this Plan into the Newport Electric Corporation Pension Plan (hereinafter referred to as the NEC Plan) effective as of January 1, 1991. The following provisions of this Addendum Number Three are effective March 1, 1992. C.1.0 Application of Addendum. This Addendum shall apply to all NEC Plan non-union participants except those participants on March 1, 1992 for whom, on or prior to December 31, 1996, the sum of their attained age and Years of Service (as defined in the NEC Plan document) will total at least eighty-five. A NEC Plan non-union participant to whom this Addendum does not apply shall be entitled to benefits according to the NEC Plan as in effect prior to the adoption of this Addendum. C.1.1 Application of Plan to NEC Non-Union Participants Covered by Addendum. Effective March 1, 1992, NEC Plan non-union participants to whom this Addendum applies shall cease to accrue benefits under the terms and provisions of the NEC Plan. On or after March 1, 1992, the benefit payable with respect to NEC Plan non-union participants to whom this Addendum applies shall be determined according to (i) or (ii) below, whichever produces the greatest benefit: (a) The benefit calculated under the terms and provisions of this Plan as in effect prior to December 31, 1990 and as subsequently amended from time to time taking into consideration all of his Years of Credited Service, including Years of Credited Service recognized under the NEC Plan document for periods prior to March 1, 1992. (b) The benefit computed with reference to his accrued benefit as of February 28, 1992, as calculated under the terms and provisions of the NEC Plan document, plus the benefit, if any, computed with reference to the benefit accrued under the terms and provisions of this Plan with respect to Years of Credited Service after February 28, 1992. To the extent a benefit is computed according to the terms and provisions of the NEC Plan document or this Plan document, all terms and provisions of the document shall apply to the benefit so computed, including for example, early retirement reduction factors, actuarial equivalent factors, and rules for determining Years of Credited Service. Except as modified by this Addendum Number Three, the terms of the NEC Plan as in effect prior to the adoption of this Addendum shall continue to apply. APPENDIX A TABLE I - REVISED JULY 1, 1991 EASTERN UTILITIES ASSOCIATES EMPLOYEES' RETIREMENT PLAN REDUCTION FACTORS FOR EARLY RETIREMENT TO BE USED IF PARTICIPANTS AGE PLUS SERVICE IS LESS THAN 85 APPENDIX A TABLE I - REVISED JULY 1, 1991 EASTERN UTILITIES ASSOCIATES EMPLOYEES' RETIREMENT PLAN REDUCTION FACTORS FOR EARLY RETIREMENT TO BE USED IF PARTICIPANTS AGE PLUS SERVICE IS GREATER THAN OR EQUAL TO 85 APPENDIX A TABLE I - REVISED 8/1/91 FOR USE PRIOR TO 7/1/91 EASTERN UTILITIES ASSOCIATES EMPLOYEES' RETIREMENT PLAN REDUCTION FOR EARLY RETIREMENT APPENDIX A TABLE II - OPTION 1 (EFFECTIVE AUGUST 1, 1983) EASTERN UTILITIES ASSOCIATES FACTORS TO BE APPLIED TO EMPLOYEE'S RETIREMENT INCOME TO DETERMINE INCOME UNDER CONTINGENT ANNUITANT OPTION IF 100% OF SUCH INCOME IS CONTINUED TO CONTINGENT ANNUITANT APPENDIX A TABLE II - OPTION 1 (EFFECTIVE AUGUST 1, 1983) EASTERN UTILITIES ASSOCIATES FACTORS TO BE APPLIED TO EMPLOYEE'S RETIREMENT INCOME TO DETERMINE INCOME UNDER CONTINGENT ANNUITANT OPTION IF 50% OF SUCH INCOME IS CONTINUED TO CONTINGENT ANNUITANT APPENDIX B NEWPORT ELECTRIC CORPORATION PENSION PLAN TEN YEAR CERTAIN AND LIFE OPTION FACTORS APPENDIX B NEWPORT ELECTRIC CORPORATION PENSION PLAN 50% JOINT AND SURVIVOR OPTION FACTORS APPENDIX B NEWPORT ELECTRIC CORPORATION PENSION PLAN 66-2/3% JOINT AND SURVIVOR OPTION FACTORS APPENDIX B NEWPORT ELECTRIC CORPORATION PENSION PLAN 100% JOINT AND SURVIVOR OPTION FACTORS NEWPORT ELECTRIC CORPORATION PENSION PLAN ACTUARIAL EQUIVALENT FACTORS FOR DETERMINING BENEFITS PAYABLE UNDER A.6.1(d) EX-10 3 10-15.03 EMPLOYEE'S SAVINGS PLAN EASTERN UTILITIES ASSOCIATES EMPLOYEE'S SAVINGS PLAN Amended and Restated Effective January 1, 1989 (Including Amendments through January 1, 1992) December, 1994 TABLE OF CONTENTS Section PREAMBLE ARTICLE I- DEFINITIONS Account 1.1 Affiliated Employer 1.2 After-Tax Participant Contribution(s) 1.3 After-Tax Participant Contribution(s) Account 1.4 Authorized Leave of Absence 1.5 Beneficiary 1.6 Board 1.7 Code 1.8 Committee 1.9 Common Shares 1.10 Disability 1.11 Earnings 1.12 Effective Date 1.13 Eligible Employee 1.14 Employee 1.15 Employer 1.16 Employment Date 1.17 Entry Date 1.18 ERISA 1.19 Fiduciary 1.20 Former Participant 1.21 Highly Compensated Employee 1.22 Highly Compensated Group 1.23 Matching Contribution 1.24 Matching Contribution Account 1.25 Nonparticipating Employer 1.26 One Year Break in Service 1.27 Parental Absence 1.28 Participant 1.29 Participating Employer 1.30 Plan 1.31 Plan Year 1.32 Pre-Tax Participant Contribution(s) 1.33 Pre-Tax Participant Contribution(s) Account 1.34 Qualified Voluntary Employee Contribution(s) 1.35 Section Qualified Voluntary Employee Contribution(s) Account 1.36 Rollover Contribution 1.37 Rollover Contribution Account 1.38 Service 1.39 Service Termination Date 1.40 Spouse 1.41 Trust or Trust Fund 1.42 Trust Agreement 1.43 Trustee 1.44 Valuation Date 1.45 ARTICLE II - PARTICIPATION Eligibility to Participate 2.1 Commencement of Participation 2.2 Transfers 2.3 Reemployment of Terminated Employee or Resumption of Employment Following Leave of Absence 2.4 ARTICLE III - PARTICIPANT CONTRIBUTIONS AND MAXIMUM AMOUNTS Pre-Tax Participant Contribution(s)s 3.1 After-Tax Participant Contribution(s)s 3.2 Rollover Contributions 3.3 Change in Level of Contributions 3.4 Suspension and Resumption of Contributions 3.5 Change in Earnings 3.6 Remittance of Participant Contributions 3.7 Limitation on Amount and Return of Pre-Tax Participant Contribution(s)s In Certain Instances 3.8 Limitation on Amount and Return of After-Tax Participant Contribution(s)s In Certain Instances 3.9 Section ARTICLE IV - MATCHING CONTRIBUTIONS AND OVERALL CONTRIBUTION LIMITS Matching Contributions 4.1 Remittance of Matching Contributions 4.2 Limitation on Amount of Matching Contributions and After-Tax Participant Contribution(s) In Certain Instances 4.3 Aggregate Limit Test 4.4 Maximum Total Allocations 4.5 Annual Additions 4.6 Contributions Conditioned on Tax Deductibility 4.7 Return of Contributions 4.8 Payment of Expenses 4.9 ARTICLE V - INVESTMENT OF CONTRIBUTIONS Committee to Establish Accounts 5.1 Investment Options 5.2 Change in Investment Options 5.3 Investment Rules 5.4 ARTICLE VI - TRUST FUND Trust Fund 6.1 Valuation of Funds 6.2 Valuation of Participant Accounts 6.3 Responsibilities of the Investment Manager 6.4 Statements of Participant Accounts 6.5 Valuation for Distribution 6.6 ARTICLE VII - DEATH AND DISABILITY Death Benefit 7.1 Payment of Death Benefit 7.2 Designation of Beneficiary 7.3 Payment Other Than to Beneficiary 7.4 Definition of Disability 7.5 Disability Benefit 7.6 Recovery from Disability 7.7 Section ARTICLE VIII - VESTING AND TERMINATION OF EMPLOYMENT Vesting of Contributions 8.1 Vesting Prior to August 1, 1983 8.2 Method of Payment 8.3 ARTICLE IX - LOANS AND WITHDRAWALS Withdrawals from Matching and Rollover Contribution Accounts 9.1 Withdrawals from After-Tax Participant Contribution(s) Account 9.2 Withdrawals from Qualified Voluntary Employee Contribution(s) Account 9.3 Withdrawals from Pre-Tax Participant Contribution(s) Account 9.4 Hardship Withdrawals 9.5 Rules for Withdrawals 9.6 Debiting of Withdrawals 9.7 Participant Loans 9.8 Rules Relating to Loans 9.9 ARTICLE X - PAYMENT OF BENEFITS Entitlement to Distribution 10.1 Form of Payment 10.2 Time of Payment 10.3 Amount of Distribution 10.4 Death Benefits 10.5 Limitation on Distributions 10.6 Segregated Accounts 10.7 Missing Persons 10.8 ARTICLE XI - EMPLOYEES' SAVINGS PLAN COMMITTEE Responsibility for Plan and Trust Administration 11.1 Retirement Plan Committee 11.2 Agents of the Committee 11.3 Committee Procedures 11.4 Administrative Powers of the Committee 11.5 Section Benefit Claims Procedures 11.6 Reliance on Reports and Certificates 11.7 Other Committee Powers and Duties 11.8 Compensation of Committee 11.9 Member's Own Participation 11.10 Liability of Committee Members 11.11 Indemnification 11.12 ARTICLE XII - FIDUCIARY RESPONSIBILITIES Basic Responsibilities 12.1 Actions of Fiduciaries 12.2 Fiduciary Liability 12.3 Bonding of Fiduciaries 12.4 Indemnification of Fiduciaries 12.5 ARTICLE XIII - AMENDMENT AND TERMINATION Internal Revenue Service Qualification 13.1 Employer's Right to Amend or Terminate 13.2 Participating Employer's Right to Terminate 13.3 Valuation of Assets 13.4 Distribution of Assets 13.5 ARTICLE XIV - TOP-HEAVY PLAN REQUIREMENTS General Rule 14.1 Minimum Contribution Provisions 14.2 Limitation on Contributions 14.3 Coordination With Other Plans 14.4 Top-Heavy Plan Definitions 14.5 Key Employee 14.6 Non-Key Employee 14.7 Change from Top-Heavy Status 14.8 Section ARTICLE XV - GENERAL PROVISIONS Plan Voluntary 15.1 Payments to Minors and Incompetents 15.2 Non-Alienation of Benefits 15.3 Use of Masculine and Feminine; Singular and Plural 15.4 Merger, Consolidation or Transfer 15.5 Leased Employees 15.6 Governing Law 15.7 PREAMBLE Effective January 1, 1982, Eastern Utilities Associates (the "Employer") established a retirement plan referred to as the Eastern Utilities Associates Employees' Savings Plan (the "Plan") as provided herein. A Trust Agreement has been adopted by the Employer and is intended to form a part of this Plan. The purpose of this Plan is to encourage employee savings for retirement and to provide a tax qualified facility for accumulation of funds to be used to provide benefits payable to an Employee upon his retirement, death, disability, termination of employment, or on certain other occasions. This Plan constitutes an amendment to, restatement of, and continuation of the Plan as it was originally effective January 1, 1982, and as amended from time to time thereafter. This amendment and restatement is effective January 1, 1989, except to the extent otherwise specifically provided herein. Effective January 1, 1992, the Newport Electric Corporation Deferred Compensation Thrift Plan was merged into and became a part of this Plan. The merged plans are maintained as a single plan pursuant to Section 414(l) of the Internal Revenue Code of 1986 (the "Code") and applicable regulations and rulings. Except as otherwise provided herein, the terms of this Plan shall govern the participation of and accounts of those employees formerly employed by Newport Electric Corporation. It is intended that this Plan be qualified under Section 401(a) of the Code, as amended from time to time, and meet the requirements of Code Section 401(k) as a qualified cash or deferred arrangement. It is also intended that the Trust be exempt from taxation as provided under Code Section 501(a). ARTICLE I DEFINITIONS The following words and phrases when used in the Plan shall have the following meanings, unless a different meaning is plainly required by the context: 1.1 "Account" shall mean the credit balance of a Participant in the Trust Fund represented by his Pre-Tax Participant Contribution(s) Account, Matching Contribution Account, After-Tax Participant Contribution(s) Account, Qualified Voluntary Employee Contribution(s) Account and his Rollover Contribution Account, if any. 1.2 "Affiliated Employer" shall mean any corporation which is included with the Employer in a controlled group of corporations, as determined in accordance with Code Section 414(b), any unincorporated trade or business which, as determined under regulations of the Secretary of the Treasury, is under common control of the Employer under Code Section 414(c), any organization that includes the Employer, which is a member of an affiliated service group, as defined in Code Section 414(m), and any other entity required to be aggregated with the Employer pursuant to regulations under Code Section 414(o). For the purposes of Sections 4.5 and 4.6, Code Sections 414(b) and (c) shall be applied as modified by Code Section 415(h). 1.3 "After-Tax Participant Contribution(s)" shall mean contributions made to the Plan by a Participant on an after-tax basis pursuant to Article III. 1.4 "After-Tax Participant Contribution(s) Account" shall mean a Participant's interest in the Trust Fund attributable to After-Tax Participant Contribution(s) made to the Plan including investment experience thereon. 1.5 "Authorized Leave of Absence" shall mean an Employee's temporary absence from work which is approved and authorized by the Employer or Participating Employer according to uniform and nondiscriminatory rules. An Authorized Leave of Absence shall include a Parental Absence as defined in Section 1.28. 1.6 "Beneficiary" shall mean the person or persons designated by the Participant or Former Participant to receive benefits under the Plan in the event of the Participant's death. If the Participant is married and designates someone other than his legal Spouse, his Beneficiary designation must include the written consent of his legal Spouse at the time the designation is made in order to be valid. A former Spouse's consent shall not be binding on a subsequent Spouse. Such written consent must approve the specific beneficiary designated, acknowledge the effect of such designation and be witnessed by a notary public or a Plan representative. If it is established to the satisfaction of the Committee that the Participant has no Spouse, or that the Spouse's consent cannot be obtained because the Spouse cannot be located, or because of such other circumstances as may be prescribed in regulations issued pursuant to Code Section 417, such written consent shall not be required. If no valid Beneficiary designation is in effect at the time of the Participant's death, Section 7.4 shall apply. 1.7 "Board" shall mean the Board of Trustees of the Employer. 1.8 "Code" shall mean the Internal Revenue Code of 1986, as amended from time to time and any regulations issued thereunder. Reference to any Code Section shall include any successor provision thereto. 1.9 "Committee" shall mean the person or persons designated by the Employer as the Employees' Savings Plan Committee to administer the Plan in accordance with Article XI. 1.10 "Common Shares" shall mean common shares of the Employer's stock with voting power and dividend rights no less favorable than the voting power and dividend rights of any other common shares of stock issued by the Employer. 1.11 "Disability" shall mean a total and permanent disability as defined pursuant to Article VII. 1.12 "Earnings" shall mean the regular straight time wages paid by the Employer to an Employee during a Plan Year, exclusive of overtime, bonuses, and the Employer's cost for any public or private employee benefit plan (including this Plan) except that Earnings shall include any Pre-Tax Participant Contribution(s) made here-under and any salary deferrals made by the Employee to a plan maintained by a Participating Employer which meets the requirements of Code Section 125 during the Plan Year. A Participant's Earnings taken into account under the Plan for any Plan Year shall not exceed $200,000 ($150,000 for Plan Years beginning January 1, 1994) or such amount as indexed pursuant to Code Sections 401(a)(17) and 415(d) and the applicable regulations thereunder. In determining the Earnings of an Employee for purposes of the Code Section 401(a)(17) limitation, the rules of Code Section 414(q)(6) shall apply except that the term "family" shall include only the Spouse of an Employee and any linear descendants of the Employee who have not attained age 19 before the close of the Plan Year. If the Earnings of the Employee exceeds the Code Section 401(a)(17) limitation, then such limitation shall be pro-rated among the Earnings of the Employee and his family (as determined under this Section 1.12 prior to the application of the Code Section 401(a)(17) limitation) in proportion to each such individual's Earnings (as determined under this Section 1.12 prior to the application of the Code Section 401(a)(17) limitation). 1.13 "Effective Date" shall mean January 1, 1989, the effective date of the amendment and restatement of the Plan. The original effective date of the Plan is January 1, 1982. 1.14 "Eligible Employee" shall mean an Employee who is included in the eligible class described in Section 2.1. 1.15 "Employee" shall mean any common-law employee of the Employer or an Affiliated Employer, excluding any individual who is an independent contractor, a consultant, or a Trustee of Eastern Utilities Associates unless such Trustee is otherwise an Employee of the Company. A leased employee as described in Code Section 414(n)(2) shall be considered an Employee only to the extent required by Section 15.6. 1.16 "Employer" shall mean Eastern Utilities Associates, a voluntary association formed under a Declaration of Trust dated April 2, 1928 as amended under the laws of the Commonwealth of Massachusetts or its successor or successors. 1.17 "Employment Date" shall mean the first day for which an Employee receives credit for an Hour of Service. 1.18 "Entry Date" shall mean any January 1 or July 1. Effective July 1, 1992, Entry Date shall mean the first day of any calendar month. 1.19 "ERISA" shall mean the Employee Retirement Income Security Act of 1974, as amended from time to time. References to any section of ERISA shall include any successor provision thereto. 1.20 "Fiduciary" shall mean any person who exercises any discretionary authority or discretionary control respecting the management of the Plan, assets held under the Plan, or disposition of Plan assets; who renders investment advice for a fee or other compensation, direct or indirect, with respect to assets held under the Plan or has any authority or responsibility to do so; or who has any discretionary authority or discretionary responsibility in the administration of the Plan. Any person who exercises authority or has responsibility of a fiduciary nature as described above shall be considered a Fiduciary under the Plan. 1.21 "Former Participant" shall mean an individual who was a Participant, has terminated employment with the Employer and all Affiliated Employers, and has received a distribution of his Account under the Plan. 1.22 "Highly Compensated Employee" shall mean each Employee who at any time during the current or preceding Plan Year: (a) was a 5% owner (as defined in Code Section 416(i)(l)) of the Employer or an Affiliated Employer; (b) received compensation from the Employer or an Affiliated Employer in excess of $75,000 (as indexed pursuant to applicable regulations under the Code); (c) received compensation from the Employer or an Affiliated Employer in excess of $50,000 (as indexed pursuant to applicable regulations under the Code) and was in the group consisting of the top 20% of all Employees when ranked on the basis of compensation received during such Plan Year; or (d) was at any time an officer of the Employer or Affiliated Employer who received compensation in excess of 50% of the amount in effect under Code Section 415(b)(1)(A) for such Plan Year. Notwithstanding the foregoing, an Employee not described in paragraph (b), (c), or (d) above for the preceding Plan Year shall only be a Highly Compensated Employee for the current Plan Year if he is described in paragraph (b), (c) or (d) for the current Plan Year and is one of the top 100 Employees when ranked by compensation for such Plan Year. For purposes of this Section, "compensation" shall mean compensation as defined in Code Section 414(q)(7). In any event, the determination of a Highly Compensated Employee shall be made pursuant to Code Section 414(q) and regulations issued thereunder. Accordingly, the Committee may elect to use the calendar year election to determine Highly Compensated Employees as provided in Treasury Regulation 1.414(q)-1T Q&A 14(b)1 or the simplified method as described in Revenue Procedure 93-42, Section 4. 1.23 "Highly Compensated Group" shall mean the group of Highly Compensated Employees who are also Eligible Employees as defined herein. 1.24 "Matching Contribution" shall mean a contribution by a Participating Employer made to the Plan on behalf of a Participant pursuant to Article IV. 1.25 "Matching Contribution Account" shall mean a Participant's interest in the Trust Fund attributable to Matching Contributions made to the Plan including investment experience thereon. 1.26 "Nonparticipating Employer" shall mean any Affiliated Employer which is not a Participating Employer. 1.27 "One Year Break in Service" shall mean a consecutive 12-month period commencing on an Employee's Service Termination Date (or anniversary thereof) in which such individual is not employed by the Employer or an Affiliated Employer. 1.28 "Parental Absence" shall mean an Employee's absence from work which has commenced after December 31, 1984, for any of the following reasons: (a) the pregnancy of the Employee; (b) the birth of the Employee's child; (c) the adoption of a child by the Employee; or (d) the need to care for the Employee's child immediately following its birth or adoption. 1.29 "Participant" shall mean an Employee who is either currently contributing to the Plan or who has an Account under the Plan. 1.30 "Participating Employer" shall mean the Employer and any other Affiliated Employer (or a division or subsidiary of either) which participates in the Plan with the permission of the Employer. A Participating Employer may elect, with the consent of the Employer, to adopt the Plan only with respect to a division or other employment unit rather than with respect to all of its employees. 1.31 "Plan" shall mean the Eastern Utilities Associates Employees' Savings Plan as set forth in this document and as amended from time to time. 1.32 "Plan Year" shall mean the 12-month period commencing on January 1 and ending on the next following December 31. 1.33 "Pre-Tax Participant Contribution(s)" shall mean a salary reduction contribution made to the Plan on behalf of a Participant pursuant to Article III. 1.34 "Pre-Tax Participant Contribution(s) Account" shall mean a Participant's interest in the Trust Fund attributable to Pre-Tax Participant Contribution(s) made to the Plan including investment experience thereon. 1.35 "Qualified Voluntary Employee Contribution(s) (QVEC)" shall mean a Participant's tax-deductible contributions made under the Plan prior to January 1, 1987. Qualified Voluntary Employee Contribution(s) shall not be made to the Plan after December 31, 1986. 1.36 "Qualified Voluntary Employee Contribution(s) Account" shall mean a Participant's interest in the Trust Fund attributable to Qualified Voluntary Employee Contribution(s) made to the Plan including investment experience thereon. 1.37 "Rollover Contribution" shall mean a contribution made to the Plan by a Participant pursuant to Section 3.3. 1.38 "Rollover Contribution Account" shall mean a Participant's interest in the Trust Fund attributable to Rollover Contributions made to the Plan including investment experience thereon. 1.39 "Service" shall mean the completed years and months of an Employee's employment with the Employer and Affiliated Employers measured from the individual's date of hire with the Employer or Affiliated Employer. Service shall include the following: (a) the first 12 months of layoff; (b) any period during which the Employee is on an Authorized Leave of Absence, with or without pay; (c) any period of absence because of service in the Armed Forces of the United States provided the Employee returns to employment with the Employer or Affiliated Employer within 90 days (or such longer period as may be provided by law for the protection of reemployment rights) after his discharge or release from active duty in the Armed Forces; (d) any other authorized period of absence, including paid holidays, paid vacations, and sick leaves; and (e) any other period of absence not in excess of one year, provided the Employee returns to work within such one-year period. For the purpose of determining an Employee's Service, a full calendar month of employment shall be deemed one month of Service and 12 months of employment shall be deemed one year of Service. All periods of employment with the Employer and Affiliated Employers shall be taken into consideration for the purpose of determining an Employee's Service. For an Employee who was an employee of Newport Electric Corporation on December 31, 1991, and who became an Employee hereunder on January 1, 1992, all periods of employment with Newport Electric Corporation will be deemed Service to the extent such period of employment with Newport Electric Corporation would have been deemed Service in accordance with the provisions of this Section 1.39. 1.40 "Service Termination Date" shall mean the earliest of the following: (a) the date on which the Employee resigns, is discharged, or retires from Service with the Employer and all Affiliated Employers; (b) the date the Employee dies; (c) the first anniversary of the date on which the Employee is laid off, starts an Authorized Leave of Absence, or is absent from work for any other reason other than a Parental Absence; and (d) the second anniversary of the date on which the Employee commenced a Parental Absence, if such Employee has not yet returned to work with the Employer or an Affiliated Employer. 1.41 "Spouse" shall mean the legal spouse to whom a Participant is married under applicable state law on the date benefits commence. However, if the Participant should die before the date benefits are to commence, then the Spouse shall be the legal spouse to whom the Participant was married on the Participant's date of death. A former spouse will be treated as the Spouse or surviving Spouse to the extent required under a qualified domestic relations order as defined in Code Section 414(p). 1.42 "Trust" or "Trust Fund" shall mean all assets held by the Trustee in accordance with the Trust Agreement. 1.43 "Trust Agreement" shall mean the trust agreement between the Employer and a Trustee as provided for in Article XI. 1.44 "Trustee" shall mean the individual, individuals or institution appointed by the Board of Trustees of the Employer to act in accordance with the Trust Agreement. 1.45 "Valuation Date" shall mean March 31, June 30, September 30, and December 31. Effective July 1, 1992, Valuation Date shall mean any date as of which the investment funds offered under the Plan are valued, provided that in any event such funds shall be valued no less frequently than quarterly. ARTICLE II PARTICIPATION 2.1 Eligibility to Participate. Each Employee shall be an Eligible Employee upon satisfying the following requirements: (a) he is employed by a Participating Employer; (b) he has completed one year of Service; (c) he has attained age 18; (d) he is not a "leased employee" as defined under Code Section 414(n)(2); (e) in the case of an Employee covered by a collective bargaining agreement, the bargaining agreement provides for his participation herein; (f) effective July 1, 1992, he is not a temporary Employee (an Employee is a temporary Employee if he is hired for a position which is expected to terminate in the foreseeable future; and (g) Notwithstanding the foregoing, an Employee who was an employee of Newport Electric Corporation as of December 31, 1991, and who was a participant of the Newport Electric Corporation Deferred Compensation Thrift Plan on such date shall be considered an Eligible Employee hereunder as of January 1, 1992. All other Employees who were employees of Newport Electric Corporation shall become Eligible Employees upon satisfying the aforementioned requirements of this Section 2.1. 2.2 Commencement of Participation. Except as provided in Section 2.4, each Eligible Employee shall become a Participant (or if his participation has terminated, shall again become a Participant) on the Entry Date coinciding with or next following the date on which he: (a) meets the requirements of Section 2.1; and (b) enrolls in the Plan by completing an election form to initiate contributions pursuant to Article III. However, if an Eligible Employee fails to enroll when first eligible to do so, such Employee shall be eligible to enroll on any following Entry Date providing he is then an Eligible Employee. 2.3 Transfers. The following provisions shall govern in the case of an Employee who changes employment status: (a) In the event that an Eligible Employee directly transfers to an ineligible class of Employees, he shall be deemed to continue as a Participant for all purposes of the Plan except that he shall not be permitted to direct any further Pre-Tax Participant Contribution(s) or make any further After-Tax Participant Contribution(s) on his behalf under the Plan nor shall he receive any further Matching Contributions unless he again becomes an Eligible Employee. Such an Employee shall continue to accrue Service pursuant to Section 1.39. (b) In the event that an Employee in an ineligible class (i.e. temporary or leased employees) transfers to an employment classification as an Eligible Employee, his Service earned during his employment with all Participating and Nonparticipating Employers shall be credited under this Plan. Such Employee shall be eligible to become a Participant on the first day of the month coinciding with or next following the transfer or, if later, the Entry Date coinciding with or next following the date when he meets the requirements of Section 2.1. 2.4 Reemployment of Terminated Employee or Resumption of Employment Following Leave of Absence. A terminated Employee or an Employee on an Approved Leave of Absence who resumes active employment with a Participating Employer as an Eligible Employee may elect to become a Participant (or shall continue participation if already a Participant) on the first day of the month coinciding with or next following his reemployment date, provided he meets the requirements of Section 2.1 on such reemployment date, or if later, the Entry Date coinciding with or next following the date on which he meets such requirements. ARTICLE III PARTICIPANT CONTRIBUTIONS AND MAXIMUM AMOUNTS 3.1 Pre-Tax Participant Contribution(s). Each Eligible Employee may elect, in writing, to authorize a Participating Employer to reduce his Earnings and make a corresponding Pre-Tax Participant Contribution(s) on his behalf commencing on any Entry Date. This reduction in Earnings shall be in any whole percentage from 1% to 12% (15% effective July 1, 1992) of such Earnings or, if permitted by the Committee, in a flat dollar amount not less than 1% and not to exceed 12% (15% effective July 1, 1992) of such Earnings. Authorization to reduce Earnings shall be in writing and shall be delivered to the Committee no later than 30 days prior to the date as of which the Pre-Tax Participant Contribution(s) becomes effective, unless the Committee agrees to accept a later authorization according to such uniform and nondiscriminatory rules as it may adopt. Such Earnings reduction shall continue unchanged until the Participant terminates employment, changes or suspends the Pre-Tax Participant Contribution(s) in accordance with Section 3.4 or 3.5 or transfers to the employment of a Nonparticipating Employer or an ineligible class of Employees. Pre-Tax Participant Contribution(s) made under this Section 3.1 shall be subject to the limitations of Sections 3.8, 4.4, and 4.5. 3.2 After-Tax Participant Contribution(s). Each Eligible Employee may elect, in writing, to contribute a percentage of his Earnings as nondeductible After-Tax Participant Contribution(s) commencing on any Entry Date. The contribution rate must be in any whole percentage from 1% to 10% of such Earnings or, if permitted by the Committee, in a flat dollar amount not less than 1% and not to exceed 10% of such Earnings, provided that such After-Tax Participant Contribution(s) shall not exceed the difference between 12% (15% effective July 1, 1992) and the contribution percentage such Eligible Employee has currently authorized for Pre-Tax Participant Contribution(s). Authorization to make After-Tax Participant Contribution(s) shall be in writing and shall be delivered to the Committee no later than 30 days prior to the date as of which the After-Tax Participant Contribution(s) becomes effective, unless the Committee agrees to accept a later authorization according to such uniform and nondiscriminatory rules it may adopt. Such contributions will be made on an after-tax basis by payroll deduction which shall continue unchanged until the Participant terminates employment, changes or suspends his After-Tax Participant Contribution(s) election in accordance with Section 3.4 or 3.5 or transfers to the employment of a Nonparticipating Employer or an ineligible class of Employees. After-Tax Participant Contribution(s) made under this Section 3.2 shall be subject to the limitations of Sections 4.3, 4.4, and 4.5. 3.3 Rollover Contributions. An Employee who is or who would be an Eligible Employee except for the Service or age requirement under Section 2.1 may elect, subject to the written consent of the Committee, to make a Rollover Contribution to the Trust Fund to the extent permitted under Code Section 402(c) and other applicable Code sections and related rulings and regulations. A Rollover Contri- bution shall be subject to the following rules: (a) A Rollover Contribution shall consist of a distribution of all or a portion of the balance to the credit of the Employee: (i) from a qualified trust under Code Section 401(a), which trust is exempt from tax under Code Section 501(a) (or from an annuity plan qualified under Code Section 403(a)), or (ii) from an individual retirement account, or an individual retirement annuity (in each case within the meaning of Code Section 408), all of the assets of which arose from a distribution described in (i) which was transferred to such account or annuity within 60 days from the date of the distribution. Notwithstanding the foregoing, a Rollover Contribution shall not consist of: any distribution that is one of a series of substantially equal periodic payments (not less frequently than annually) made for the life (or the life expectancy) of the Employee or the joint lives (or joint life expectancies) of the Employee and the Employee's designated beneficiary, or for a specified period of ten years or more; any distribution to the extent such distribution is required under Code Section 401(a)(9); and the portion of any distribution that is not includible in gross income (determined without regard to the exclusion for net unrealized appreciation with respect to Employer securities). (b) A Rollover Contribution shall not exceed the fair market value of the amount described in (a) above; (c) A Rollover Contribution shall be made in cash; (d) In the event a Rollover Contribution consists of an amount which has been paid directly to the individual, such Rollover Contribution shall be made no later than 60 days following the date the Participant receives the amount distributed; (e) A Rollover Contribution must be submitted with supporting documentation that the Rollover Contribution meets the requirements of this Section 3.3. An Employee who makes a Rollover Contribution shall be considered a Participant under the Plan solely with respect to such Rollover Contribution until he otherwise becomes a Participant pursuant to Sections 2.1 and 2.2. 3.4 Change in Level of Contributions. The Pre-Tax and After-Tax Participant Contribution(s) percentages as designated by the Participant shall continue in effect, notwithstanding any change in his Earnings, until he elects to change such percentage. Subject to the requirements of Sections 3.1 and 3.2, a Participant may change the rate of such contributions as of any Entry Date by providing 30 days' prior written notice to the Committee or such lesser notice as the Committee may approve according to such uniform and nondiscriminatory rules as it may adopt. Notice of any such change shall be given on a form to be provided by the Committee for this purpose and shall be signed by the Participant and delivered to the Committee. 3.5 Suspension and Resumption of Contributions. A Participant may suspend the making of Pre-Tax Participant Contribution(s) and/or After-Tax Participant Contribution(s) as of any pay period by providing at least 30 days' prior written notice to the Committee or such lesser notice as the Committee may approve according to such uniform and nondiscriminatory rules as it may adopt. A suspension of Pre-Tax and/or After-Tax Participant Contribution(s) pursuant to this Section shall continue for a period of no less than three months. Providing he is still an Eligible Employee, a Participant who suspends his contributions pursuant to the above rules may resume such contributions effective as of the first day of any month following the required three month suspension period, with 30 days' prior written notice to the Committee or such lesser notice as the Committee may approve according to uniform and nondiscriminatory rules it may adopt. 3.6 Change in Earnings. In the event of a change in the Earnings of a Participant, the percentage of his Earnings that he has authorized as his Pre-Tax Participant Contribution(s) and/or After-Tax Participant Contribution(s) shall be applied as soon as practicable with respect to such changed Earnings without action by the Participant. In the case of a Participant who has elected a flat dollar contribution, such contribution shall not change on account of a change in his Earnings. 3.7 Remittance of Participant Contributions. Pre-Tax and After-Tax Participant Contribution(s) will be remitted to the Trustee by the Participating Employers as soon as practicable following the date such contributions are made but in no event later than 30 days following the end of the Plan Year in which such contributions are made. Rollover Contributions shall be remitted to the Trustee as soon as practicable after they are delivered to a Participating Employer. All Pre-Tax, After-Tax, and Rollover Contributions shall be invested in accordance with the Participant's investment direction pursuant to Article V. Notwithstanding the foregoing, a Participant's Pre-Tax and After-Tax Participant Contribution(s) will stop for any period of time during which he is on an unpaid authorized leave of absence or layoff. 3.8 Limitation on Amount and Return of Pre-Tax Participant Contribution(s) In Certain Instances. (a) In no event shall a Participant's Pre-Tax Participant Contribution(s) for a taxable year under this Plan and any other cash or deferred arrangement (such as any other plan permitting contributions under Section 401(k) of the Code) maintained by the Employer exceed the dollar limit on excludable salary deferrals under Code Section 402(g)(1) ($9,240 for 1994) as adjusted for increases in the cost of living pursuant to Code Section 402(g)(5). In the event a Participant's Pre-Tax Participant Contribution(s) should exceed such dollar limit for a taxable year, the excess, together with any investment earnings attributable thereto, shall be returned to the Participant no later than April 15 following the close of the taxable year for which the excess contribution was made. (b) In the event a Participant's Pre-Tax Participant Contribution(s) for a taxable year under this Plan, together with his salary reduction amounts under any other plan which meets the requirements of Code Section 401(k), exceed the limits set forth in (a) above, the Participant may treat a portion of such excess as having been contributed to this Plan and request a return of such excess together with any investment earnings attributable thereto. Any such request shall be made no later than March 1 following the close of the taxable year for which the excess contribution was made, and the return of such excess shall be made no later than the immediately following April 15. (c) Effective January 1, 1987, for each Plan Year, the "average deferral percentage" authorized by the Highly Compensated Group as Pre-Tax Participant Contribution(s) must meet one of the following tests: (i) The "average deferral percentage" of the Highly Compensated Group may not exceed 1.25 multiplied by the "average deferral percentage" of all other Eligible Employees who are not in such group, or (ii) The "average deferral percentage" of the Highly Compensated Group may not exceed 2.0 multiplied by the "average deferral percentage" of all other Eligible Employees, who are not in such group, subject to a maximum differential of two percentage points. (d) The "average deferral percentage" for a specified group for a Plan Year shall mean the average of the ratios (calculated separately for each Employee in such group) of (i) over (ii) where: (i) equals the sum of the Pre-Tax Participant Contribution(s) made on behalf of each Eligible Employee for the Plan Year pursuant to Section 3.1; and (ii) equals the Eligible Employee's compensation for such Plan Year as provided under Code Section 414(s), including any alternative definitions thereunder. For purposes of the foregoing, only Pre-Tax Participant Contribution(s) allocated to the Participant's Account on a date within a Plan Year and paid to the Trust Fund within 12 months following the close of such Plan Year shall be considered in determining his "deferral percentage" for such Plan Year. In addition, only Pre-Tax Participant Contribution(s) which are attributable to the Earnings an Employee receives from the Employer during a Plan Year or within two and one-half months following the close of such Plan Year shall be considered in determining the Employee's "deferral percentage" for such Plan Year. If the Participating Employer sponsors two or more plans which include a cash or deferred arrangement but are considered one plan for purposes of Code Section 401(a)(4) or 410(b), the cash or deferred arrangements included in such plans shall be treated as one plan for purposes of determining the "average deferral percentage". If any Eligible Employee who is a member of the Highly Compensated Group is participating in two or more cash or deferred arrangements (such as any other plan permitting contributions under Section 401(k) of the Code) sponsored by the Employer or an Affiliated Employer, such cash or deferred arrangements shall be treated as one arrangement for purposes of determining the "deferral percentage" for such Eligible Employee. For purposes of determining the "deferral percentage" of an Eligible Employee who is a 5% owner or one of the ten most highly-paid Highly Compensated Employees, the Pre-Tax Participant Contribution(s) and compensation of such Eligible Employee shall include the Pre-Tax Participant Contribution(s) and compensation for the Plan Year of "family members" (as defined in Code Section 414(q)(6)) as may be required pursuant to the family aggregation rules of Code Section 401(k) and pertinent regulations issued thereunder. To such extent as required by regulations, family members, with respect to such Highly Compensated Employees, shall be disregarded as separate Employees in determining the "average deferral percentage" both for Eligible Employees who are non-highly compensated Employees and for Eligible Employees who are Highly Compensated Employees. (e) From time to time, the Committee shall review the Pre-Tax Participant Contribution(s) authorized by Eligible Employees. If, upon such review, the Committee determines that the average percentage of such contributions applicable to the Highly Compensated Group exceeds or is likely to exceed the maximum average percentage necessary to comply with the above rules, the Committee may reduce the Pre-Tax Participant Contribution(s) of the Highly Compensated Group, to the extent necessary to comply with such rules. Such reduction shall be effected by successive reductions of the highest Pre-Tax Participant Contribution(s) percentage authorized by one or more members of the Highly Compensated Group until the average percentage applicable to the Highly Compensated Group does not exceed the maximum average percentage referred to above. Notwithstanding the foregoing sentence, the Committee may impose a maximum dollar limitation which is less than the amount specified in Code Section 402(g) or a maximum percentage which is less than the percentage in Section 3.1 to all Pre-Tax Participant Contribution(s) made by the Highly Compensated Group. (f) If, after the end of the Plan Year, the Committee determines that the Pre-Tax Participant Contribution(s) made on behalf of Highly Compensated Employees are in excess of the amounts allowed under (c)(i) and (c)(ii) above, the Committee shall return any Pre-Tax Participant Contribution(s) in excess of the amount permitted above, together with any investment earn- ings or losses allocable thereto to the affected Participants until the rules in either (c)(i) or (c)(ii) above are met. The return of such "excess contributions" shall be made in the same manner as described in paragraph (e) above. Such "excess contributions" shall be distributed within 2-1/2 months, if at all possible, following the end of the Plan Year in which such Pre-Tax Participant Contribution(s) were made and in no event later than the close of the following Plan Year. The return of any excess Pre-Tax Participant Contribution(s) shall be made on a pro rata basis from the funds in which the Pre-Tax Participant Contribution(s) are then invested, unless the Committee shall permit the Participant to elect such other method of return based on such uniform and nondiscriminatory rules as it may adopt. In the case of an Eligible Employee who is subject to the family aggregation rules of Code Section 414(q)(6) because he is a member of a family of a 5% owner of the Employer or of one of the ten most highly paid Highly Compensated Employees, the determination of and return of excess Pre-Tax Participant Contribution(s) under this Section shall be made in accordance with the family aggregation rules of Code Section 401(k) and pertinent regulations issued thereunder. (g) For purposes of determining the investment earnings or loss to be distributed pursuant to paragraphs (a) and (f) hereunder, the following rules shall apply: The earnings or loss allocable to Pre-Tax Participant Contribution(s) is the earnings or losses allocable to the Participant's Pre-Tax Participant Contribution(s) Account for the Plan Year multiplied by a fraction, the numerator of which is the Pre-Tax Participant Contribution(s) to be distributed to the Participant for the year and the denominator is the Participant's Account balance attributable to Pre-Tax Participant Contribution(s) without regard to any earnings or loss occurring during such Plan Year. (h) In the event that the Participating Employer made a Matching Contribution with respect to any Pre-Tax Participant Contribution(s) returned pursuant to this Section, such Matching Contribution shall be distributed or forfeited to the affected members of the Highly Compensated Group, as determined by the Committee according to such uniform and nondiscriminatory rules as it may adopt. 3.9 Limitation on Amount and Return of After-Tax Participant Contribution(s) in Certain Instances. The limitation on the amount and return of After-Tax Participant Contribution(s) is described in Article IV. ARTICLE IV MATCHING CONTRIBUTIONS AND OVERALL CONTRIBUTION LIMITS 4.1 Matching Contributions. Each Participating Employer shall make a Matching Contribution on behalf of each of its Participants in an amount equal to 100% of the first 2% of Earnings and 50% of the next 1% of Earnings with respect to which such Participant makes Pre-Tax Participant Contribution(s). The level of Matching Contributions for any Employee whose terms of employment are governed by a collective bargaining agreement shall be subject to the terms of such collective bargaining agreement with respect to a Plan Year. Matching Contribu- tions made under this Section 4.1 shall be subject to the limitations of Sections 4.3, 4.4, and 4.5. The Board may change the Matching Contribution from time to time. In the event Matching Contributions on behalf of a Participant for a Plan Year would otherwise cease because his Pre-Tax Participant Contribution(s) for such Year cease on account of the dollar limit set forth in Section 402(g)(1) of the Code, Matching Contributions shall be continued on his behalf for the remainder of the Plan Year in accordance with this Section during his continued employment as long as his actual Pre-Tax Participant Contribution(s) for the Plan Year are at least equal to 3% of his Earnings for the Year or such other amount as eligible for the maximum Matching Contribution. 4.2 Remittance of Matching Contributions. Matching Contributions will be paid by the Participating Employers to the Trustee no later than 30 days following the end of the Plan Year in which the corresponding Pre-Tax Participant Contribution(s) are made, but in no event later than the Participating Employer's tax filing deadline for its fiscal year in which such Plan Year ends. Matching Contributions shall be invested in EUA Common Shares pursuant to Article V, except as may otherwise be provided under the terms of a collective bargaining agreement. As such, Matching Contributions may be contributed in cash, common shares or partially in cash and common shares. 4.3 Limitation on Amount of Matching Contributions and After-Tax Participant Contribution(s) In Certain Instances. Effective January 1, 1987, for each Plan Year, the "average contribution percentage" of the Highly Compensated Group must meet one of the following tests: (a) The "average contribution percentage" of the Highly Compensated Group may not exceed 1.25 multiplied by the "average contribution percentage" of all other Eligible Employees who are not in such group. (b) The "average contribution percentage" of the Highly Compensated Group may not exceed 2.0 multiplied by the "average contribution percentage" of all other Eligible Employees who are not in such group, subject to a maximum differential of two percentage points. The "average contribution percentage" for a specified group for a Plan Year shall mean the average of the ratios (calculated separately for each Employee in such group) of (i) over (ii) where: (i) equals the sum of the Eligible Employee's After-Tax Participant Contribution(s) for the Plan Year pursuant to Section 3.2 plus the Matching Contribution made on behalf of the Eligible Employee for the Plan Year pursuant to Section 4.1; and (ii) equals the Eligible Employee's compensation for such Plan Year as provided in Code Section 414(s), including any alternative definitions thereunder. For purposes of determining the "contribution percentage" of an Eligible Employee who is a 5% owner or one of the ten most highly- paid Highly Compensated Employees, the After-Tax Participant Contribution(s), Matching Contributions and compensation of such Eligible Employee shall include the After-Tax Participant Contribution(s), Matching Contributions and compensation for the Plan Year of "family members" (as defined in Code Section 414(q)(6)) as may be required pursuant to the family aggregation rules of Code Section 401(m) and pertinent regulations issued thereunder. To such extent as required by regulations, family members with respect to Highly Compensated Employees shall be disregarded as separate Employees in determining the "contribution percentage" both for Eligible Employees who are non-highly compensated Employees and for Eligible Employees who are Highly Compensated Employees. If the Participating Employer sponsors two or more plans to which After-Tax and matching Employer Contributions are made and which are subject to Code Section 401(m), but are considered one plan for purposes of Code Section 401(a)(4) or 410(b), such plans shall be treated as one plan for purposes of determining the "average contribution percentage". If any Eligible Employee who is a member of the Highly Compensated Group is participating in two or more plans sponsored by the Employer or an Affiliated Employer that include After-Tax and/or matching Employer Contributions subject to Code Section 401(m), all such contributions will be treated as made under one plan for purposes of this paragraph (b). (c) If for any Plan Year the "average contribution percentage" for the Highly Compensated Group exceeds the limits set forth in (a) and (b) above, the "excess aggregate contributions" (as defined in Code Section 401(m)(6)(B)) shall be distributed to the Highly Compensated Group within 2-1/2 months, if at all possible, following the end of the Plan Year in which such contributions were made and in no event later than the close of the following Plan Year. The distribution of such "excess aggregate contributions" shall be effected by successive reductions of the After-Tax and/or Matching Contribution percentage(s) of one or more members of the Highly Compensated Group with the highest "average contribution percentage" until the "average contribution percentage" applicable to the Highly Compensated Group does not exceed the maximum "average contribution percentage" referred to above. The distributable amount for each affected member of the Highly Compensated Group shall be determined in accordance with the following provisions: (i) After-Tax Participant Contribution(s) made during the Plan Year shall be returned to the Highly Compensated Employee until he has no remaining "excess aggregate contributions" or until all of his After-Tax Participant Contribution(s) for the Plan Year have been distributed; then (ii) Matching Contributions made during the Plan Year to the Highly Compensated Employee shall be distributed to such Highly Compensated Employee or forfeited at the Committee's discretion until he has no remaining "excess aggregate contributions" or until all of his Matching Contributions for the Plan Year have been distributed/forfeited. In the event that any "excess aggregate contributions" are forfeited, such amounts shall be used to reduce future Matching Contributions to the Plan. The return of any "excess aggregate contributions" shall be made on a pro-rata basis from the funds in which the "excess aggregate contributions" are then invested, unless the Committee shall permit the Participant to elect such other method of return based on such uniform and nondiscriminatory rules as it may adopt. In the case of an Eligible Employee who is subject to the family aggregation rules of Code Section 414(q)(6) because he is a member of a family of a 5% owner of the Employer or of one of the ten most highly paid Highly Compensated Employees, the determination of and return of "excess aggregate contributions" under this Section shall be made in accordance with the family aggregation rules of Code Section 401(m) and pertinent regulations issued thereunder. (d) The "excess aggregate contributions" to be distributed to a Participant shall be adjusted for investment earnings or losses applicable thereto. (e) For purposes of determining the investment earnings or losses to be distributed pursuant to the foregoing paragraphs, the following rules shall apply: The earnings or loss is the sum of earnings or losses allocable to the Participant's After-Tax Participant Contribution(s) Account and Matching Contribution Account for the Plan Year multiplied by a fraction, the numerator of which is After-Tax Participant Contribution(s) and Matching Contributions to be returned to the Eligible Employee for the year and the denominator is the Eligible Employee's Account balance(s) attributable to After-Tax Participant Contribution(s) and Matching Contributions without regard to any earnings or loss occurring during such Plan Year. 4.4 Aggregate Limit Test. (a) For any Plan Year commencing on or after January 1, 1989, in which the "average deferral percentage" (as defined in Section 3.8) and the "average contribution percentage" (as defined in Section 4.3) of the Highly Compensated Group can only satisfy the limitations set forth in Sections 3.8(c)(ii) and 4.3(b) respectively, but neither can satisfy the limitations set forth in Sections 3.8(c)(i) and 4.3(a), respectively, and all corrective measures have been taken under Sections 3.8 and 4.3 to ensure compliance with the provisions of Code Sections 401(k) and 401(m), the "aggregate limit test" prescribed under proposed Treasury Regulation 1.401 (m)-2(b)(3), or pertinent final regulations shall be applicable. The "aggregate limit test" shall be deemed met if (i) below is greater than or equal to (ii) below where: (i) equals the sum of (A) and (B) below where: (A) equals 1.25 multiplied by the greater of (1) and (2) where: (1) equals the "average deferral percentage" of the non-highly compensated group of Eligible Employees; and (2) equals the "average contribution percentage" of the non-highly compensated group of Eligible Employees; (B) equals the lesser of (1) and (2) above plus two percentage points. In no event, however, shall this amount exceed 2.0 multiplied by the lesser of (1) and (2) above. (ii) equals the sum of (C) and (D) below where: (C) equals the "average deferral percentage" of the Highly Compensated Group; and (D) equals the "average contribution percentage" of the Highly Compensated Group. (b) An "alternative aggregate limit test" may be used in place of the "aggregate limit test" set forth in (a) above for any Plan Years commencing on or after January 1, 1989, as long as such test is permitted by the Internal Revenue Service. This "alternative aggregate limit test" shall be deemed met if (i) below is greater than or equal to (ii) below where: (i) equals the sum of (A) and (B) below where: (A) equals 1.25 multiplied by the lesser of (1) and (2) where: (1) equals the "average deferral percentage" of the non-highly compensated group of Eligible Employees; and (2) equals the "average contribution percentage" of the non-highly compensated group of Eligible Employees; (B) equals the greater of (1) and (2) above plus two percentage points. In no event, however, shall this amount exceed 2.0 multiplied by the greater of (1) and (2) above. (ii) equals the sum of (C) and (D) below where: (C) equals the "average deferral percentage" of the Highly Compensated Group; and (D) equals the "average contribution percentage" of the Highly Compensated Group. (c) The Committee shall determine each Plan Year the appropriate reductions, distributions, or forfeitures to be made in order to satisfy the applicable limits set forth in this Section 4.4 and in Sections 3.8 and 4.3. Any such reductions, distributions or forfeitures shall be made in accordance with the applicable provisions of Sections 3.8 and 4.3 and the nondiscrimination requirements of Code Section 401(a)(4). (d) In the event that the "average deferral percentage", the "average contribution percentage" and the "aggregate limit" of the Highly Compensated Group does not satisfy the requirements set forth in Sections 3.8, 4.3, and this 4.4, respectively, the Employer may for any Plan Year perform such testing by restructuring the Plan into component plans as may be permitted in regulations under Code Section 401(a)(4), provided such component plans meet the coverage requirements of Code Section 410(b). 4.5 Maximum Total Allocations. (a) Effective January 1, 1987, anything to the contrary herein notwithstanding, in no event shall the Annual Additions, as defined in Section 4.6, for any Employee for any Plan Year exceed the lesser of: (i) $30,000 or, if greater, 1/4 of the dollar limitation in effect under Code Section 415(b)(1)(A) (which amount shall be subject to adjustments as provided by Treasury regulations under Code Section 415), or (ii) 25% of the Employee's compensation (as defined by Treasury regulations under Code Section 415(c)) from the Participating Employer. For purposes of this Section 4.5(a), the Plan Year shall be the limitation year. In the event an Annual Addition in excess of the lesser of (i) or (ii) above is allocated to an Employee for a Plan Year, such excess shall be corrected in the following order to the extent required to eliminate the excess: (iii) After-Tax Participant Contribution(s) plus any allocable interest shall be refunded to the Employee, if such contributions were made to this Plan or any other qualified plan of the Employer for the Plan Year. (iv) Matching Contributions shall be reduced. Any reduction in Matching Contributions shall be credited to a suspense account and treated as the first allocation of Matching Contributions on behalf of such Employee for the following Plan Year and, if not fully utilized for such allocation, the remainder shall be allocated prorata to the Matching Contribution Accounts of the other Employees on the last day of the following Plan Year. (v) Pre-Tax Participant Contribution(s) shall be reduced. Any reduction of Pre-Tax Participant Contribution(s) shall be credited to a suspense account and treated as the first allocation of Pre-Tax Participant Contribution(s) on behalf of such Employee for the following Plan Year (and succeeding Plan Years as necessary) or, any such contribution shall be refunded in accordance with Section 415 of the Code. In the event that any Pre-Tax Participant Contribution(s) in the suspense account have not been allocated as Pre-Tax Participant Contribution(s) to the Employee as of his Service Termination Date, the Employer shall directly reimburse the Employee for such remaining amounts, including any investment earnings thereon as may be required under pertinent regulations. No contributions shall be made to the Plan on behalf of an Employee for any period during which a suspense account is in existence for such Employee. (b) In the case of an Employee who has participated in a defined benefit plan maintained by the Employer or an Affiliated Employer, the sum of the "defined benefit plan fraction" and the "defined contribution plan fraction," determined as of the close of any Plan Year, shall not exceed one. An Employee's defined benefit plan fraction and defined contribution plan fraction shall be determined as follows: (i) The "defined benefit plan fraction" is a fraction with a numerator equal to the Employee's projected annual retirement benefit determined (other than any benefit attributable to Employee contributions) under the defined benefit plan and a denominator equal to the lesser of (A) 1.25 multiplied by the dollar limitation in effect under Code Section 415(b)(1)(A) for such Plan Year, or (B) 1.4 multiplied by 100% of the Employee's compensation which may be taken into account for such Plan Year. (ii) The "defined contribution plan fraction" is a fraction with a numerator equal to the sum of the Annual Additions to the Employee's Account and a denominator equal to the sum for each calendar year of the Employee's employment with the Employer, any predecessor of the Employer, or an Affiliated Employer of the lesser of (A) 1.25 multiplied by the amount determined in accordance with Code Section 415(e)(3)(B)(i) for each such Plan Year, or (B) 1.4 multi- plied by 25% of the Employee's compensation (as defined by Treasury Regulations under Code Section 415) which may be taken into account for each such Plan Year. For the purpose of applying this Section 4.5(b), all defined benefit plans and all defined contribution plans maintained by the Employer and all Affiliated Employers shall be aggregated. It is intended that this Section 4.5 shall be applied in a manner which will be in the best interest of an Employee, as determined by the Committee. Accordingly, the Committee shall reduce an Employee's Annual Additions under this Plan so that such fraction equals one only if the terms of the defined benefit plan in which the Employee is participating does not allow for a reduction of the Employee's benefit so that such fraction equals one. 4.6 Annual Additions. Effective January 1, 1987, the Annual Addition with respect to an Employee for any Plan Year shall be the sum of the following amounts allocated to his Account for the Plan Year: (a) All After-Tax Participant Contribution(s) made subsequent to December 31, 1986, and prior to January 1, 1987, the lesser of one-half of an Employee's After-Tax Participant Contribution(s), or the amount of his After-Tax Participant Contribution(s) in excess of 6% of his Earnings, plus (b) Matching Contributions plus any other Employer contributions made to a qualified plan, plus (c) Pre-Tax Participant Contribution(s), plus (d) Any forfeitures allocated to the Employee's Account, plus (e) Any amount applied from the suspense account (pursuant to Section 4.5), plus (f) Excess contributions and excess aggregate contributions as defined in Code Sections 401(k)(8)(B) and 401(m)(6)(B), respectively, plus (g) Excess deferrals, as defined in Code Section 402(g), to the extent such excess deferrals have not been returned to the affected Employee by the April 15 following the taxable year in which such excess deferral was made; plus (h) Amounts described in Code Sections 415(l)(1) and 419A(d)(2). For purposes of applying this Section 4.6, all defined contribution plans maintained by the Employer and all Affiliated Employers shall be aggregated. The term Annual Additions shall not include any Rollover Contributions. 4.7 Contributions Conditioned on Tax Deductibility. All Pre-Tax Participant Contribution(s) and Matching Contributions shall be conditioned upon their deductibility by the Participating Employer for federal income tax purposes; provided, however, that no contributions shall be returned to a Participating Employer, except as provided in Section 4.8. 4.8 Return of Contributions. Notwithstanding any other provision of this Plan, a Pre-Tax Participant Contribution(s), or Matching Contribution upon request by the Participating Employer may be returned to the Participating Employer who made the contribution if: (a) the contribution was made by reason of a mistake of fact; or (b) the contribution was conditioned upon its deductibility for income tax purposes and the deduction was disallowed; and Such contribution shall be returned to the Participating Employer within one year of the mistaken payment of the contribution or the disallowance of such deduction, as the case may be. The amount which may be returned to the Participating Employer is the excess of the amount contributed over the amount that would have been contributed had there not occurred the circumstances causing the excess. Earnings attributable to the excess contribution may not be returned to the Participating Employer, but losses thereto shall reduce the amount to be returned. Furthermore, if the withdrawal of the amount attributable to the excess contribution would cause the balance of the Account of any Participant to be reduced to less than the balance which would have been in the Account had the excess amount not been contributed, then the amount to be returned to the Participating Employer shall be limited to avoid such reduction. In the event any Pre-Tax Participant Contribution(s) are returned to a Participating Employer pursuant to this Section 4.8, the Participating Employer shall directly reimburse affected Participants for the amounts so returned. Any After-Tax Participant Contribution(s) (exclusive of earnings) made by mistake of fact shall be returned to the affected Participants. 4.9 Payment of Expenses. In addition to its contributions, the Employer (or Participating Employer, if applicable) may elect to pay the administrative expenses of the Plan and fees and retainers of the Plan's Trustees, consultants, administrators, recordkeepers, auditors, counsel, and other advisors or service providers so long as the Plan or Trust Fund remains in effect. If the Employer does not elect to pay all or part of such expenses, the Trustee may pay these expenses and charge the payment thereof against the Trust Fund for the Plan Year in which the expenses were incurred. All investment expenses including investment management fees, brokerage fees, taxes and other expenses associated with Plan investments shall be paid from the investment fund assets. The Trustee, if so authorized by the Committee, may apportion the administrative expenses to be paid from the Trust Fund. Such expenses will be allocated to Participants according to procedures and methodologies to be established by the Committee so long as such procedures and methodologies of apportioning the expenses are executed under rules uniformly applied in a nondiscriminatory manner. ARTICLE V INVESTMENT OF CONTRIBUTIONS 5.1 Committee to Establish Accounts. The Committee shall establish and maintain a separate accounting in the name of each Participant, Former Participant or, if applicable, Beneficiary which shall reflect all contributions by the Participant or Former Participant, all amounts contributed by the Participating Employer under the Plan on his behalf, investment experience on all such contributions, any distributions, withdrawals, and any expenses charged against such contributions. The separate accounting in the name of each Participant, Former Participant or Beneficiary shall include a separate accounting for Pre-Tax Participant Contribution(s), After- Tax Participant Contribution(s), Qualified Voluntary Employee Contribution(s), Rollover Contributions, and Matching Contributions. 5.2 Investment Options. Subject to the provisions of Sections 5.3 and 5.4, a Participant, (including any Employee who is a Participant solely with respect to Rollover Contributions) and any Former Participant shall direct the Committee to invest his Pre-Tax Participant Contribution(s), After-Tax Participant Contribution(s), Qualified Voluntary Employee Contribution(s) and Rollover Contributions, if any, in Funds available under the Plan as described below other than EUA Common Shares. Matching Contributions and any Rollover Contributions from a terminated plan maintained by the Employer which were invested in Common Shares of Eastern Utilities Associates shall be invested wholly in EUA Common Shares. For Participants who are members of a collective bargaining agreement, the investment of contributions hereunder shall be governed by the terms of such collective bargaining agreement. Fund shall mean the amounts held by any insurance company and/or Trustee in accordance with this Plan. The Employer shall maintain: (a) Capital preservation funds consisting of a money market fund or similar fund invested primarily in short-term fixed income securities, including investment contracts and annuity contracts (issued by insurance companies) or certificates of deposit issued by banks. (b) Growth and income funds invested primarily in stocks and/or bonds selected to offer the potential for capital growth and current income. (c) Growth funds invested primarily in domestic and foreign securities designed to achieve above average capital growth by assuming above average investment risk. (d) EUA Common Shares is an unsegregated investment together with earnings thereon invested in Common Shares of Eastern Utilities Associates. Contributions made to and dividends received by this Fund shall, to the extent practicable, be reinvested through the Dividend Reinvestment and Common Share Purchase Plan of Eastern Utilities Associates. For periods prior to July 1, 1992 (the date the above described Funds were offered under the Plan) the investment options and the rules applicable thereto, as described in the predecessor to this document, shall apply. The Committee may, with the approval of the Board, eliminate one or more investment funds, offer additional investment funds, or alter the underlying investments of one or more funds from time to time. Participants shall be notified of any changes in investment funds prior to the effective date of such changes. 5.3 Change in Investment Options. Subject to Section 5.4, a Participant may change the investment allocation of his future Pre-Tax Participant Contribution(s), After-Tax Participant Contribution(s), Rollover Contributions, if any, on a monthly basis by phone in accordance with the rules of the Trustee. Subject to Sections 5.2 and 5.4, a Participant or Former Participant may also change the investment allocation of his existing Pre-Tax Participant Contribution(s) Account, After-Tax Participant Contribution Account, Qualified Contribution Account and Rollover Contribution(s) Account, on a daily basis by phone in accordance with the rules of the Trustee. The Committee may elect to change the Trustee and/or recordkeeper relationship at any time. Upon such change, the Committee may temporarily suspend the right of Participants to change or make elections regarding the investment of Accounts and the Committee may temporarily direct the investment of all or a portion of their Accounts into a money market fund or similar fund consisting primarily of short term fixed income securities or other fund deemed appropriate to effect an efficient transition to the new recordkeeper and investment funds. Notice of such suspension will be provided to all eligible participants. 5.4 Investment Rules. The following rules shall govern all aspects of this Article V: (a) A Participant shall direct the Committee to invest his current Pre-Tax Participant Contribution(s), After-Tax Participant Contribution(s), and Rollover Contributions, if any, in multiples of 5%, in Funds A, B, C, D, E, or F. Reallocation of the Participant's or Former Participant's existing Account pursuant to Section 5.3 shall also be made to Funds A, B, C, D, E, or F in multiples of 5%. (b) A Participant's or Former Participant's Matching Contribution Account and Rollover Contribution Account attributable to amounts distributed from a terminated plan maintained by the Employer which was invested in Common Shares of Eastern Utilities Associates shall be invested exclusively in EUA Common Shares. Notwithstanding the foregoing, for Participants who are members of a collective bargaining agreement, the investment rules with respect to Employee and Employer contributions hereunder shall be governed by the terms of such collective bargaining agreement. (c) Any investment direction given by a Participant or Former Participant shall continue in effect until changed by such Participant or Former Participant as provided hereunder. (d) In the absence of any written designation of investment preference by the Participant or Former Participant, Pre-Tax Participant Contribution(s), After-Tax Participant Contribution(s), Qualified Voluntary Employee Contribution(s), Rollover Contributions (other than Rollover Contributions described in (b) above), if any, shall be invested 100% in short-term fixed income investments. (e) Notwithstanding any instruction from any Participant or Former Participant for investment of funds as provided in this Article V, the Trustee shall have the right to hold uninvested, or invested in short-term fixed income investments, any funds intended for investment or reinvestment as otherwise provided in this Article for such time as the Trustee, in its sole discretion, deems advisable. (f) The Committee may limit changes otherwise permitted hereunder in the investment allocation of a Participant's or Former Participant's Account to the extent a change is precluded as a result of a temporary period of adverse liquidity with respect to an investment fund or to the extent a change would adversely affect the investment return of Accounts of other Participants or Former Participants. (g) For periods prior to July 1, 1992 (the date the Funds described in Section 5.2 were offered under the Plan) the investment options, and the rules applicable thereto, as described in the predecessor to this document shall apply. ARTICLE VI TRUST FUND 6.1 Trust Fund. All Accounts shall be held in the Trust Fund and each Participant's and Former Participant's interest in the investment funds shall be valued in accordance with the further provisions of this Article VI. The Trust Fund shall be held and administered under a Trust Agreement between the Employer and the Trustee. The Employer, in its sole discretion, shall have the right to change the method of funding or the designation of Trustee, subject only to any contractual restrictions of the existing method of funding. The Trust shall hold all contributions made under the Plan and all earnings and other income attributable thereto. All amounts payable under the Plan shall be disbursed from the Fund. 6.2 Valuation of Funds. The current market value of each Fund shall be separately determined by the Trustee as of every Valuation Date. (a) For those securities traded on a national stock exchange, the current market value shall be the closing price on the Valuation Date. (b) For those securities not traded on a national stock exchange, the current market value shall be the average of the latest available bid and ask quotes as of the Valuation Date. If there is no trading of a security on a national stock exchange on the Valuation Date or if bid and ask quotes are not available for a security for a substantial amount of time, the current market value of such security shall be determined on the basis of such market quotations or other method as the Trustee shall deem appropriate. 6.3 Valuation of Participant Accounts. The Trustee shall maintain a separate account for each Participant and Former Participant, including a separate record of the share of each Participant or Former Participant in each Fund attributable to contributions by the Employer and to Pre-Tax, After-Tax, Qualified and Rollover Contributions by the Participant. Each Participant's or Former Participant's share in a Fund shall be determined as of each Valuation Date and shall reflect contributions credited to his Account and all withdrawals and forfeitures from his Account since the last Valuation Date. 6.4 Investment Responsibilities of the Committee Relating to Investments. The Committee, with the approval of the Board, shall invest and reinvest the Trust Fund in such securities and other property in accordance with the provisions of this Plan; provided, however, that the Committee shall not engage in any "prohibited transaction" as defined under ERISA. The Committee shall have such powers as may be necessary to discharge its duties under the Plan, including, but not limited to, the power: (a) to make, execute, acknowledge, and deliver any and all deeds, leases, assignments, and instruments; (b) to cause any investments from time to time held by it to be registered in, or transferred into, its name or in the name of its nominee or nominees or to retain them unregistered or in form permitting transferability by delivery, but the books and records of the Committee shall at all times show that such investments are part of the Fund; (c) except in the case of Common Shares of Eastern Utilities Associates, to vote in person or by proxy on any stocks, bonds or other securities held by it; to exercise any options appurtenant to any stocks, bonds, or other securities for the conversion thereof into other stocks, bonds or securities, or to exercise any rights to subscribe for additional stocks, bonds, or other securities and to make any and all necessary payments therefore; to join in, or to dissent from, and to oppose, the reorganization, recapitalization, consolidation, liquidation sale, or merger of corporations or properties in which it may be interested as investment manager, upon such terms and conditions as it may deem wise; (d) in the case of Common Shares of Eastern Utilities Associates, to carry out, or cause to be carried out, the voting instructions of Participants respecting their interests in such Shares; (e) to select depositories for the care, custody, and safekeeping of any and all securities or other property of the Fund; (f) to select, replace and/or eliminate one or more of the investment funds offered under the Plan; (g) to delegate investment management responsibilities to one or more persons; (h) to perform all acts which they deem necessary or proper for the protection of the property of the Fund. 6.5 Statements of Participant Accounts. No less frequently than is practicable after the completion of a Plan Year, an individual statement will be issued to each Participant showing the value of his interests in any of the investment funds which may be offered under the Plan. 6.6 Valuation for Distribution. All withdrawals and distributions shall be valued as of a Valuation Date and paid out as soon as practicable thereafter or at such other time as the Committee may permit under uniform and nondiscriminatory rules it may adopt. ARTICLE VII DEATH AND DISABILITY 7.1 Death Benefit. Upon the death of a Participant or Former Participant, his Beneficiary shall be entitled to 100% of the Participant's or Former Participant's remaining Account. Such Account shall be held and maintained for the benefit of the Beneficiary and the Beneficiary shall be entitled to exercise the Participant's or Former Participant's rights respecting investment of such Account and full and immediate repayment of any outstanding loan, provided that the Beneficiary may not elect to take a new loan from such Account or to make a partial withdrawal. 7.2 Payment of Death Benefit. After receipt by the Committee of due notice of the death of the Participant, the benefit payable under this Article shall be paid in one lump sum in accordance with the provisions of Article X. 7.3 Designation of Beneficiary. Each Participant shall have the right, by written notice to the Committee, to designate or to change the Beneficiary to receive any benefit payable in the event of his death, subject to the spousal consent requirements of Section 1.6, if he is then married. 7.4 Payment Other Than to Beneficiary. If a Participant has not designated a Beneficiary, or the Participant's designated Beneficiary dies before the Participant, or if the Beneficiary dies after the death of the Participant, but prior to receiving the full death benefit hereunder, any remaining benefit shall be paid to the Benefi- ciary's designated beneficiary. In the absence of such designation, any remaining benefit will be paid to the Beneficiary's estate, unless specified otherwise by the Participant. 7.5 Definition of Disability. A Participant will be deemed to have suffered a total and permanent disability for purposes of the Plan if he is eligible to receive Social Security disability benefits or disability benefits under a long-term disability plan sponsored by the Employer or an Affiliated Employer. 7.6 Disability Benefit. A Participant who has suffered a Disability shall be entitled to distribution of 100% of the value of his Account upon written request pursuant to the provisions of Article X. 7.7 Recovery from Disability. (a) If it is subsequently determined that a Participant who had become permanently disabled is no longer disabled, and if he should return to employment with a Participating Employer immediately upon recovery from Disability, he shall resume membership in the Plan pursuant to Article II. In the event his Account has not been distributed prior to his recovery from Disability, he shall not be entitled to a distribution of his Account prior to his Service Termination Date except as may be permitted under Article IX. (b) If it is subsequently determined that a Participant who had become permanently disabled is no longer disabled, and if he should fail to return to employment with a Participating Employer or an Affiliate immediately upon recovery from Disability, he shall be considered to have a Service Termina- tion Date upon such recovery. In the event his Account has not been distributed upon his recovery from Disability, his Account shall be distributed pursuant to the provisions of Article X. ARTICLE VIII VESTING AND TERMINATION OF EMPLOYMENT 8.1 Vesting of Contributions. Subject to the further provisions of this Article VIII, a Participant shall at all times be 100% vested in his Account hereunder. 8.2 Vesting Prior to August 1, 1983. (a) Any Participant who is actively employed on or after August 1, 1983 shall be 100% vested in his Account, except to the extent that any portion of his Account may have been forfeited pursuant to the further provisions of this Article. (b) Any Participant who terminated employment with the Employer and all Affiliated Employers prior to August 1, 1983 and who does not subsequently return to employment with the Employer or an Affiliated Employer shall not have any interest in that portion of his Account that may have been forfeited as a result of such termination of employment. (c) If an Employee has a Service Termination Date prior to August 1, 1983, and is reemployed on or after August 1, 1983 by a Participating Employer or an Affiliated Employer: (i) before he has incurred a number of consecutive One Year Breaks in Service equal to the greater of five and his Service as of his Service Termination Date, or, if he was at least partially vested pursuant to the provisions of the Plan as in effect prior to August 1, 1983 on his Service Termination Date, he shall be reinstated in the portion of his Matching Contribution Account that may have been forfeited pursuant to the Plan as in effect prior to August 1, 1983. Any amounts reinstated in accordance with this paragraph shall be paid by the applicable Participating Employer with an additional contribution to the Plan. Upon reemployment, the Employee shall be 100% vested in his Account. (ii) after he has incurred a number of consecutive One Year Breaks in Service equal to the greater of five and his Service as of his Service Termination Date, and he was not partially or fully vested pursuant to the provisions of the Plan as in effect prior to August 1, 1983 on his Service Termination Date, he shall have no further right to the portion of his Matching Contribution Account that may have been forfeited pursuant to the Plan as in effect prior to August 1, 1983. The Employee shall be 100% vested in his Matching Contribution Account attributable to contributions made subsequent to his return to employment only. 8.3 Method of Payment. When a Participant incurs a Service Termination Date, his Account shall be distributed pursuant to the provisions of Article X. ARTICLE IX WITHDRAWALS 9.1 Withdrawals from Matching and Rollover Contribution Accounts. Subject to the further provisions of this Article IX, a Participant who has been a Participant in the Plan for at least five full years shall have the right to withdraw any portion of his Account attributable to Matching and Rollover Contributions at any time. A Participant who has not completed five full years of participation may withdraw at any time any amount from the vested portion of his Matching and Rollover Contribution Accounts other than Matching and Rollover Contributions made during the 24 months preceding the date of such withdrawal. Notwithstanding the foregoing, subject to the further provisions of this Article IX, a Participant may withdraw all or a portion of his Matching and Rollover Contributions to the extent necessary to meet a financial hardship. 9.2 Withdrawals from After-Tax Participant Contribution(s) Account. Subject to the further provisions of this Article IX, a Participant may withdraw any portion of his Account attributable to After-Tax Participant Contribution(s) for any reason. Any hardship withdrawal made from a Participant's After-Tax Account shall be subject to the provisions of Sections 9.5 and 9.6. 9.3 Withdrawals from Qualified Voluntary Employee Contribution(s) Account. Subject to the further provisions of this Article IX, a Participant may withdraw all or a portion of his Account attributable to Qualified Voluntary Employee Contribution(s) for any reason. 9.4 Withdrawals from Pre-Tax Participant Contribution(s) Account. Subject to the further provisions of this Article IX, specifically with reference to Section 9.6, a Participant may withdraw all or a portion of his Account attributable to Pre-Tax Participant Contribution(s) to the extent necessary to meet a financial hardship as outlined in Section 9.5. 9.5 Hardship Withdrawals. For the purposes of this Article IX, a "financial hardship" shall mean an immediate and heavy financial need which cannot be met from any other available resource and which is due to: (a) unreimbursed medical expenses described in Code Section 213(d) for which payment is necessary in advance in order to obtain medical services for the Participant, his Spouse, or dependents or for such medical expenses already incurred by the Participant, his Spouse, or dependents; (b) the purchase of the Participant's principal residence (not including mortgage payments, remodeling or investment property purchase); (c) the need to prevent eviction from, or foreclosure on the Participant's principal residence; (d) tuition payments and related educational expenses for the next 12 months, semester, or quarter of post-secondary education for the Participant, his Spouse or dependents; or (e) such additional immediate and heavy financial needs as may be approved by the Committee on a uniform and nondiscriminatory basis. The Committee shall determine in its sole discretion whether a financial hardship exists to warrant a withdrawal, and if such hardship exists, the amount of the withdrawal necessary to meet the hardship. Such determination shall be made on the basis of written documentation, provided by the Participant, which demonstrates the existence and amount of the financial hardship. In any event, the Committee's determination shall be made according to such uniform and non-discriminatory rules as it may adopt. A Participant shall be deemed to lack other resources to satisfy the "financial hardship" if the following conditions are satisfied: (f) the Participant has withdrawn all After-Tax, Matching, Rollover and Qualified Voluntary Employee Contribution(s) available hereunder and all amounts available to him under all other of the Employer's (or Affiliated Employer's) qualified plans; (g) the Participant has borrowed, through a loan, any amounts available to him from any qualified plans of the Employer and Affiliated Employers, unless the repayment of the amount borrowed would constitute a "financial hardship" to the Participant; and (h) the amount of the withdrawal does not exceed the amount necessary to meet the Participant's "financial hardship". 9.6 Rules For Withdrawals. The following rules shall apply to withdrawals made pursuant to this Article IX: (a) No more than one non-hardship withdrawal may be made in any three-month period unless otherwise permitted in accordance with such uniform and nondiscriminatory rules as the Committee may adopt. (b) The minimum amount of any non-hardship withdrawal from the Plan shall be $500 or, if less, 100% of the amount in the Participant's Account that is available as a withdrawal under the provisions of this Article. (c) A Participant who has not attained age 59-1/2 may not withdraw that portion of his Pre-Tax Participant Contribution(s) Account which is attributable to investment earnings which are credited to such Account after December 31, 1988. (d) In the event of a non-hardship withdrawal from the Participant's After-Tax Participant Contribution(s) Account or from his Matching and/or Rollover Contribution Account that does not exceed 50% of the value of the Participant's Account, exclusive of his Qualified Voluntary Employee Contribution(s) Account, the Participant shall be suspended from making any further Pre-Tax or After-Tax Participant Contribution(s) under the Plan for a period of six months from the date of the withdrawal. No Employer Matching Contributions will be made during the suspension period. (e) In the event of a non-hardship withdrawal from the Participant's After-Tax Participant Contribution(s) Account or from his Matching and/or Rollover Contribution Account that exceeds 50% of the value of the Participant's Account, exclusive of his Qualified Voluntary Employee Contribution(s) Account, the Participant shall be suspended from making any further Pre-Tax or After-Tax Participant Contribution(s) under the Plan for a period of 12 months from the date of the withdrawal. No Employer Matching Contributions will be made during the suspension period. (f) In the event a withdrawal is on account of a financial hardship, the Participant shall be suspended from making any further Pre- Tax or After-Tax Participant Contribution(s) under the Plan for a period of 3 months from the date of the withdrawal. No Employer Matching Contributions will be made during the suspension period. (g) In the event a withdrawal consists of a withdrawal from more than one of a Participant's investment funds within his Account, such withdrawal shall be considered a single withdrawal for the purpose of applying paragraph (d) or (e) above. (h) Any suspension of Pre-Tax and After-Tax Participant Contribution(s) resulting from the application of paragraph (d), (e) or (f) above shall be in addition to rather than coincident with any suspension which may apply pursuant to Article III. No more than one 12-month suspension shall be required, however, for a single withdrawal under this Article IX. (i) Any withdrawal made from a Participant's After-Tax Participant Contribution(s) and/or investment earnings thereon shall be made in a manner which corresponds with the tax treatment of such a withdrawal under the Code. (j) A Participant shall request a withdrawal hereunder by providing the Committee with at least 30 days' advance written request of the withdrawal, except that the Committee may agree to accept a later request in the case of a withdrawal for "financial hardship". The Participant will receive such payment as soon as practicable after the Committee receives the request. (k) Withdrawals shall be effective as of the Valuation Date next following the date the Committee approves the withdrawal request, unless the Committee agrees to another date according to uniform and nondiscriminatory rules it may adopt. (l) Any withdrawal shall be paid in cash, except that a Participant electing a non-hardship withdrawal may elect to receive Common Shares of Eastern Utilities Associates for such non-hardship withdrawal with respect to the portion of his Account invested in such Shares. (m) If the Participant has made a withdrawal from his Pre-Tax Participant Contribution(s) Account, the Participant's Pre-Tax and After-Tax Contributions to the Plan are suspended for the 3- month period immediately following the date of the hardship withdrawal. (n) The Participant's maximum Pre-Tax Participant Contribution(s) permitted under Section 3.8(a) for the Plan Year following the Plan Year in which the hardship withdrawal was made is reduced by the amount of the Participant's Pre-Tax Participant Contribution(s) made during the Plan Year in which the hardship withdrawal occurred. 9.7 Debiting of Withdrawals. To the extent otherwise permitted by this Article IX, all withdrawals shall be debited to a Participant's Account in the following hierarchy; first from his After-Tax Participant Contribution(s) Account, next from his Rollover Contribution Account, next from his Qualified Voluntary Employee Contribution(s) Account, next from his Matching Contribution Account. In the case of Hardship withdrawals only, after the above sources have been exhausted, withdrawals shall be debited next to a Participant's Pre-Tax Contribution Account. In the event that the provisions of this Article IX prohibit a withdrawal from a Participant's Account in the sequence described in the preceding sentence, the amounts withdrawn shall follow such sequence only to the extent otherwise permitted by the provisions of this Article IX. Except in the case of a withdrawal from a Participant's Matching Contribution Account, a withdrawal will be debited to his interest in the Funds offered under this Plan on a pro-rata basis. 9.8 Participant Loans. The Plan may lend a Participant who is actively employed an amount not in excess of the lesser of (a) $50,000 reduced by the Participant's highest outstanding loan balance from the Plan during the preceding 12-month period; and (b) 50% of the value of his Rollover, Pre-Tax and Matching Contribution Accounts as of the date on which the loan is approved. A loan may be made only from a Participant's Rollover Account (but not from any portion of such Account invested in Common Shares of Eastern Utilities Associates) and/or his Pre-Tax Participant Contribution(s) Account. 9.9 Rules Relating to Loans. All loans shall comply with the following terms and conditions: (a) The minimum amount that may be borrowed under the Plan is $1,000. (b) Loans may be applied for as of any date with prior written notice as the Committee may approve according to uniform and nondiscriminatory rules it may adopt. (c) No more than one regular loan (a loan for a purpose other than the purchase of the Participant's principal residence) and one housing loan (a loan for the purpose of purchasing the Participant's principal residence) may be outstanding to a Participant at any time. (d) An application for a loan by a Participant shall be made in writing to the Committee whose action thereon shall be final. Furthermore, appropriate documentation for the purchase of a home, such as a purchase and sale agreement, must be provided. (e) Repayment of a loan shall be made based on level amortization of the loan amount, including interest, and shall be made no less frequently than quarterly over the term of the loan. The Participant shall authorize the Participating Employer to deduct from his pay the level amount sufficient to accomplish the repayment. A Participant who is on an Authorized Leave of Absence or layoff shall continue to repay any outstanding loan by submitting payments to the committee responsible for plan administration. (f) The period of repayment for any loan shall be arrived at by mutual agreement between the Committee and the Participant, but subject to a maximum repayment period of five years for a regular loan and 20 years for a housing loan. (g) Loans may be prepaid in full at any time without penalty, but at no time will a partial payment of principal or interest only be allowed. (h) Each loan shall be made against the collateral assignment of the Participant's right, title and interest in the portion of his Account against which the loan is taken, evidenced by such Participant's collateral promissory note for the amount of the loan, including interest, payable to the order of the Plan. (i) Each loan shall bear a reasonable rate of interest, which shall be the highest prime rate of interest, as published in the "money rate" section of the Wall Street Journal as of the last day of the calendar quarter preceding the effective date of the loan. The Committee shall review from time to time the rate of interest to determine if it is consistent with commercial rates for similar loans, and if not, the Committee shall have the authority to modify such rate of interest for new loans to be consistent with such commercial rates. (j) In the event a loan repayment is not made or is not paid at maturity, the loan shall be deemed to be in default and the Committee shall give written notice of such default to such Participant to his last known address. If the default is not cured within a reasonable period of time from the date of such notice as determined by the Committee, according to uniform and nondiscriminatory rules it may adopt and set forth in the notice, the Participant's Account shall be reduced by the amount of the unpaid balance of the loan, together with the interest at the time of default thereon, and the Participant's indebtedness shall thereupon be discharged. This reduction shall occur as soon as the Participant could have received a distribution of the portion of the Account balance so reduced under applicable law, disregarding the provisions of (k) below. (k) Upon termination or retirement, no distribution shall be made to any Participant or Former Participant or to a Beneficiary of any such Participant or Former Participant unless and until all unpaid loans, including accrued interest thereon, have been liquidated; provided, however, if any unpaid balance is due on a loan of such Participant or Former Participant at the time of such distribution which has not been satisfied through collection or liquidation of his Account, the Plan shall distribute to such Participant or Former Participant or Beneficiary the collateral promissory note evidencing the loan, and his Account, reduced by the unpaid balance of the loan, including accrued interest thereon, shall be distributed. (l) All loans shall be debited to a Participant's Account first from his Rollover Contribution Account and next from his Pre-Tax Participant Contribution(s) Account. (m) Subject to the provisions of paragraph (l) above, all loans shall be debited on a pro-rata basis to the investment funds in which the Account is invested, provided that the proceeds for a loan shall in no event be withdrawn from amounts invested in Common Shares of Eastern Utilities Associates or any other Company Matching Contributions. (n) Upon receipt of a loan repayment and associated interest, the Trustee shall deposit such repayment in the investment funds in accordance with the Participant's investment designation at the time of the repayment. The Trustee shall also credit such repayment to the Participant's Accounts in the same proportion as the Participant's investment designation at the time of the repayment. (o) The Committee shall make loans available hereunder on a reasonably equivalent basis. The Committee shall apply objective criteria in a uniform and nondiscriminatory manner to determine whether a loan application should be approved. Such criteria shall be limited to those factors which would be considered by a commercial lender in the business of making similar types of loans. Decisions by the Committee regarding loans shall be final and shall be communicated to the Participant as soon as practicable. (p) The Committee may adopt such other rules and regulations relating to loans as it may deem appropriate, including imposing reasonable loan expense charges to the Accounts of Participants electing loans. ARTICLE X PAYMENT OF BENEFITS 10.1 Entitlement to Distribution. A Participant (or, if applicable, his Beneficiary) shall be entitled to a distribution upon his termination of employment, his total and permanent disability or his death as provided herein. 10.2 Form of Payment. (a) An Account whose value is $3,500 or less must be distributed in one lump sum payment, upon completion of written instructions by the Participant. (b) The normal form of payment for an Account whose value is more than $3,500 shall also be one lump sum payment. The distribution of any Account, the value of which exceeds $3,500, shall require the written consent of the Participant. 10.3 Time of Payment. (a) To the extent practicable, and unless otherwise elected by the Participant or Former Participant pursuant to Section 10.3(c) (or, if applicable, his Beneficiary pursuant to Section 10.5) any distributions shall be made as soon as practicable after the event which gave rise to the distribution or after all contributions are credited. The value of the Participant's or Former Participant's Account for this purpose shall be determined as of the Valuation Date immediately preceding the date of distribution. Notwithstanding the foregoing, distributions shall not commence prior to the applicable date described in Section 10.3(b), unless otherwise required under Section 10.6, until the Participant, Former Participant or Beneficiary returns a completed form to the Committee with 30 days prior written notice or such lesser notice as the Committee shall approve according to uniform and nondiscriminatory rules it may adopt. However, if the Participant, Former Participant or Beneficiary fails to return the completed election form to the Committee, benefits will automatically commence within the period described in Section 10.3(b), unless prior commencement is required under Section 10.6. (b) Unless a Participant or Former Participant elects a deferred payment in accordance with Section 10.3(c), distribution shall commence no later than 60 days after the close of the Plan Year in which: (i) the Participant or Former Participant attains age 65, or (ii) the 10th anniversary of the Participant's or Former Participant's commencement of participation occurs, or (iii) the Participant or Former Participant terminates employment, whichever is latest. (c) A Participant or Former Participant who has an Account balance which is greater than $3,500 may elect, in writing, to defer the commencement of a distribution under this Article X to a date which is not later than the April 1 which follows the year in which he attains age 70-1/2. In the event a Participant or Former Participant elects to defer receipt of his Account pursuant to this paragraph, his Account shall continue to be valued in accordance with Article VI and shall be invested in accordance with the Participant's or Former Participant's election under Article V. (d) If a Participant or Former Participant has elected a deferred payment under Section 10.3(c), he may at any time thereafter elect to change the time or manner of payment of the unpaid portion of his Account in accordance with the further provisions of this Article X, provided that 60 days advance written notice, or lesser period if agreed upon by the Committee, is given to the Committee. 10.4 Amount of Distribution. The amount of any distribution shall be determined by the amount in the Participant's or Former Participant's Account as of the Valuation Date coinciding with or otherwise immediately preceding the distribution. 10.5 Death Benefits. In the event of the death of a Participant prior to the date his Account has been distributed, his remaining Account shall be paid to his Beneficiary in one lump sum pursuant to the following rules: (a) In the event the value of the Account is $3,500 or less, such Account shall be paid to the Beneficiary as soon as practicable following the Participant's or Former Participant's death. (b) Except as otherwise provided in (a) above, in the event the Beneficiary is the Participant's or Former Participant's Spouse, the Beneficiary may elect to defer payment to a date no later than April 1 following the calendar year in which the Participant or Former Participant would have attained age 70- 1/2. (c) Except as otherwise provided in (a) above, in the event the Beneficiary is not the Spouse of the Participant or Former Participant, the Beneficiary may elect to defer payment to a date no later than five years following the Participant's or Former Participant's death. Upon the death of a Participant, his Beneficiary shall be considered a Participant of the Plan, subject to the rules of the Plan hereunder. 10.6 Limitation on Distributions. Distribution of benefits to a Participant or Former Participant shall not be deferred beyond the April 1 following the calendar year in which the Participant attains age 70-1/2. In any event, distributions hereunder shall be made in accordance with Code Section 401(a)(9), including the incidental death benefit requirements of such Code Section, and regulations thereunder, including Treasury Regulation 1.401(a)(9)-2. Such regulations and applicable rulings or announcements, including any grandfather provisions or provisions delaying the effective date of Code Section 401(a)(9), are hereby incorporated by reference. 10.7 Segregated Accounts. If a Participant or Beneficiary has elected to have his Account distribution deferred to a later date pursuant to Section 10.3(c) or Section 10.6, the Account of the Participant will continue to be invested in accordance with the most recent investment direction on file with the Committee. If there is no investment direction on file, the Committee shall direct the Trustee to segregate the Participant's or Beneficiary's interest in the Plan and invest such interest in Fund A as described in Section 5.2. Amounts invested in this manner shall share the earnings, on a pro rata basis, attributable to such fund. Effective July 1, 1992, the investment of any Account whose distribution has been deferred shall be made according to the rules relating to investments as established by the Committee and investment funds. 10.8 Missing Persons. If the Committee shall be unable, within five years after any amount becomes due and payable from the Plan to a Participant, Former Participant or Beneficiary, to make payment because the identity or whereabouts of such person cannot be ascertained, the Committee may mail a notice by registered mail to the last known address of such person outlining the action to be taken unless such person makes written reply to the Committee within 60 days from the mailing of such notice. The Committee may direct that such amount and all further benefits with respect to such person shall be forfeited and all liability for the payment thereof shall terminate. However, in the event of the subsequent reappearance of the Participant, Former Participant or Beneficiary prior to termination of the Plan, the benefit which was forfeited (but not any earnings attributable to such forfeiture) shall be reinstated in full. Any benefits forfeited shall be applied to reduce future Matching Contributions to the Plan, or to pay expenses under the Plan as determined by the Committee. Reinstatement of any benefit forfeited under this Section 10.8 shall be made by the applicable Participating Employer with an additional contribution to the Plan. ARTICLE XI EMPLOYEES' SAVINGS PLAN COMMITTEE 11.1 Responsibility for Plan and Trust Administration. The Board shall have the sole authority to appoint and remove the Trustee, appoint and remove members of the Committee, approve any investment fund which may be provided for under the Trust, and to amend or terminate, in whole or in part this Plan or the Trust. The Employer, through its Committee, shall have the responsibility for the administra- tion of this Plan, which is specifically described in this Plan and the related Trust Agreement. The Employer shall be the "named fiduciary" for purposes of the Code and ERISA. 11.2 Employee Savings Plan Committee. The Plan shall be administered by the Employer through a Committee of not less than three persons to be appointed by and to serve at the pleasure of the Board. Any person appointed as a member of the Committee may resign from the Committee by delivering his written resignation to both the Board and the Secretary of the Committee. The Committee shall be the "Plan Administrator" within the meaning of Section 3(16)A of ERISA. 11.3 Agents of the Committee. The Committee may delegate specific responsibilities to other persons as the Committee shall determine. The Committee may authorize one or more of their number, or any agent, to execute or deliver any instrument or to make any payment in their behalf. The Committee may employ and rely on the advice of counsel, accountants, and such other persons as may be necessary in administering the Plan. 11.4 Committee Procedures. The Committee may adopt such rules as it deems necessary, desirable, or appropriate. All rules and decisions of the Committee shall be uniformly and consistently applied to all Participants in similar circumstances. When making a determination or calculation, the Committee shall be entitled to rely upon information furnished by a Participant, Former Participant or Benefi- ciary, the Employer, the legal counsel of the Employer or the Trustee. The Committee may act at a meeting or in writing without a meeting. The Committee shall elect one of its members as chairman, appoint a secretary, who may or may not be a Committee member, and advise the Trustee of such actions in writing. The secretary shall keep a record of all meetings and forward all necessary communications to the Employer and the Trustee. The Committee may adopt such bylaws and regulations as it deems desirable for the conduct of its affairs. All decisions of the Committee shall be made by the vote of the majority including actions in writing taken without a meeting. 11.5 Administrative Powers of the Committee. The Committee may from time to time establish rules for the administration of the Plan. Except as otherwise herein expressly provided, the Committee will have the exclusive right and discretionary authority, to the fullest extent provided by law, to interpret the Plan and decide any matters arising hereunder in the administration and operation of the Plan, and any interpretations or decisions so made will be conclusive and binding on all persons having an interest in the Plan; provided, however, that all such interpretations and decisions will be applied in a uniform and nondiscriminatory manner to all Employees. The Committee shall have no right to modify any provisions of the Plan as herein set forth. 11.6 Benefit Claims Procedures. All claims for benefits under the Plan shall be in writing and shall be submitted to the Committee member designated as Committee Secretary by the Committee. If any application for payment of a benefit under the Plan shall be denied, the Committee shall notify the claimant within 90 days of such application setting forth the specific reasons therefor and shall afford such claimant a reasonable opportunity for a full and fair review of the decision denying his claim. If special circumstances require an extension of time for processing the claim, the claimant will be furnished with a written notice of the extension prior to the termination of the initial 90-day period. In no event shall such extension exceed a period of 90 days from the end of such initial period. The extension notice shall indicate the special circumstances requiring an extension of time and the date by which the Committee expects to render its decision. Notice of such denial shall set forth, in addition to the specific reasons for the denial, the following: (a) reference to pertinent provisions of the Plan; (b) such additional information as may be relevant to the denial of the claim; (c) an explanation of the claims review procedure; and (d) notice that such claimant may request the opportunity to review pertinent Plan documents and submit a statement of issues and comments. Within 60 days following notice of denial of his claim, upon written request made by any claimant for a review of such denial to the Committee Secretary, the Committee shall take appropriate steps to review its decision in light of any further information or comments submitted by such claimant. The Committee shall render a decision within 60 days after the claimant's request for review and shall advise said claimant in writing of its decision on such review, specifying its reasons and identifying appropriate provisions of the Plan. If special circumstances require an extension of time for processing, a decision will be rendered as soon as possible, but not later than 120 days after receipt of a request for the review. If the extension of time for review is required because of special circumstances, written notice of the extension shall be furnished to the claimant prior to the commencement of the extension. If the decision is not furnished within such time, the claim shall be deemed denied on review. The decision on review shall be in writing and shall include specific reasons for the decision, written to the best of the Committee's ability in a manner calculated to be understood by the claimant without legal counsel, as well as specific references to the pertinent Plan provisions on which the decision is based. 11.7 Reliance on Reports and Certificates. The Employer (or the Committee if so designated by the Employer) will be entitled to rely conclusively upon all valuations, certificates, opinions, and reports which may be furnished by the recordkeeper, or any accountant, controller, counsel, or other person who is employed or engaged for such purposes and shall exercise the authority and responsibility as it deems appropriate to comply with all of the legal and governmental regulations affecting this Plan. 11.8 Other Committee Powers and Duties. The Committee shall have such duties and powers as may be necessary to discharge its duties hereunder, including, but not by way of limitation, the following: (a) to prescribe written procedures to be followed by Participants, Former Participants, or Beneficiaries filing applications for benefits; (b) to prepare and distribute, in such manner as the Committee determines to be appropriate, information explaining the Plan; (c) to receive from the Employer, Participants and Former Participants such information as shall be necessary for the proper administration of the Plan; (d) to furnish the Employer, upon request, such annual reports with respect to the administration of the Plan as are reasonable and appropriate; (e) to receive and review the periodic valuations of the Plan made by the recordkeeper; (f) to receive, review and keep on file (as it deems convenient or proper) reports of benefit payments by the Trustee and reports of disbursements for expenses directed by the Committee; and (g) to invest and reinvest the Trust Fund, to select, replace and/or eliminate one or more of the investment funds offered under the Plan, and to exercise certain other powers respecting the investment of the Trust Fund, in each case in accordance with Section 6.4 hereof. The Committee shall have no power to add to, subtract from or modify any of the terms of the Plan, or to change or add to any benefits provided by the Plan, or to waive or fail to apply any requirements of eligibility for a benefit under the Plan. 11.9 Compensation of Committee. No member of the Committee who is an Employee will receive any compensation for his services as such, but will be reimbursed for reasonable expenses incident to the performance of such services. The reimbursement of expenses shall be paid in whole or in part by the Employer, and any expenses not paid by the Employer shall be paid by the Trustee out of the principal or income of the Trust Fund. 11.10 Member's Own Participation. No member of the Committee may act, vote, or otherwise influence a decision of the Committee specifically relating to his own participation under the Plan. 11.11 Liability of Committee Members. No member of the Committee will be liable for any act of omission or commission except as provided by federal law. 11.12 Indemnification. The Board, the Committee and the individual members thereof shall be indemnified by the Employer and not the Trust Fund against any and all expenses, costs, and liabilities arising by reason of any act or failure to act, unless such act or failure to act is judicially determined to be gross negligence or willful misconduct. ARTICLE XII FIDUCIARY RESPONSIBILITIES 12.1 Basic Responsibilities. Any Plan Fiduciary, whether specifically designated or not, shall: (a) discharge all duties solely in the interest of Participants, Former Participants, and Beneficiaries and for the exclusive purpose of providing benefits and defraying reasonable administrative expenses under the Plan; (b) discharge his responsibilities with the care, skill, prudence, and diligence a prudent man would use in similar circumstances; and (c) conform with the provisions of the Plan. No person who is ineligible by law will be permitted to serve as Fiduciary. 12.2 Actions of Fiduciaries. Any Plan Fiduciary: (a) may serve in more than one fiduciary capacity with respect to the Plan; (b) may employ one or more persons to render advice with regard to or to carry out any responsibility that such Fiduciary has under the Plan; and (c) may rely upon any discretion, information, or action of any other Plan Fiduciary, acting within the scope of its responsibilities under the Plan, as being proper under the Plan. 12.3 Fiduciary Liability. No Fiduciary shall be personally liable for any losses resulting from his action except as provided by federal law. Each Fiduciary shall have only the authority and duties which are specifically allocated to him, shall be responsible for the proper exercise of his own authority and duties, and shall not be respon- sible for any act or failure to act of any other Fiduciary. 12.4 Bonding of Fiduciaries. Notwithstanding any other provision of the Plan to the contrary, every Fiduciary shall be bonded to the extent required by law. 12.5 Indemnification of Fiduciaries. The Employer shall indemnify and hold harmless the other named Fiduciaries, and any Trustee of the Employer or Employee held to be a Fiduciary with respect to the Plan from any liability, claim, demand, suit or action of any type arising from any action or failure to act; provided, however, that such person acted in good faith and in a manner he reasonably believed to be in the best interests of the Participants and Beneficiaries and consistent with the provisions of the Plan and, with respect to any criminal action or proceeding, that he had no reasonable cause to believe his conduct was unlawful. ARTICLE XIII AMENDMENT AND TERMINATION 13.1 Internal Revenue Service Qualification. It is the intention of the Employer that the Plan shall be and remain qualified and exempt under Code Sections 401(a) and 501(a) and meet the requirements of Code Sections 401(k) and 401(m). The Employer may authorize any modification or amendment of this Plan, which is deemed necessary or appropriate to qualify or maintain the qualification and exemption of the Plan within the requirements of Code Sections 401(a), 401(k), 401(m), and 501(a), or any other applicable provisions of the Code as now in effect or hereafter amended or adopted. 13.2 Employer's Right to Amend or Terminate. The Employer, with the written approval of the Board of Directors, reserves the right to modify, suspend or terminate the Plan in whole or in part (including the provisions relating to contributions). Any modification, suspension, or termination of the Plan shall be set forth in a written Plan amendment executed by an officer of the Employer. The Employer shall not have the power to modify, suspend, amend or terminate the Plan in such manner as will cause or permit any part of the Trust Fund to be used for or diverted to purposes other than the exclusive benefit of Participants, Former Participants or their Beneficiaries, or for the payment of expenses pursuant to the provisions of the Plan. Further, except as otherwise specifically provided in Sections 4.5 and 4.8, no portion of the Trust Fund may revert to or become the property of the Employer, so as to divest a Participant or Former Participant from or deprive him of any benefits which may have accrued to him. Upon termination or partial termination of the Plan or "complete discontinuance of contributions" as such term is defined in Code Section 411, the amounts credited to the Accounts of Participants affected by such termination or partial termination shall be nonforfeitable. Notwithstanding anything to the contrary contained herein, upon such termination of the Plan, the Employer shall have no obligation or liability whatsoever to make any further payments to the Trustee. 13.3 Participating Employer's Right to Terminate. Each Participating Employer by action of its Board of Directors or other governing authority, subject to the approval of the Board, shall have the right to terminate, as to itself, the Plan hereby created, by delivering written notice authorizing the termination to the Board, the Committee, and the Trustee. 13.4 Valuation of Assets. In determining the value of the Accounts of the Participants or Former Participants as of the date of the termination of the Plan, the assets of the Trust Fund shall be valued by the Trustee at fair market value as of the close of business on the distribution date. The Accounts of the Participants and Former Participants shall be adjusted in the manner provided in Article VI. 13.5 Distribution of Assets. If the Plan is terminated, the Trustee, at the direction of the Employer shall continue to maintain the Trust Fund, as permitted by applicable law, until all assets remaining in the Trust Fund after payment of any expenses properly chargeable to the Trust Fund are distributed to Participants, Former Participants or their Beneficiaries. Such distribution shall be equal to the value of the Accounts of the Participants as of the date of the termination of the Plan adjusted for any earnings and expenses of the Trust Fund and Plan between such date and the date of distribution. Payment will be made in cash or in kind, or partly in cash and partly in kind, in such manner as the Committee shall determine and as may be required by applicable law. The Committee's determination shall be final and binding on all persons. ARTICLE XIV TOP-HEAVY PLAN REQUIREMENTS 14.1 General Rule. For any Plan Year for which this Plan is a Top-Heavy Plan as defined in Section 14.4, any other provisions of the Plan to the contrary notwithstanding, the Plan shall be subject to the following provisions: (a) The minimum contribution provisions of Section 14.2, and (b) The limitation on contributions set by Section 14.3. 14.2 Minimum Contribution Provisions. Subject to the provisions of Sections 14.3 and 14.4, each Eligible Employee who (a) is a Non-Key Employee (as defined in Section 14.7) and (b) is employed on the last day of the Plan Year shall be entitled to have an Employer Contribution (exclusive of any Matching Contributions) allocated to his Account of not less than 3% (the "Minimum Contribution Percentage") of his compensation (as defined for purposes of applying the limits of Code Section 415) or such other amount, if any, as may be necessary to comply with the rules established by the Internal Revenue Service. The Minimum Contribution Percentage set forth above shall be reduced for any Plan Year to the percentage at which contributions are made (or required to be made) under the Plan for the Plan Year for the Key Employee (as defined in Section 14.6) for whom such percentage is the highest for such Plan Year. For this purpose, the percentage with respect to a Key Employee shall be determined by dividing the contributions made for such Key Employee by his total compensation for the Plan Year not to exceed $200,000 ($150,000 for the Plan Year beginning January 1, 1994) adjusted in the same manner as set forth in Section 1.12. Contributions taken into account under the immediately preceding sentence shall include contributions under this Plan and under all other defined contribution plans required to be included in an Aggregation Group (as defined in Section 14.5), but shall not include any plan required to be included in such Aggregation Group if such plan enables a defined benefit plan required to be included in such Group to meet the requirements of the Code prohibiting discrimination as to contributions or benefits in favor of Employees who are officers, shareholders or the highly-compensated or prescribing the minimum participation standards. Contributions taken into account under this Section 14.2 shall not include any contributions under the Social Security Act or any other federal or state law. 14.3 Limitation on Contributions. In the event that the Employer also maintains a defined benefit plan providing benefits on behalf of Participants of this Plan, one of the two following provisions shall apply: (a) If for the Plan Year this Plan would not be a Top-Heavy Plan if "90%" were substituted for "60%," then Section 14.2 shall apply for such Plan Year as if amended so that "4%" were substituted for the "3%". (b) If for the Plan Year (i) this Plan is subject to paragraph (a) above but does not provide the required additional minimum contribution or (ii) this Plan would continue to be a Top-Heavy Plan if "90%" were substituted for "60%," then the denominator of both the defined contribution plan fraction and the defined benefit plan fraction shall be calculated as set forth in Section 4.5 for the limitation year ending in such Plan Year by substituting "1.0" for "1.25" in each place such figure appears, except with respect to any individual for whom there are no Matching Contributions, forfeitures or voluntary nondeductible contributions allocated or any accruals for such individual under the defined benefit plan. 14.4 Coordination With Other Plans. In the event that another defined contribution or defined benefit plan maintained by the Employer or an Affiliated Employer provides contributions or benefits on behalf of Participants in this Plan, such other plan shall be treated as a part of this Plan pursuant to the applicable principles set forth in Revenue Ruling 81-202 in determining whether the plans are providing benefits at least equal to the minimum benefit required under the defined benefit plan. If the Plan is subject to Section 14.3(b) but the Employer does not substitute "1.0" for "1.25" as required, the applicable percentage under the defined benefit plan shall be increased by one percentage point (up to a maximum of ten percentage points). Such determination shall be made by the Committee. 14.5 Top-Heavy Plan Definitions. This Plan shall be a Top-Heavy Plan for any Plan Year if, as of the Determination Date, the aggregate of the Accounts under the Plan for Participants and Former Participants who are Key Employees exceeds 60% of the present value of the aggregate of the Accounts for all Participants, or if this Plan is required to be in an Aggregation Group which for such Plan Year is a Top-Heavy Group. For purposes of making this determination, the present value of the aggregate of the Accounts for a Participant who is not a Key Employee, but who was a Key Employee in a prior year, or who has not performed any service for the Employer at any time during the five- year period ending on the Determination Date, shall be disregarded. (a) "Determination Date" shall mean for any Plan Year the last day of the immediately preceding Plan Year (except that for the first Plan Year the Determination Date means the last day of such Plan Year). (b) "Aggregate of the Accounts" shall mean the sum of (i) the Accounts determined as of the most recent Valuation Date that is within the 12-month period ending on the Determination Date, and (ii) the adjustment for contributions due as of the Determination Date, and as described in the regulations under the Code. (c) "Aggregation Group" shall mean the group of plans, if any, that includes both the group of plans that are required to be aggregated and, if the Committee so elects, the group of plans that are permitted to be aggregated. (i) The group of plans that are required to be aggregated (the "Required Aggregation Group") includes: (a) each plan of the Employer in which a Key Employee is a Participant, including collectively-bargained plans, and (b) each other plan of the Employer or an Affiliated Employer including collectively-bargained plans, which enables a plan in which a Key Employee is a Participant to meet the requirements of the Code prohibiting discrimination as to contributions or benefits in favor of Employees who are officers, shareholders or the highly-compensated or prescribing the minimum participation standards. (ii) The group of plans that are permitted to be aggregated (the "Permissive Aggregation Group") includes the Required Aggregation Group plus one or more plans of the Employer or an Affiliated Employer that is not part of the Required Aggregation Group and that the Committee certifies as constituting a plan within the Permissive Aggregation Group. Such plan or plans may be added to the Permissive Aggregation Group only if, after the addition, the Aggregation Group as a whole continues not to discriminate as to contributions or benefits in favor of Employees who are officers, shareholders or the highly-compensated and to meet the minimum participation standards under the Code. (d) "Top-Heavy Group" shall mean the Aggregation Group, if as of the applicable Determination Date, the sum of the present value of the cumulative accrued benefits for Key Employees under all defined benefit plans included in the Aggregation Group plus the aggregate of the accounts of Key Employees under all defined contribution plans included in the Aggregation Group exceeds 60% of the sum of the present value of the cumulative accrued benefits for all Employees under all such defined benefit plans plus the aggregate accounts for all Employees under such defined contribution plans. For purposes of making this determination, the present value of the accrued benefits for a Participant (i) who is not a Key Employee, but who was a Key Employee in a prior year or (ii) who has not performed services for the Employer at any time during the five-year period ending on the Determination Date, shall be disregarded. If the Aggregation Group that is a Top-Heavy Group is a Required Aggregation Group, each plan in the Group will be Top-Heavy. If the Aggregation Group that is a Top-Heavy Group is a Permissive Aggregation Group, only those plans that are part of the Required Aggregation Group will be treated as Top-Heavy. If the Aggregation Group is not a Top- Heavy Group, no plan within such Group will be Top-Heavy. (e) In determining whether this Plan constitutes a Top-Heavy Plan, the Committee shall make the following adjustments in connection therewith: (i) When more than one plan is aggregated, the Committee shall determine separately for each plan as of each plan's determination date the present value of the accrued benefits or the sum of Account balances. Such accrued benefits shall be determined by using the method which is used for accrual purposes for all plans of the Employer, or, if there is no such method, as if such benefit accrued not more rapidly than the slowest accrual rate permitted under Code Section 411(b)(1)(C). (ii) In determining the present value of the cumulative accrued benefit or the amount of the Account of any Employee, such present value or Account shall include the dollar value of the aggregate distributions made to such Employee under the applicable plan during the five-year period ending on the determination date, unless reflected in the value of the accrued benefit or account balance as of the most recent valuation date. Such amounts shall include distributions to Employees which represented the entire amount credited to their Accounts under the applicable plan, and distributions made on account of the death of a Participant to the extent such death benefits do not exceed the present value of the accrued benefit or Account. (iii) Further, in making such determination, such present value or such Account shall include any rollover contribution (or similar transfer), as follows: (A) If the rollover contribution (or similar transfer) is initiated by the Employee and made to or from a plan maintained by another employer, the plan providing the distribution shall include such distribution in the value of such account; the plan accepting the distribution shall not include such distribution in the value of such account unless the plan accepted it before December 31, 1983. (B) If the rollover contribution (or similar transfer) is not initiated by the Employee or made from a plan maintained by another employer, the plan accepting the distribution shall include such distribution in the present value of such account, whether the plan accepted the distribution before or after December 31, 1983; the plan making the distribution shall not include the distribution in the present value of such account. (f) Solely for the purpose of determining if the Plan, or any other plan included in the required aggregation group of which this Plan is a part, is top-heavy (within the meaning of Code Section 416(g)) the accrued benefit of an Employee other than a "Key Employee" (as defined in Section 14.6 below) shall be determined under the method, if any, that uniformly applies for accrual purposes under all plans maintained by the Employer. 14.6 Key Employee. The term "Key Employee" shall mean any Employee (and any Beneficiary of an Employee) under this Plan who is a key employee as determined in accordance with Code Section 416(i)(1), excluding in any event individuals who have not performed services for the Employer during the five-year period ending on the date on which the Top-Heavy determination is made. 14.7 Non-Key Employee. The term "Non-Key Employee" shall mean any Employee (and any Beneficiary of an Employee) who is not a Key Employee, excluding in any event individuals who have not performed services for the Employer during the five-year period ending on the date on which the Top-Heavy determination is made. 14.8 Change from Top-Heavy Status. In the event the Plan should become a Top-Heavy Plan for a Plan Year and subsequently reverts to a Plan which is not Top-Heavy, the change from a Top-Heavy Plan to a Plan which is not Top-Heavy shall not reduce a Participant's Account. ARTICLE XV GENERAL PROVISIONS 15.1 Plan Voluntary. Although it is intended that the Plan shall be continued and that contributions shall be made as herein provided, this Plan is entirely voluntary on the part of the Employer and the continuance of this Plan and the payment of contributions hereunder are not to be regarded as contractual obligations of any Participating Employer, and no Participating Employer guarantees or promises to pay or to cause to be paid any of the benefits provided by this Plan. Each person who shall claim the right to any payment or benefit under this Plan shall be entitled to look only to the Fund for any such payment or benefit and shall not have any right, claim, or demand therefore against any Employer, except as provided by federal law. The Plan shall not be deemed to constitute a contract between any Participating Employer and any Employee or to be a consideration for, or an inducement for, the employment of any Employee by any Participating Employer. Nothing contained in the Plan shall be deemed to give any Employee the right to be retained in the service of any Employer or to interfere with the right of any Employer to discharge or to terminate the service of any Employee at any time without regard to the effect such discharge or termination may have on any rights under the Plan. 15.2 Payments to Minors and Incompetents. If any Participant, Former Participant, or Beneficiary entitled to receive any benefits hereunder is a minor or is deemed by the Committee or is adjudged to be legally incapable of giving valid receipt and discharge for such benefits, they will be paid to such person or institution as the Committee may designate or to the duly appointed guardian. Such payment shall, to the extent made, be deemed a complete discharge of any liability for such payment under the Plan. 15.3 Non-Alienation of Benefits. No amount payable to, or held under the Plan for the account of, any Participant or Former Participant shall be subject in any manner to anticipation, alienation, sale, transfer, assignment, pledge, encumbrance, or charge, and any attempt to so anticipate, alienate, sell, transfer, assign, pledge, encumber, or charge the same shall be void; nor shall any amount payable to, or held under the Plan for the account of, any Participant be in any manner liable for his debts, contracts, liabilities, engagements, or torts, or be subject to any legal process to levy upon or attach, except as may be provided under a qualified domestic relations order as defined in Code Section 414(p). The Committee shall establish a procedure to determine the status of a judgement, decree or order as a qualified domestic relations order and to administer Plan distributions in accordance with qualified domestic relations orders. Such procedure shall be in writing, shall include a provision specifying the notification requirements enumerated in Code Section 414(p), shall permit an alternate payee to designate a representative for receipt of communications from the Committee and shall include such other provisions as the Committee shall determine, including provisions describing the interest rate to be used in making present value determinations as well as provisions required under regulations promulgated by the Secretary of the Treasury. 15.4 Use of Masculine and Feminine; Singular and Plural. Wherever used in this Plan, the masculine gender will include the feminine gender and the singular will include the plural, unless the context indicates otherwise. 15.5 Merger, Consolidation or Transfer. In the event that the Plan is merged or consolidated with any other plan, or should the assets or liabilities of the Plan be transferred to any other plan, each Participant shall be entitled to a benefit immediately after such merger, consolidation, or transfer if the Plan should then terminate equal to or greater than the benefit he would have been entitled to receive immediately before such merger, consolidation, or transfer if the Plan had then terminated. 15.6 Leased Employees. Any individual who performs services for the Employer or an Affiliated Employer and who, by application of Code Section 414(n)(2) and regulations issued pursuant thereto, would be considered a "leased employee", shall, for purposes of determining the number of Employees of the Employer and its Affiliated Employers and for purposes of the requirements enumerated in Code Section 414(n)(3), be considered an Employee with regard to services performed after December 31, 1986. When the total of all leased employees constitutes less than 20% of the Employer's non-highly compensated work force within the meaning of Code Section 414(n)(5)(c)(ii), however, a "leased employee" shall not be considered an Employee if the organization from which the individual is leased maintains a qualified safe harbor plan (as defined in Code Section 414(n)(5)) in which such individual participates. "Leased employees" who are deemed to be Employees for purposes of this Section 15.6 shall not be eligible to participate in the Plan unless specifically provided for in Article II. 15.7 Governing Law. The Plan shall be administered, construed, and enforced according to the laws of the State of/Commonwealth of Massachusetts; provided, however, wherever applicable, the provisions of ERISA shall govern and in such event the laws of the United States of America shall be applied and to the extent necessary, its courts shall have competent jurisdiction. IN WITNESS WHEREOF, Eastern Utilities Associates has caused this instrument to be executed by its officers thereunto duly authorized and its corporate seal to be hereunto affixed, as of the 21 day of December, 1994. EASTERN UTILITIES ASSOCIATES By/s/John R. Stevens John R. Stevens President ATTEST: /s/W. F. O'Connor W. F. O'Connor Secretary (CORPORATE SEAL) EX-10 4 EXHIBIT 10-16.03 EMPLOYEES' RETIREMENT PLAN OF EASTERN UTILITIES ASSOCIATES AND ITS AFFILIATED COMPANIES FIRST AMENDMENT TO THE 1989 RESTATED PLAN WHEREAS, Eastern Utilities Associates amended and restated its pension plan known as the "Employees' Retirement Plan of Eastern Utilities Associates and its Affiliated Companies" effective as of January 1, 1989 (hereinafter sometimes referred to as the "Plan"); and WHEREAS, the Association wishes to make certain additional amendments to said Plan; and WHEREAS, by Article 12 of the Plan the power to modify or amend the Plan is reserved to the Board of Trustees of Eastern Utilities Associates subject to certain conditions not here applicable. NOW THEREFORE, said Plan is hereby further amended effective as of June 1, 1995 by adding a new section 4.5 to read as follows: 4.5 Special 1995 Voluntary Retirement Incentive. (a) Subject to the maximum benefit limitation of Section 3.3, a Special 1995 Voluntary Retirement Incentive shall be available to a Participant who is not employed at Newport Electric Corporation who: (i) is an Active Participant on January 1, 1995; (ii) will have attained at least age 55 during 1995; (iii) will have completed at least 10 Years of Vesting Service during 1995; and (iv) is less than 61 years of age during 1995 or will have completed less than 35 Years of Vesting Service during 1995; or to a Participant who is employed at Newport Electric Corporation who: (i) will have attained at least age 55 during 1995; (ii) will have completed at least 10 Years of Vesting Service during 1995; and is either case, such Participant: (i) is employed in a job classification of "monthly paid exempt employee" which the Employer has designated as eligible for this special benefit; (ii) is not a highly compensated employee, which within the meaning of section 414(q) of the Code; and (iii) elects to retire hereunder effective no later than June 1, 1995 (or such later date as determined by the Company, but in no event later than May 31, 1996) in accordance with procedures established by the Retirement Board. (b) The monthly Special 1995 Voluntary Retirement Incentive of an eligible Participant who elects to retire hereunder shall be equal to his Voluntary Retirement Incentive determined under Section 4.2 or Section A.6.1, whichever is applicable, as of his Early Retirement Date, based on: (i) his Years of Benefit Service on such date plus five additional years of such service, and (ii) his age on such date plus five additional years for purposes of determining the appropriate early retirement reduction factor in the Appendix. (c) A participant who elects to retire hereunder may be entitled to an additional supplemental monthly benefit of $600. Such supplemental monthly benefit shall be payable for the period beginning on the Participant's Early Retirement Date and ending on the earlier of his death or with the payment due for the month before which the Participant attains age 62. No supplemental monthly benefit shall be payable for a Participant who has attained age 62 as of his Early Retirement Date. (d) For participants (a) above who retire after June 1, 1995, the actuarial equivalent at retirement of the increased benefits provided under (b) and (c) above shall not be less than the actuarial equivalent of such amounts calculated as of June 1, 1995. (e) For participants who retired on or after March 1, 1995, and who elected such retirement prior to the announcement of this Section 4.5 and who met the applicable requirements described in (a) above will be eligible for the benefits described in (b) and (c) above with such increases in benefit amounts payable beginning June 1, 1995. (f) The Special 1995 Voluntary Retirement Incentive shall be in lieu of any other benefit payable under the Plan and shall be payable in accordance with Article VII and Section A.11.0 if applicable, except that the additional supplemental monthly benefit of $600 will be paid in accordance with (c) above. IN WITNESS WHEREOF, the Employer has caused this instrument to be executed by its officers thereunto duly authorized and its corporate seal to be hereunto affixed, as of the 30 Day of November, 1995. EASTERN UTILITIES ASSOCIATES By/s/ John R. Stevens John R. Stevens President ATTEST: /s/ Clifford J. Hebert, Jr. Clifford J. Hebert, Jr. Secretary (CORPORATE SEAL) EX-10 5 EXHIBIT 10-17.03 EASTERN UTILITIES ASSOCIATES EMPLOYEES' SAVINGS PLAN FIRST AMENDMENT TO THE 1989 RESTATED PLAN WHEREAS, Eastern Utilities Associated (the "Employer") previously adopted the Eastern Utilities Associates Employees' Savings Plan (the "Plan") effective January 1, 1982; WHEREAS, the Employer amended and restated the Plan effective January 1, 1989; WHEREAS, TransCapacity Limited Partnership has become an Affiliated Employer under Section 1.2 of the Plan; WHEREAS, EUA has reserved the right to amend the Plan from time to time under Section 13.2 of the Plan; NOW THEREFORE, in accordance with and pursuant to the foregoing, the Plan is amended, effective July 1, 1995, as follows: 1. Section 1.30 of the Plan is hereby amended by deleting the same in its entirety and by substituting therefore the following: 1.30 "Participating Employers" shall mean the Employer and any other Affiliated Employer which has elected to participate in the Plan pursuant to the provisions under Article XVI. 2. Section 2.1 of the Plan is hereby amended by adding the following paragraph (h) thereto: (h) Notwithstanding paragraph (b) above, an Employee who was an employee of TransCapacity Limited Partnership after December 31, 1994 who are not otherwise ineligible to participate in the Plan under Paragraphs (a), (c), (d), (e) or (f) of this Section 2.1 shall become Eligible Employees after completing three months of Service following December 31, 1994, but in no event earlier than July 1, 1995. 3. Section 4.1 of the Plan is hereby amended by adding the following sentence at the end of the first paragraph of such section: Notwithstanding anything to the contrary in this Article IV, TransCapacity Limited Partnership shall not make a Matching Contribution on behalf of each of its Participants under the Plan who make a Pre-Tax Participant Contribution. 4. A new Article XVI is added to the plan as follows: ARTICLE XVI PARTICIPATING EMPLOYERS 16.1 Adoption of Plan by a Participating Employer. Any Affiliated Employer, whether or not presently existing, may adopt the Plan with respect to all or some of its employees after the Board authorizes the participation of such employer in the Plan. The Board authorization shall set forth the date on which the Affiliated Employer may begin to participate in the Plan and any special restrictions or requirements applicable to the Affiliated Employer's participation in the Plan. An Affiliated Employer becomes a Participating Employer under the Plan following such authorization by appropriate action of its board of directors (or noncorporate counterpart) to adopt the Plan. 16.2 Plan Provisions Applicable to Participating Employer. The provisions of the Plan shall apply equally to each Participating Employer and its Employees except as specifically set forth in the Plan. 16.3 Termination of Participation in the Plan. (a) Any Participating Employer may terminate its participation in the Plan as provided in Section 13.3 of the Plan. (b) The Board may, in its sole discretion, terminate a Participating Employer's participation in the Plan at any time without consent or approval of such employer. 16.4 Single Plan. For purposes of the Code and ERISA, the Plan as adopted by the Participating Employer shall constitute a single plan rather than a separate plan of each Participating Employer. All assets in the Trust Fund shall be available to pay benefits to all Participants and their Beneficiaries. IN WITNESS WHEREOF, the Employer has caused this instrument to be executed and delivered on behalf by the undersigned on this 30th day of November, 1995. EASTERN UTILITIES ASSOCIATES By /s/ John R. Stevens John R. Stevens Its President ATTEST: /s/ Clifford J. Hebert, Jr. Clifford J. Hebert, Jr. Secretary (CORPORATE SEAL) EX-10 6 EXHIBIT 10-38.05 Exhibit 10-38.05 TWENTY-EIGHTH AGREEMENT AMENDING NEW ENGLAND POWER POOL AGREEMENT THIS AGREEMENT, dated as of the 15th day of September, 1992 is entered into by the signatories hereto for the amendment by them of the New England Power Pool Agreement dated as of September 1, 1971 (the "NEPOOL Agreement"), as previously amended or proposed to be amended by twenty-seven (27) amendments, the most recent of which was dated as of October 1, 1990. WHEREAS, in response to the factors specified in Section 5.10 of the NEPOOL Agreement regarding election of members of the Management Committee to serve as an Executive Committee, the member of the Management Committee representing Public Service Company of New Hampshire has been elected to serve as a member of the Executive Committee since the formation of NEPOOL; and WHEREAS, Northeast Utilities has recently acquired Public Service Company of New Hampshire, Public Service Company of New Hampshire has elected to be treated as a single Participant with the other Entities controlled by Northeast Utilities, and Public Service Company of New Hampshire is no longer entitled to be separately represented by a member of the Management Committee; and WHEREAS, the signatory Participants have determined to amend the NEPOOL Agreement in the manner specified below in order to reflect the fact that the considerations specified in Section 5.10 for membership on the Executive Committee can now be satisfied by election of only ten members. NOW THEREFORE, the signatories hereby agree as follows: SECTION I TEXT OF AMENDMENT Section 5.10 of the NEPOOL Agreement is amended to read as follows: Election of Executive Committee Members Unless there are less than eleven members of the Management Committee, the Management Committee; at each annual meeting, shall elect ten of its members to serve as an Executive Committee. In electing the Executive Committee, the Management Committee shall give such consideration as it shall deem advisable to qualifications for the office, geographic distribution, the relative sizes of Participants and the public and private sectors of the electric utility industry. Each member so selected may designate an alternate who is acceptable to the Management Committee. SECTION II EFFECTIVENESS OF AGREEMENT Following its execution by the requisite number of Participants, this Agreement, and the amendment provided for above, shall become effective on December 1, 1992, or on such later date as the Federal Energy Regulatory Commission shall provide that such amendment shall become effective. SECTION III USAGE OF DEFINED TERMS The usage in this Agreement of terms which are defined in the NEPOOL Agreement shall be deemed to be in accordance with the definitions thereof in the NEPOOL Agreement. SECTION IV 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 the counterparts had signed the same instrument. Any signature page of this Agreement may be detached from any counterpart of this Agreement without impairing the legal effect of any signatures thereof, 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, each of the signatories has caused a counterpart signature page to be executed by its duly authorized representative, as of the 15th day of September, 1992. CONFORMED COPY COUNTERPART SIGNATURE PAGE TO TWENTY-EIGHTH AGREEMENT AMENDING NEW ENGLAND POWER POOL AGREEMENT DATED AS OF SEPTEMBER 15, 1992 The NEPOOL Agreement, being dated as of September 1, 1971, and being previously amended by twenty-seven (27) amendments, the most recent prior amendment being an amendment dated as of October 1, 1990. Ashburnham Municipal Light Department By: /s/ Robert W. Gould Manager 86 Central Street Ashburnham, MA 01430 Bangor Hydro-Electric Company By: /s/ Robert S. Briggs President & CEO 33 State Street Bangor, Maine 04402-0932 Belmont Municipal Light Department By: /s/ Timothy L. McCarthy Acting Manager 450 Concord Avenue Belmont, MA 02178 Boston Edison Company By: /s/ Cameron H. Daley Senior Vice President 800 Boylston Street Boston, MA 02199 Boylston Municipal Light Department By: /s/ H. Bradford White, Jr. Manager P.O. Box 560 Boylston, MA 01505 Central Maine Power Company By: /s/ Donald F. Kelly Senior Vice President Edison Drive Augusta, Maine 04336 City of Chicopee Municipal Lighting Plant By: /s/ Barry W. Soden General Manager 725 Front Street Chicopee, MA 01021-0405 Commonwealth Energy System Companies Commonwealth Electric Company Cambridge Electric Light Company Canal Electric Company By: /s/ Harold N. Scherer, Jr. President and CEO 2421 Cranberry Highway Wareham, MA 02571 Concord Municipal Light Plant By: /s/ Daniel J. Sack Superintendent 135 Keyes Road Concord, MA 01742 Connecticut Municipal Electric Energy Cooperative By: /s/ Maurice R. Scully Executive Director 30 Stott Avenue Norwich, CT 06360-1526 Eastern Utilities By: /s/ Donald G. Pardus Chairman/CEO One Liberty Square Boston, MA 02109 Groton Electric Light Department By: /s/ Roger H. Beeltje Manager P.O. Box 679 Groton, MA 01450 Hingham Municipal Lighting Plant By: /s/ Joseph R. Spadea, Jr. General Manager 19 Elm Street Hingham, MA 02043 Holden Municipal Light Department By: /s/ Edla Ann Bloom Director of Electric Services 94 Reservoir Street Holden, MA 01520 Holyoke Gas & Electric Department By: /s/ George E. Leary Manager 70 Suffolk Street Holyoke, MA 01040 Ipswich Municipal Light Department By: /s/ Donald R. Stone Director of Utilities P.O. Box 151 Ipswich, MA 01938 Mansfield Municipal Electric By: /s/ John Larch Manager 50 West Street Mansfield, MA 02048 Marblehead Municipal Light Department By: /s/ Richard L. Bailey General Manager 80 Commercial Street Marblehead, MA 01945 Merrimac Municipal Light Department By: /s/ David Vance Commissioner 2 School Street Merrimac, MA 01860 Middleton Municipal Electric Department By: /s/ William E. Kelly Manager 197 North Main Street Middleton, MA 01949 The Narragansett Electric Company By: /s/ Robert L. McCabe President 280 Melrose Street Providence, Rhode Island New England Power Company By: /s/ Jeffrey D. Tranen Vice President 25 Research Drive Westborough, MA 01582 Massachusetts Electric Company By: /s/ John H. Dickson President 25 Research Drive Westborough, MA 01582 Granite State Electric Company By: /s/ Lydia M. Pastuszek President 33 West Lebanon Road Lebanon, New Hampshire The Connecticut Light and Power By: /s/ Bernard M. Fox President P.O. Box 270 Hartford, CT 06141-0270 Western Massachusetts Electric By: /s/ Bernard M. Fox President P.O. Box 270 Hartford, CT 06141-0270 Holyoke Water Power Company By: /s/ Bernard M. Fox President P.O. Box 270 Hartford, CT 06141-0270 Holyoke Power and Electric Company By: /s/ Bernard M. Fox President P.O. Box 270 Hartford, CT 06141-0270 Public Service Company of New Hampshire By: /s/ Bernard M. Fox President P.O. Box 270 Hartford, CT 06141-0270 Pascoag Fire District - Electric Department By: /s/ James E. Daniels Chairman, Operating Committee 55 South Main Street Pascoag, RI 02859 Princeton Municipal Light Department By: /s/ Sharon A. Staz Manager P.O. Box 247 Princeton, MA 01541-0247 Rowley Municipal Lighting Plant By: /S/ G. Robert Merry Manager 47 Summer Street Rowley, MA 01969 Taunton Municipal Lighting Plant By: /s/ Joseph M. Blain General Manager 55 Weir Street Taunton, MA 02780 The United Illuminating Company By: /s/ Richard J. Grossi Chairman and CEO 157 Church Street New Haven, CT 06506-0901 Vermont Electric Power Company, Inc. By: /s/ Richard W. Mallary President P.O. Box 548 Rutland, Vermont 05702-0548 Central Vermont Public Service Corporation By: /s/ Robert de R. Stein Vice President 77 Grove Street Rutland, VT 05701 Citizens Utilities Company By: /s/ James P. Avery Vice President High Ridge Park Stamford, CT 06905 City of Burlington Electric Dept. By: /s/ Dale L. Pohlman General Manager 585 Pine Street Burlington, VT 05401 Franklin Electric Light Co. By: /s/ Hugh H. Gates President P.O. Box 96 Franklin, VT 05457-0096 Green Mountain Power Corporation By: /s/ John V. Cleary President & CEO P.O. Box 850 S. Burlington, Vermont 05402 Rochester Electric Light & Power Company By: /s/ Thomas Pierce President P.O. Box 6 Rochester, Vermont 05767 Vermont Marble Company By: /s/ John M. Mitchell President 61 Main Street Proctor, Vermont 05765 Vermont Public Power Supply Authority By: /s/ William J. Gallagher General Manager 512 St. George Road Williston, VT 05495 Village of Hardwick Electric Department By: /s/ Jack E. Young General Manager Box 516 Hardwick, Vermont 05843 Village of Ludlow Electric Light Department By: /s/ Donald Ellison Commissioner, Chairman P.O. Box 289 Ludlow, Vermont 05149 Village of Morrisville Water and Light Department By: /s/ James C. Fox Superintendent 18 Portland Street Morrisville, VT 05661 Village of Northfield Electric Department By: /s/ Kevin O'Donnell Municipal Manager 26 South Main Street Northfield, Vermont 05663 Village of Orleans Electric Department By: /s/ Slayton R. Marsh Superintendent Memorial Square Orleans, VT 05860 Village of Readsboro Electric Light Department By: /s/ Annette Caruso Utility Clerk P.O. Box 247 Readsboro, Vermont 05350 Wakefield Municipal Light Department By: /s/ William J. Wallace Manager 11 Albion Street Wakefield, MA 01880 EX-10 7 EXHIBIT 10-39.05 Exhibit 10-39.05 TWENTY-NINTH AGREEMENT AMENDING NEW ENGLAND POWER POOL AGREEMENT THIS AGREEMENT, dated as of the 1st day of May, 1993 is entered into by the signatories hereto for the amendment by them of the New England Power Pool Agreement dated as of September 1, 1971 (the "NEPOOL Agreement), as previously amended by twenty- eight (28) amendments, the most recent of which was dated as of September 15, 1992. WHEREAS, Participant generation resources, other than hydroelectric units, whose annual hours of operation are restricted by regulatory requirements, contract terms or engineering or operating constraints, may require treatment different from that otherwise provided in the NEPOOL Agreement for Capability Responsibility and energy billing purposes; and WHEREAS, the signatory Participants have determined to amend the NEPOOL Agreement in the manner specified below in order to provide for a modified Capability Responsibility and energy billing treatment for restricted generation resources NOW THEREFORE, the signatories hereby agree as follows: Section I TEXT OF AMENDMENTS A. Amendment of Section 9.2(b)(2) Section 9.2(b)(2) of the NEPOOL Agreement is amended by inserting the following additional provisions immediately following the present final paragraph of Section 9.2(b)(2): The New Unit Adjustment Factor for any Restricted Unit for which proposed plans were submitted subsequent to November 1, 1990 for review pursuant to Section 10.4 (or, in the case of a unit with a rated capacity of less than SMW, for which notification was first given to NEPOOL subsequent to November 1, 1990) and for the Peabody Municipal Light Plant's Waters River #2 unit shall be determined in accordance with the formula previously specified in this Section 9.2(b)(2), modified as follows: n = (K to the 1st base)(c-C) + (K to the 2nd base)(f-F) + (K to the third base)(m-M) + (K to the fourth base)(d-D) + (K to the fifth base)(f-Fc) + (K to the sixth base)(2500-a) The symbols used in the above formula, as modified, shall have the meanings previously specified, except that the symbols "K to the 6th base" and "a" shall have the following meanings: K to the 6th base is a scaling factor of 0.0001. a is as follows: for units with more than 2500 annual hours available for operation, "a" = 2500, for units with annual hours available for operation between 500 and 2500, inclusive, "a" = annual hours available for operation, and for units with annual hours available for operation less than 500 hours, "a" = -7500; provided, however, that a Participant may elect to avoid, in whole or part, the effect on its Capability Responsibility of a Restricted Unit's availability being limited to 2500 hours or less a year by agreeing to leave unfilled a portion of its dispatchable load allocation in accordance with rules to be adopted by the Operations Committee. B. Amendment of Section 12.6 The first two sentences of Section 12.6 of the NEPOOL Agreement are amended to read as follows: If pursuant to Section 12.5A, a Participant is deemed to have received energy service in any hour when the Participant (i) had Entitlements in one or more generating units which were available for service but were not scheduled for operation by NEPEX at their full available Reserve Capability (or, to the extent applicable, at their full available Temporary Reserve Capability) and which, in the case of any Restricted Unit, had an unused portion of an available Restricted Unit Operational Allowance and/or (ii) had Scheduled Outage Service Entitlements, the Participant shall be deemed to have received Economy Flow Service and/or Scheduled Outage Service in an amount equal to the lesser of: (a) the amount of energy service the Participant is deemed to have received pursuant to Section 12.5A, or (b) the amount of energy service which could have been provided from its share of (1) the unused portion of the available Reserve or Temporary Reserve Capabilities of the units described in (i) above, as limited in the case of any Restricted Unit by the unused portion of its available Restricted Unit Operational Allowance, plus (2) its Scheduled Outage Service Entitlements. Economy Flow Service is service which a Participant is deemed to receive at any time to replace service which it could have provided at the time from units described in (i) above, and the amount of Economy Flow Service which it is deemed to receive at the time shall not exceed the amount of energy service which could have been provided from its share of the unused portions of the available Reserve Capabilities (or, to the extent applicable, the unused portion of the available Temporary Reserve Capabilities or the unused portion of the available Restricted Unit Operational Allowances, whichever is controlling) of such units. C. Addition of Definitions of "Restricted Unit" and "Restricted Unit Operational Allowance". The NEPOOL Agreement is amended by adding the following definitions following the definition of "Reserve Savings Shares" in Section 15 37A: 15.37B. Restricted Unit is a generating unit, other than a hydroelectric unit, that is restricted in annual hours available for operation by regulatory requirements, contract terms or actual engineering or operating constraints Planned or forced outages due to maintenance requirements are not considered restrictions in annual hours available for operation. 15.37C. Restricted Unit Operational Allowance ("Allowance") for a Participant's Entitlement in a Restricted Unit for any calendar year (or for the term of the Entitlement in any year, if such term is for a shorter period than the year) is the number of hours for which the Restricted Unit is available for operation during the year or such shorter period, whichever is applicable. The Allowance for a Participant's Entitlement in a Restricted Unit for any year or shorter period shall be deemed to be exhausted when (i) the number of hours that the Operations Committee determines the Participant would have used its Restricted Unit Entitlement to minimize the Participant's overall energy costs in the absence of NEPEX dispatch, plus (ii) the number of hours that the Participant is deemed to receive Scheduled Outage Service with respect to its Entitlement in the Restricted Unit during the year or such shorter period pursuant to Section 12.6, equals the Allowance. D. Modification of Definition of "Scheduled Outage Service Entitlement". The definition of "Scheduled Outage Service Entitlement" in Section 15.38B of the NEPOOL Agreement is amended to read as follows: 15.38B Scheduled Outage Service Entitlement of a Participant is the amount of Scheduled Outage Service which the Participant is entitled to receive in any hour with respect to a generating unit which is scheduled by the Operations Committee to be out of service, in whole or in part, for maintenance during a period approved for it by the Operations Committee for Scheduled Outage Service and is in fact out of service, in whole or in part, for any reason during the approved period. Such amount is equal to the lesser of (i) the portion of the Participant's share of the Reserve Capability of such unit which is unavailable for service times an estimated average availability of such unit between its periodic scheduled outages or (ii) in the case of any generating unit with a currently applicable Temporary Reserve Capability, the portion of the Participant's share of the Temporary Reserve Capability which is unavailable for service; provided, however, that (a) in the case of any Limited Fuel Unit, the amount of a Participant's Scheduled Outage Service Entitlement shall be reduced, if appropriate, to take account of any limit on the availability of stream flow or fuel to operate the unit during the outage period, and (b) in the case of any Restricted Unit, the Participant's Scheduled Outage-Service Entitlement shall be limited to the unused portion, if any, of its currently available Restricted Unit Operational Allowance for the unit The Operations Committee shall develop rules for establishing the estimated average availability of each unit between scheduled outages. Such rules shall become effective upon approval by the Management Committee. SECTION II EFFECTIVENESS OF AGREEMENT Following its execution by the requisite number of Participants, this Agreement, and the amendments provided for above, shall become effective on August 1, 1993, or on such later date as the Federal Energy Regulatory Commission shall provide that such amendment shall become effective. SECTION III USAGE OF DEFINED TERMS The usage in this Agreement of terms which are defined in the NEPOOL Agreement shall be deemed to be in accordance with the definitions thereof in the NEPOOL Agreement. SECTION IV 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 the counterparts had signed the same instrument Any signature page of this Agreement may be detached from any counterpart of this Agreement without impairing the legal effect of any signatures thereof, 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, each of the signatories has caused a counterpart signature page to be executed by its duly authorized representative, as of the 1st day of May, 1993. CONFORMED COPY COUNTERPART SIGNATURE PAGE TO TWENTY-NINTH AGREEMENT AMENDING NEW ENGLAND POWER POOL AGREEMENT DATED AS OF MAY 1, 1993 The NEPOOL Agreement, being dated as of September 1, 1971, and being previously amended by twenty-eight (28) amendments, the most recent prior amendment being an amendment dated as of September 15, 1992. Ashburnham Municipal Light Department By: /s/ Robert W. Gould Manager 86 Central Street P.O. Box 823 Ashburnham, MA 01430 Bangor Hydro-Electric Company By: /s/ Carroll R. Lee Vice President, Operations 33 State Street P O. Box 932 Bangor, ME 04402-0932 Boston Edison Company By: /s/ B.W. Reznicek Chairman, President and Chief Executive Officer 800 Boylston Street Boston, MA 02199 Boylston Municipal Light Department By: /s/ H. Bradford White Jr. Manager Tivnan Road, P.O. Box 560 Boylston, MA 01505 Braintree Electric Light Department By: /s/ Walter R. McGrath General Manager 44 Allen Street Braintree, MA 02184 Central Maine Power Company By: /s/ Donald F. Kelly Senior Vice President Edison Drive Augusta, ME 04336 Commonwealth Electric Company By: /s/ James J. Keane Vice President - Power Supply and Transmission 2421 Cranberry Highway Wareham, MA 02571 Concord Municipal Light Plant By: /s/ Daniel J. Sack Superintendent 135 Keyes Road Concord, MA 01742 Connecticut Municipal Electric Energy Cooperative By: /s/ Maurice R. Scully Executive Director 30 Stott Avenue Norwich, CT 06360 Eastern Utilities Associates By: /s/ Donald G. Pardus Chairman/CEO P.O. Box 2333 Boston, MA 02107 Fitchburg Gas and Electric Light Company By: /s/ David K. Foote Senior Vice President 216 Epping Road Exeter, NH 03833 Georgetown Municipal Light Department By: /s/ Edward Stanley Manager Moulton and West Main Streets Georgetown, MA 01833 Groton Electric Light Department By: /s/ Roger H. Beeltje Manager P.O. Box 679 Groton, MA 01450 Hingham Municipal Lighting Plant By: /s/ Joseph R. Spadea, Jr. General Manager 19 Elm Street Hingham, MA 02043 Holden Municipal Light Department By: /s/ Edla Ann Bloom Director 94 Reservoir Street Holden, MA 01520 Holyoke Gas & Electric Department By: /s/ George E. Leary Manager 70 Suffolk Street Holyoke, MA 01040 Littleton Electric Light and Water Department By: /s/ Curtis J. Lanciani General Manager 39 Ayer Road Littleton, MA 01460 Marblehead Municipal Light Department By: /s/ Richard L. Bailey General Manager 80 Commercial Street, Box 369 Marblehead, MA 01945 Middleborough Gas & Electric Department By: /s/ John W. Dunfey General Manager 32 South Main Street Middleboro, MA 02346 Middleton Municipal Electric Department By: /s/ William E. Kelley Interim Manager 197 North Main Street Middleton, MA 01949 New England Electric System By: /s/ Jeffrey D. Tranen Vice President 25 Research Drive Westborough, MA 01582 Northeast Utilities Companies The Connecticut Light and Power Company By: /s/ Bernard M. Fox President and Chief Operating Officer P.O. Box 270 Hartford, CT 06141-0270 Western Massachusetts Electric Company By: /s/ Bernard M. Fox President and Chief Operating Officer P.O Box 270 Hartford, CT 06141-0270 Holyoke Water Power Company By: /s/ Bernard M. Fox President and Chief Operating Officer P.O. Box 270 Hartford, CT 06141-0270 Holyoke Power and Electric Company By: /s/ Bernard M. Fox President and Chief Operating Officer P.O. Box 270 Hartford, CT 06141-0270 Public Service Company of New Hampshire By: /s/ W. T. Frain, Jr Senior Vice President 1000 Elm Street Manchester, NH 03105 Pascoag Fire District By: /s/ Thomas J. Beauregard Chairman P.O. Box 107 Pascoag, Rhode Island 02859 Paxton Light Department By: /s/ Harold L. Smith Manager 578 Pleasant Street Paxton, MA 01612 Princeton Municipal Light Department By: /s/ Sharon A. Staz General Manager P.O. Box 247 Princeton, MA 01541-0247 Rowley Municipal Lighting Plant By: /s/ G. Robert Merry Manager 47 Summer Street Rowley, MA 01969 Shrewsbury's Electric Light Plant By: /s/ Thomas R. Josie General Manager 100 Maple Avenue Shrewsbury, MA 01545 Town of South Hadley Electric Light Department By: /s/ Wayne D. Doerpholz Manager 85 Main Street South Hadley, MA 01015 Taunton Municipal Lighting Plant By: /s/ Joseph M. Blain General Manager P O. Box 870 Taunton, MA 02780 Templeton Municipal Light Plant By: /s/ Gerald Skelton Manager/Engineer 2 School Street Baldwinville, MA 01436 The United Illuminating Company By: /s/ Richard J. Grossi Chairman and Chief Executive Officer 157 Church Street New Haven, CT 06506-0901 UNITIL Power Corporation By: /s/ David K. Foote Senior Vice President 216 Epping Road Exeter, NH 03833 Vermont Electric Power Company, Inc. By: /s/ Richard W. Mallary President P.O. Box 548 Rutland, VT 05702-0548 Central Vermont Public Service Corporation By: /s/ Robert de R. Stein Senior Vice President Engineering & Energy Resources 77 Grove Street Rutland, VT 05701 Franklin Electric Light Company By: /s/ Hugh H. Gates President P.O Box 96 Franklin, VT 05457 Green Mountain Power Corporation By: /s/ John V. Cleary President & Chief Executive Officer P.O Box 850 South Burlington, VT 05402 Vermont Marble Power Division of OMYA, Inc. By: /s/ John M. Mitchell Executive Vice President 61 Main Street Proctor, VT 05765 Village of Jacksonville By: /s/ Earle S. Holland President Board of Trustees P.O. Box 73 Jacksonville, VT 05342 Village of Ludlow Electric Light Department By: /s/ Donald Ellison Chairman, Board of Commissioners P.O. Box 289 Ludlow, VT 05109 Village of Morrisville Water and Light Department By: /s/ James C Fox Superintendent P.O. Box 325 Morrisville, VT 05661-0325 Village of Northfield Electric Department By: /s/ Kevin O'Donnell Municipal Manager 26 South Main Street Northfield, VT 05663 Readsboro Electric By: /s/ Annette Caruso Clerk P.O. Box 247 Readsboro, VT 05350 Wakefield Municipal Light Department By: /s/ William J. Wallace General Manager 9 Albion Street Wakefield, MA 01880 Westfield Gas & Electric Light Department By: /s/ Daniel Golubek General Manager Elm Street Westfield, MA 01085 EX-10 8 EXHIBIT 10-40.05 Exhibit 10-40.05 THIRTY-SECOND AGREEMENT AMENDING NEW ENGLAND POWER POOL AGREEMENT THIS THIRTY-SECOND AGREEMENT, dated as of the 1st day of September, 1995, is entered into by the signatory Participants for the amendment by them of the New England Power Pool Agreement dated as of September 1, 1971 (the "NEPOOL Agreement"), as previously amended by twenty-nine (29) amendments, the most recent of which was dated as of May 1, 1993; as previously proposed to be amended by a thirtieth amendment dated as of June 1, 1993 which has been withdrawn; and as proposed to be amended by a pending thirty-first amendment dated as of July 1, 1995. NOTE: Because Section I of the Thirty-Second Agreement is the only Section that amends the NEPOOL Agreement, only that Section is reproduced and compared to the language in the currently effective NEPOOL Agreement. All other text of the Thirty-Second Amendment has been deleted for purposes of this compare document. NOW THEREFORE, the signatory Participants hereby agree as follows: SECTION I AMENDMENTS TO NEPOOL AGREEMENT 1. The definition of "Entity" in Section 15.14 of the NEPOOL Agreement, as heretofore amended, is amended to read as follows: Entity is any person or organization engaged in the electric utility business (the generation and/or transmission and/or distribution of electricity for consumption by the public, or the purchase, as principal or broker, of electric energy and/or capacity for resale at wholesale), whether the United States of America or Canada or a state or province or a political subdivision thereof or a duly established agency of any of them, a private corporation, a partnership, an individual, an electric cooperative or any other person or organization recognized in law as capable of owning property and contracting with respect thereto. No person or organization shall be deemed to be an Entity if the generation, transmission and, or distribution of electricity by such person or organization is primarily conducted to provide electricity for consumption by such person or organization or an affiliated person or organization. 2. Section 5.15 of the NEPOOL Agreement, as heretofore amended, is amended to re-letter paragraph (h) as paragraph (i) and by inserting the following new paragraph (h) after present paragraph (g): (h) The Management Committee shall have the authority, at the time that it acts on an Entity's application pursuant to Section 1.2 to become a Participant, to waive conditionally or unconditionally, compliance by such Entity with one or more of the obligations imposed by this Agreement if the Committee determines that such compliance would be unnecessary or inappropriate for such Entity and the waiver for such Entity will not impose an additional burden on other Participants. 3. Section 5.16 of the NEPOOL Agreement, as heretofore amended, is hereby amended to read as follows: Each member of the Management Committee or that member's designee shall be entitled to attend any meeting of the Executive Committee, Operations Committee, and Policy Planning Committee and shall have a reasonable opportunity to express views on any matter to be acted upon at the meeting. THIRTY-SECOND AGREEMENT AMENDING NEW ENGLAND POWER POOL AGREEMENT THIS THIRTY-SECOND AGREEMENT, dated as of the 1st day of September, 1995, is entered into by the signatory Participants for the amendment by them of the New England Power Pool Agreement dated as of September 1, 1971 (the "NEPOOL Agreement"), as previously amended by twenty-nine (29) amendments, the most recent of which was dated as of May 1, 1993; as previously proposed to be amended by a thirtieth amendment dated as of June 1, 1993 which has been withdrawn; and as proposed to be amended by a pending thirty-first amendment dated as of July 1, 1995. WHEREAS, the NEPOOL Review Committee has been reconstituted, in response to a general invitation issued in early 1995 by the NEPOOL Participants, to include representatives of independent power producers ("IPPs"), power marketers, power brokers, utility regulators, environmental groups and others, and the Committee is currently discussing a restructuring of NEPOOL in light of the emerging changes in the electric utility industry; WHEREAS, the NEPOOL Review Committee's January 1995 Phase One Report concluded as part of the NEPOOL restructuring that "NEPOOL membership should be open to a broad spectrum of entities"; WHEREAS, IPPs are permitted to become Participants under current NEPOOL provisions and the Participants are willing, consistent with the NEPOOL Review Committee's Phase One Report, to amend the NEPOOL Agreement also to permit power marketers and power brokers to become Participants; WHEREAS, as an interim step in the restructuring of NEPOOL the Participants are willing to amend the NEPOOL Agreement to permit power marketers and power brokers to become Participants now, even before the completion of the restructuring of NEPOOL, to facilitate their participation in bulk power transactions in New England and more directly in the day-to-day activities of NEPOOL; WHEREAS, certain New England utilities that have chosen so far not to become Participants have expressed their interest in amending language to the NEPOOL Agreement in order to make membership in NEPOOL more desirable to them; WHEREAS, the amendments proposed herein do not change the voting and governance provisions of the NEPOOL Agreement; WHEREAS, representatives of certain of the IPPs and power marketers have expressed in NEPOOL Review Committee discussions (1) the belief that any amendments to the NEPOOL Agreement designed to effect the restructuring of NEPOOL should be preceded by an amendment to the NEPOOL voting and governance structure so that IPPs and power marketers can participate fully and have a separate vote on all restructuring matters placed before the NEPOOL Executive Committee, (2) the concern that the interests of IPPs and power marketers may not be adequately addressed in the restructuring discussions in the NEPOOL Executive Committee during the interim period when the terms of NEPOOL restructuring are being discussed, and (3) the position that the issue of whether and, if so, how to amend the definition of the term "Entity" under Section 15.14 of the NEPOOL Agreement to include end-users should be addressed and resolved during the NEPOOL restructuring process; WHEREAS, during NEPOOL Review Committee discussions, various NEPOOL Participants have expressed (1) their belief that the NEPOOL voting and governance structure (a) should be fair, (b) should take into account the interests of all members and reflect votes that are appropriately weighted in relationship to each member's responsibilities and obligations (i.e. transmission, generation and/or load), and (c) should minimize the opportunities for gridlock, (2) their desire to involve substantively the IPPs, power marketers, power brokers, Federal and state regulators, and any other interested entities in the restructuring effort, but not to impede the operations of NEPOOL during the restructuring process, and (3) the desire first to assure the opportunity for broader membership by all entities transacting business in the wholesale bulk power market in New England before addressing whether and, if so, how to involve end- users in the Pool; WHEREAS, in order to address the IPPs' and power marketers' beliefs, concerns, positions, desires, and interests, the Participants have invited IPPs, power marketers, and power brokers that elect to become Participants after this Thirty- Second Agreement is effective to select a common representative to receive notice of all meetings of the NEPOOL Executive Committee, NEPOOL Operations Committee, and NEPOOL Policy Planning Committee and to attend those meetings and act as their common spokesperson at such meetings; WHEREAS, those IPPs and power marketers involved in the NEPOOL Review Committee effort which are listed in Attachment 1 to this Thirty-Second Agreement have provided the Participants assurances that these IPPs and power marketers support or do not oppose acceptance of this Thirty-Second Agreement by the Federal Energy Regulatory Commission (the "Commission"); WHEREAS, in reliance on and subject to the assurances of the IPPs and power marketers described in the preceding paragraph, the Participants, IPPs and power marketers participating in the NEPOOL Review Committee effort have agreed that governance and voting issues relative to IPPs and power marketers are among the priority issues identified in the NEPOOL Review Committee's Phase One Report and that they will continue to use their best efforts to resolve these issues expeditiously through the NEPOOL Review Committee; and WHEREAS, Participants, IPPs and power marketers have also agreed that the issue of whether and, if so, how to amend the NEPOOL Agreement to permit membership by those not eligible for NEPOOL membership after this Thirty-Second Agreement becomes effective should be addressed before completion of the NEPOOL restructuring process; NOW THEREFORE, the signatory Participants hereby agree as follows: SECTION 1 AMENDMENTS TO NEPOOL AGREEMENT 1. The definition of "Entity" in Section 15.14 of the NEPOOL Agreement, as heretofore amended, is amended to read as follows: Entity is any person or organization engaged in the electric utility business (the generation and/or transmission and/or distribution of electricity for consumption by the public, or the purchase, as principal or broker, of electric energy and/or capacity for resale at wholesale), whether the United States of America or Canada or a state or province or a political subdivision thereof or a duly established agency of any of them, a private corporation, a partnership, an individual, an electric cooperative or any other person or organization recognized in law as capable of owning property and contracting with respect thereto. No person or organization shall be deemed to be an Entity if the generation, transmission, or distribution of electricity by such person or organization is primarily conducted to provide electricity for consumption by such person or organization or an affiliated person or organization. 2. Section 5.15 of the NEPOOL Agreement, as heretofore amended, is amended to re-letter paragraph (h) as paragraph (i) and by inserting the following new paragraph (h) after present paragraph (g): (h) The Management Committee shall have the authority, at the time that it acts on an Entity's application pursuant to Section 1.2 to become a Participant, to waive, conditionally or unconditionally, compliance by such Entity with one or more of the obligations imposed by this Agreement if the Committee determines that such compliance would be unnecessary or inappropriate for such Entity and the waiver for such Entity will not impose an additional burden on other Participants. 3. Section 5.16 of the NEPOOL Agreement, as heretofore amended, is hereby amended to read as follows: Each member of the Management Committee or that member's designee shall be entitled to attend any meeting of the Executive Committee, Operations Committee, and Policy planning Committee and shall have a reasonable opportunity to express views on any matter to be acted upon at the meeting. SECTION II PARTICIPATION ON NEPOOL COMMITTEES The Participants that are the signatories to this Thirty- Second Agreement agree that they will cause their representatives to take action in the NEPOOL Executive Committee, the NEPOOL Operations Committee and the NEPOOL Policy Planning Committee to authorize the IPPs, power marketers and power brokers that become Participants (collectively, such IPPs, power marketers, and power brokers are hereinafter referred to as "non-utility Participants") to designate as a group after this Thirty-Second Agreement becomes effective, a non-voting representative for each of the NEPOOL Executive Committee, NEPOOL Operations Committee, and NEPOOL Policy Planning Committee. The right to designate such representatives to the NEPOOL Executive Committee, NEPOOL Operations Committee, and NEPOOL Policy Planning Committee shall be in addition to, and not in lieu of, such non-utility Participants' rights under the existing provisions of the NEPOOL Agreement to be represented by members on the NEPOOL Operations Committee and NEPOOL Policy Planning Committee. If the non-utility Participants designate a representative for the NEPOOL Executive Committee, NEPOOL Operations Committee or NEPOOL Policy Planning Committee, that representative shall be treated as if he or she were a member of that Committee for purposes of notice of and participation in Committee meetings, but shall not be entitled to vote, and shall not be deemed a member of the Committee for purposes of determining the number of votes required for Committee action. SECTION III EFFECTIVENESS OF THE THIRTY-SECOND AGREEMENT This Thirty-Second Agreement, and the amendments provided for above, shall become effective on November 15, 1995, or on such other date as the Federal Energy Regulatory Commission shall provide that such amendments shall become effective. SECTION IV USAGE OF DEFINED TERMS The usage in this Thirty-Second Agreement of terms which are defined in the NEPOOL Agreement shall be deemed to be in accordance with the definitions thereof in the NEPOOL Agreement. SECTION V COUNTERPARTS This Thirty-Second 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-Second Agreement may be detached from any counterpart of this Thirty-Second Agreement without impairing the legal effect of any signatures thereof, and may be attached to another counterpart of this Thirty-Second 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 September, 1995. COUNTERPART SIGNATURE PAGE TO THIRTY-SECOND AGREEMENT AMENDING NEW ENGLAND POWER POOL AGREEMENT DATED AS OF September 1, 1995 The NEPOOL Agreement, being dated as of September 1, 1971, and being previously amended by twenty-nine (29) amendments the most recent of which was dated as of May 1, 1993 and as proposed to be amended by a pending amendment dated as of July 1, 1995. Boston Edison Company (Participant) By: /s/ Douglas S. Horan Title: Vice President & General Counsel Address: 800 Boylston Street (P360) Boston, MA 02199-8001 COUNTERPART SIGNATURE PAGE TO THIRTY-SECOND AGREEMENT AMENDING NEW ENGLAND POWER POOL AGREEMENT DATED AS OF SEPTEMBER 1, 1995 The NEPOOL Agreement, being dated as of September 1, 1971, and being previously amended by twenty-nine (29) amendments the most recent of which was dated as of May 1, 1995, and as proposed to be amended by a pending amendment dated as of July 1, 1995 Boylston Light Department (Participant) By: /s/ H. Bradford White, Jr. Name: H. Bradford White, Jr. Title: Manager Address: COUNTERPART SIGNATURE PAGE TO THIRTY-SECOND AGREEMENT AMENDING NEW ENGLAND POWER POOL AGREEMENT DATED AS OF September 1, 1995 The NEPOOL Agreement, being dated as of September 1, 1971, and being previously amended by twenty-nine (29) amendments the most recent of which was dated as of May 1, 1993 and as proposed to be amended by a pending amendment dated as of July 1, 1995. Blackstone Valley Electric Company Eastern Edison Company Montaup Electric Company Newport Electric Corporation (Participant) By: /s/ Kevin A. Kirby Title: Vice President Address: 750 West Center Street West Bridgewater, MA 02379-0543 COUNTERPART SIGNATURE PAGE TO THIRTY-SECOND AGREEMENT AMENDING NEW ENGLAND POWER POOL AGREEMENT DATED AS OF September 1, 1995 The NEPOOL Agreement, being dated as of September 1, 1971, and being previously amended by twenty-nine (29) amendments the most recent of which was dated as of May 1, 1993 and as proposed to be amended by a pending amendment dated as of July 1, 1995. Cambridge Electric Light Company Canal Electric Company Commonwealth Electric Company (Participant) By: /s/ Russell D. Wright Title: President and C.O.O. Address: 2421 Cranberry Highway Wareham, MA 02571-1002 COUNTERPART SIGNATURE PAGE TO THIRTY-SECOND AGREEMENT AMENDING NEW ENGLAND POWER POOL AGREEMENT DATED AS OF September 1, 1995 The NEPOOL Agreement, being dated as of September 1, 1971, and being previously amended by twenty-nine (29) amendments the most recent of which was dated as of May 1, 1993 and as proposed to be amended by a pending amendment dated as of July 1, 1995. Central Maine Power Company (Participant) By: /s/ Arthur Adelberg Title: Vice President Address: 83 Edison Drive Augusta, ME 04336-0001 COUNTERPART SIGNATURE PAGE TO THIRTY-SECOND AGREEMENT AMENDING NEW ENGLAND POWER POOL AGREEMENT DATED AS OF September 1, 1995 The NEPOOL Agreement, being dated as of September 1, 1971, and being previously amended by twenty-nine (29) amendments the most recent of which was dated as of May 1, 1993 and as proposed to be amended by a pending amendment dated as of July 1, 1995. Central Vermont Public Service Corporation (Participant) By: /s/ Robert Stern Name: Robert Stern Title: Senior Vice President Address: 77 Grove Street Rutland, VT 05701-3400 COUNTERPART SIGNATURE PAGE TO THIRTY-SECOND AGREEMENT AMENDING NEW ENGLAND POWER POOL AGREEMENT DATED AS OF September 1, 1995 The NEPOOL Agreement, being dated as of September 1, 1971, and being previously amended by twenty-nine (29) amendments the most recent of which was dated as of May 1, 1993 and as proposed to be amended by a pending amendment dated as of July 1, 1995. Chicopee Municipal Lighting Plant (Participant) By: Barry W. Soden Title: General Manager Address: 725 Front Street Chicopee, MA 01021-0405 COUNTERPART SIGNATURE PAGE TO THIRTY-SECOND AGREEMENT AMENDING NEW ENGLAND POWER POOL AGREEMENT AS OF September 1, 1995 The NEPOOL Agreement, being dated as of September 1, 1971, and being previously amended by twenty-nine (29) amendments the most recent of which was dated as of May 1, 1993 and as proposed to be amended by a pending amendment dated as of July 1, 1995. The Connecticut Light and Power Company Western Massachusetts Electric Company Holyoke Water Power Company Holyoke Power and Electric Company Public Service Company of New Hampshire (Participant) By: /s/ Frank P. Sabatino Title: Vice President Address: 107 Selden Street Berlin, CT 06037-1616 COUNTERPART SIGNATURE PAGE TO THIRTY-SECOND AGREEMENT AMENDING NEW ENGLAND POWER POOL AGREEMENT DATED AS OF September 1, 1995 The NEPOOL Agreement, being dated as of September 1, 1971, and being previously amended by twenty-nine (29) amendments the most recent of which was dated as of May 1, 1993 and as proposed to be amended by a pending amendment dated as of July 1, 1995. Conn. Municipal Electric Energy Cooperative (Participant) By: /s/ Maurice R. Scully Title: Executive Director Address: 30 Stott Avenue Norwich, CT 06360-1535 COUNTERPART SIGNATURE PAGE TO THIRTY-SECOND AGREEMENT AMENDING NEW ENGLAND POWER POOL AGREEMENT DATED AS OF September 1, 1995 The NEPOOL Agreement, being dated as of September 1, 1971, and being previously amended by twenty-nine (29) amendments the most recent of which was dated as of May 1, 1993 and as proposed to be amended by a pending amendment dated as of July 1, 1995. Fitchburg Gas and Electric Light Company (Participant) By: /s/ David K. Foote Title: Senior Vice President Address: 216 Epping Road Exeter, NH 03833-4575 COUNTERPART SIGNATURE PAGE TO THIRTY-SECOND AGREEMENT AMENDING NEW ENGLAND POWER POOL AGREEMENT DATED AS OF September 1, 1995 The NEPOOL Agreement, being dated as of September 1, 1971 and being previously amended by twenty-nine (29) amendments the most recent of which was dated as of May 1, 1993 and as proposed to be amended by a pending amendment dated as of July 1, 1995. Village of Hardwick Electric Department (Participant) By: /s/ Jack E. Young Name: Jack E. Young Title: General Manager Address: P.O. Box 516 Hardwick, VT 05843-0516 SIGNATURE PAGE TO THIRTY-SECOND AGREEMENT AMENDING NEW ENGLAND POWER POOL AGREEMENT DATED AS OF September 1, 1995 The NEPOOL Agreement, being dated as of September 1, 1971, and being previously amended by twenty-nine (29) amendments the most recent of which was dated as of May 1, 1993 and as proposed to be amended by a pending amendment dated as of July 1, 1995. Hingham Municipal Lightinq Plant (Participant) By: Joseph R. Spadea, Jr. Title: General Manager Address: 19 Elm Street Hingham, MA 02043-2518 COUNTERPART SIGNATURE PAGE TO THIRTY-SECOND AGREEMENT AMENDING NEW ENGLAND POWER POOL AGREEMENT DATED AS OF SEPTEMBER 1, 1995 The NEPOOL Agreement, being dated as of September 1, 1971, and being previously amended by twenty-nine (29) amendments the most recent of which was dated as of May 1, 1993, and as proposed to be amended by a pending amendment dated as of July 1, 1995. New England Power Company (Participant) By: /s/ Jeffrey D. Tranen Name: Jeffrey D. Tranen Title: President Address: 25 Research Drive Westborough, MA 01582 COUNTERPART SIGNATURE PAGE TO THIRTY-SECOND AGREEMENT AMENDING NEW ENGLAND POWER POOL AGREEMENT DATED AS OF SEPTEMBER 1, 1995 The NEPOOL Agreement, being dated as of September 1, 1971, and being previously amended by twenty-nine (29) amendments the most recent of which was dated as of May 1, 1993, and as proposed to be amended by a pending amendment dated as of July 1, 1995. Massachusetts Electric Company (Participant) By: /s/ Richard P. Sergel Name: Richard P. Sergel Title: Chairman Address: 25 Research Drive Westborough, MA 01582 COUNTERPART SIGNATURE PAGE TO THIRTY-SECOND AGREEMENT AMENDING NEW ENGLAND POWER POOL AGREEMENT DATED AS OF SEPTEMBER 1, 1995 The NEPOOL Agreement, being dated as of September 1, 1971, and being previously amended by twenty-nine (29) amendments the most recent of which was dated as of May 1, 1993, and as proposed to be amended by a pending amendment dated as of July 1, 1995. The Narragansett Electric Company (Participant) By: /s/ Richard P. Sergel Name: Richard P. Sergel Title: Chairman Address: 25 Research Drive Westborough, MA 01582 COUNTERPART SIGNATURE PAGE TO THIRTY-SECOND AGREEMENT AMENDING NEW ENGLAND POWER POOL AGREEMENT DATED AS OF SEPTEMBER 1, 1995 The NEPOOL Agreement, being dated as of September 1, 1971, and being previously amended by twenty-nine (29) amendments the most recent of which was dated as of May 1, 1993, and as proposed to be amended by a pending amendment dated as of July 1, 1995 Granite State Electric Company (Participant) By: /s/ Richard P. Sergel Name: Richard P. Sergel Title: Chairman Address: 25 Research Drive Westborough, MA 01582 COUNTERPART SIGNATURE PAGE TO THIRTY-SECOND AGREEMENT AMENDING NEW ENGLAND POWER POOL AGREEMENT DATED AS OF September 1, 1995 The NEPOOL Agreement, being dated as of September 1, 1971, and being previously amended by twenty-nine (29) amendments the most recent of which was dated as of May 1, 1993 and as proposed to be amended by a pending amendment dated as of July 1, 1995. New Hampshire Electric Cooperative, Inc. (Participant) By: /s/Steven Kaminski Title: Director, Energy Services Address: Tenney Mountain Highway Plymouth, NH 03264-9420 COUNTERPART SIGNATURE PAGE TO THIRTY-SECOND AGREEMENT AMENDING NEW ENGLAND POWER POOL AGREEMENT DATED AS OF September 1, 1995 The NEPOOL Agreement, being dated as of September 1, 1971, and being previously amended by twenty-nine (29) amendments the most recent of which was dated as of May 1, 1993 and as proposed to be amended by a pending amendment dated as of July 1, 1995. Paxton Municipal Light Department (Participant) By: /s/ Harold L. Smith Name: Harold L. Smith Title: Manager Address: 578 Pleasant Street Paxton, MA 01612-1365 COUNTERPART SIGNATURE PAGE TO THIRTY-SECOND AGREEMENT AMENDING NEW ENGLAND POWER POOL AGREEMENT DATED AS OF September 1, 1995 The NEPOOL Agreement, being dated as of September 1, 1971, and being previously amended by twenty-nine (29) amendments the most recent of which was dated as of May 1, 1993 and as proposed to be amended by a pending amendment dated as of July 1, 1995. The United Illuminating Company (Participant) By: /s/ James F. Crowe Title: Vice President Address: 157 Church Street, 16th Fl. New Haven, CT 06506-0901 COUNTERPART SIGNATURE PAGE TO THIRTY-SECOND AGREEMENT AMENDING ENGLAND POWER POOL AGREEMENT DATED AS OF September 1, 1995 The NEPOOL Agreement, being dated as of September 1, 1971, and being previously amended by twenty-nine (29) amendments the most recent of which was dated as of May 1, 1993 and as proposed to be amended by a pending amendment dated as of July 1, 1995. UNITIL Power Corp. (Participant) By: /s/ David K. Foote Name: David K. Foote Title: Senior Vice President Address: 216 Epping Road Exeter, NH 03833-4575 COUNTERPART SIGNATURE PAGE TO THIRTY-SECOND AGREEMENT AMENDING NEW ENGLAND POWER POOL AGREEMENT DATED AS OF September 1, 1995 The NEPOOL Agreement, being dated as of September 1, 1971, and being previously amended by twenty-nine (29) amendments the most recent of which was dated as of May 1, 1993 and as proposed to be amended by a pending amendment dated as of July 1, 1995. Vermont Electric Power Company Inc. (Participant) By: /s/ Richard M. Chapman Title: President/CEO Address: P.O. Box 548 Rutland, VT 05702-0548 APPENDIX 1 The following independent power producers and power marketers who are participating in the work of the NEPOOL Review Committee have provided the Participants assurances that they support or do not oppose acceptance of the foregoing Agreement by the Federal Energy Regulatory Commission: Enron Power Marketing, Inc. Coastal Electric Services Corp. North American Energy Conservation, Inc. KCS Power Marketing, Inc. Electric Clearing House, Inc. American National Power, Inc. Associated Power Service, Inc. Citizens Lehman Power Sales EX-13 9 EXHIBIT 13-1.03 EUA ANNUAL REPORT Eastern Utilities 1995 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; 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 service to approximately 297,000 customers in southeastern Massachusetts, and northern and coastal Rhode Island. Retail electric 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 wholesale to the retail electric subsidiaries and two other non-affiliated municipal electric utilities. "Map of Southern New England Depicting Montaup Electric Wholesale Territory, Blackstone Valley Electric Service Area, Eastern Edison Service Area and Newport Electric Service Area." Energy Related Business EUA's energy related business unit includes EUA Cogenex Corporation, EUA Ocean State Corporation and EUA Energy Investment Corporation. EUA Cogenex is the most active of our energy related companies with energy services contracts throughout the United States and Canada (map). EUA Ocean State owns a 29.9% partnership interest in the Ocean State Power electric generating station in northern Rhode Island. EUA Energy makes investments in energy related businesses. 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. On The Cover: Competition is on the horizon for the electric utility industry. Just as the race goes to the most prepared runner, so too, the company which is best prepared for competition is in a stronger position to win. Eastern Utilities intends to be a winner! Throughout this Annual Report, artist Paul Zwolak interprets factors we consider most important to our growth and the changing utility industry. "Map of United States and Southern Canada Depicting Areas of EUA Cogenex Activity" HIGHLIGHTS
1995 1994 1993 FINANCIAL DATA ($ in thousands) Operating Revenues $ 563,363 $ 564,278 $ 566,477 Consolidated Net Earnings(1) 32,626 47,370 44,931 Return on Average Common Equity 8.8% 13.6% 15.0% Common Shareholder Equity- % of Capitalization (Year-End) 44.5% 42.8% 38.7% Total Assets 1,200,273 1,234,049 1,203,137 Cash Construction Expenditures 77,923 50,519 76,391 COMMON SHARE DATA Consolidated Earnings per Share $ 1.61 $ 2.41 $ 2.44 Dividends Paid per Share $ 1.585 $ 1.515 $ 1.42 Annual Dividend Rate $ 1.60 $ 1.54 $ 1.44 Total Common Shares Outstanding 20,436,764 19,936,980 19,032,598 Average Common Shares Traded Daily 58,573 35,359 42,854 Book Value per Share (Year-End) $ 18.36 $ 18.33 $ 17.50 Market Price -High 25 27 3/8 29 7/8 -Low 21 1/2 21 3/8 23 7/8 -Year-End 23 5/8 22 28 OPERATING DATA Total Primary Sales (MWH) 4,441,000 4,410,000 4,352,000 System Requirements (MWH) 4,668,000 4,643,000 4,599,000 System Peak Demand (MW) 931 921 854 System Reserve Margin (At Peak) 24.2% 22.4% 37.1% System Load Factor 57.2% 57.5% 61.5% Customers (Year-End) 297,331 293,707 291,799 Employees (Year-End) - Core Electric 541 720 766 - Energy Related 253 240 238 - Corporate 536 437 440 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 completed in 1995.
To Our Shareholders Dear Shareholder: The waves of change continued rolling through the electric utility industry in 1995. Our management team continued its proactive involvement in the formation of the framework for an orderly transition from the age of regulated monopoly to the new world of competition. As this transition plays out over the next year or two we will be challenged to be flexible and innovative. During 1995 we made a number of decisions to better position ourselves in both the new competitive electric utility business and the energy services business. Some of these decisions had a negative impact on current earnings but we believe they were in the best long-term interests of all stakeholders. The balance of this letter will summarize some of our key activities within our Core Electric and Energy Related Businesses. Consolidated earnings per share of $1.61 were 33% below the $2.41 per share reported for the year 1994. Consolidated net earnings were $32.6 million versus $47.4 million in 1994. These decreases were driven primarily by two unusual charges which amounted to $13.2 million or 66 cents per share. These charges are more fully discussed in "Management's Discussion and Analysis." As stated earlier, we believe that these actions were in the best long-term interests of all stakeholders. Your dividend was increased 3.9% - about double the electric utility average - to an annual rate of $1.60. This increase was consistent with our goal of providing annual dividend increases above the industry average while maintaining a conservative payout ratio. CORE ELECTRIC BUSINESS The Retail and Wholesale Business units that comprise our Core Electric Business improved their 1995 earnings. This improvement came about despite a full year's impact of a reduction in electric rates to all customers implemented in mid 1994 and a one-time after-tax charge of $2.7 million for a voluntary retirement incentive. Consolidation of the Core Electric Business under a single management team enabled us to continue our practice of paring costs wherever possible without adversely affecting the quality of our service. As part of the consolidation, we were able to reduce the number of professional personnel by 49 through a voluntary retirement incentive. Since 1990 we have reduced the workforce of our Core Electric and Corporate Businesses by 20%. Introduction of our Choice and Competition proposal for the restructuring of the electric utility industry in Massachusetts and Rhode Island continued EUA's proactive involvement in this most important issue. The era of electric utility competition is upon us! Massachusetts and Rhode Island, the states where our utility subsidiaries do business, are at the forefront of this wave of industry reform. Choice and Competition is predicated on a regional approach to competition and envisions all customers in New England being able to choose their electricity supplier. ENERGY RELATED BUSINESS The decision to sell EUA Cogenex's portfolio of cogeneration installations was based on their poor financial performance and resulted in a one-time after-tax charge of $10.5 million. The sale enables our most active non-utility energy related subsidiary to refocus itself for the long term on the broader based, more profitable market for energy-efficiency services and products. The EUA Cogenex refocusing includes a consolidation of marketing activities designed to improve the "hit rate" of signed contracts from project proposals. In addition, new strategic alliances with major utilities in Pennsylvania and Kansas will expand EUA Cogenex's field of operations to 11 additional states. Our agreement with Duke/Louis Dreyfus LLC to market energy and related services throughout the six-state New England region provides us with the opportunity to become a meaningful player in the competitive New England marketplace as it develops. Two additional energy related opportunities in which we are investing also show promise for the future. TransCapacity L.P. has developed software to be used by participants in the gas industry. While we are disappointed that the progress of TransCapacity slowed in 1995, we still believe this investment has the potential to contribute positively to system earnings in the near future. The BIOTEN Partnership has developed a prototype bio-mass-fueled electric generating unit which is currently going through its initial test phase. These two energy related opportunities represent relatively modest investments with the potential for meaningful contributions to our earnings. Our medium size means that an investment that contributes as little as $1 million to earnings represents 5 cents per common share. WE PLAN TO SUCCEED The unprecedented restructuring of the electric utility industry will occupy a significant amount of our resources for the foreseeable future. However, it will not reduce the importance of our Energy Related Business activities. The key to EUA's future success will continue to be pursuit of strategies that will maximize the potential of each of our business units. It is our intention to succeed! We extend our thanks to our dedicated workforce who are being called upon each day to do more with less. We also thank you for your continued loyalty as shareholders and assure you that we will provide our strongest efforts to enhance the value of your investment. "Picture of Donald G. Pardus Chairman and Chief Executive Officer" "Picture John R. Stevens President and Chief Operating Officer" Donald G. Pardus Chairman and Chief Executive Officer John R. Stevens President and Chief Operating Officer March 8, 1996 BUSINESS AND STRATEGIES COMPETITION. COMPETITION. COMPETITION. ... a word that has been synonymous with many industries for centuries... a word that is sending shock waves through the electric utility industry today. At EUA we've operated in the competitive arena for ten years in the Energy Related businesses we own. Whether one views the coming of competition in the electric utility industry as the dawn of a bright new day or as thunder clouds in the distance, the reality is that the age of utility competition is here. The approach of a competitive marketplace led us to adopt our current Business Unit structure, a solid framework for the future. Our Core Electric Business includes two business units: Retail and Wholesale. These continue to be the foundation on which we build. Our Energy Related Business unit combines our energy related diversification efforts. It provides us with the vehicle to invest in opportunities that can enhance shareholder value and provide non-utility synergies to our Core Electric Business. Our Corporate Business unit provides professional and technical services to all EUA System companies. The remainder of this section briefly describes how EUA is taking a proactive position in the move to a competitive utility industry and the steps that have been taken at our Energy Related businesses in light of disappointing results in 1995. AN INDUSTRY IN TRANSITION There are many forces working toward a competitive marketplace in the electric utility industry - federal and state regulators, coalitions of utility stakeholders, state legislatures, as well as electric utility companies. EUA is taking a proactive stance in proposing principles that move us towards competition, while keeping in mind the interests of our shareholders, customers, employees and the communities we serve. Massachusetts and Rhode Island, the home states of our Core Electric Business, are at the forefront of the charge to a competitive electric industry. While both states retain their individuality, the goal of regulators and collaboratives of utilities and other industry stakeholders in each is the same: negotiate the transition to competition rather than litigate. The move to competition is not being driven only at the state level. The Federal Energy Regulatory Commission, which regulates our Wholesale Business unit, has been a primary catalyst by proposing new rules to require open access to bulk power transmission lines. Eastern Utilities has participated from the start at both the federal and state levels, and we'll continue our active role. We reinforced our commitment to establishing new relationships between service and energy providers and customers by introducing our Choice and Competition plan for a competitive industry. Our proposal would put all utilities in New England on an equal footing to compete head-to-head for power sales with each other and with other market alternatives. By envisioning New England-wide participation, Choice and Competition ensures access to all retail markets for all utilities and access to a variety of energy sources for all customers. Key components of Choice and Competition include: - Customer choice of supplier as early as 1998. Fossil-fueled and hydroelectric generating units enter the competitive arena without guaranteed cost recovery. - Performance-based rates governing the distribution costs of delivering energy to customers. The retail distribution companies would be measured against standards of performance and rewarded or penalized based on actual performance related to the standards. - Open, equal access to transmission facilities consistent with FERC policies. - Continued commitment to energy-efficiency and low-income programs. - Competitively-priced power for customers who choose not to choose. While we will do everything we can to spur competition, we accept the challenge of retaining our current customers with our traditional reliable service at the same time we actively pursue new business. These are but a few of our plan's highlights. We suspect the final outcome of the collaborative and/or legislative processes may not include all of our recommendations, but we intend to be proactive throughout the transition to a competitive electric industry. In positioning EUA for the future, our efforts have not been limited to the changing regulatory environment. We continue to look for innovative ways in which Eastern Utilities can gain access to market share which today is limited. For example, our Retail Business unit customers represent only 4% of the New England energy market. Our challenge is how, in a competitive market, we can gain access to the other 96%. In December we agreed to form a joint- venture with the Duke Energy subsidiary of Duke Power and the Louis Dreyfus Group - Duke/Louis Dreyfus Energy Services (New England) - which, once all regulatory authorizations are received, will provide the vehicle for us to participate in the marketing of energy and other services to the other 96% of New England. The new company should be ready to begin marketing electric power and other energy services to customers throughout New England when competition becomes a reality. Initial efforts of Duke/Louis Dreyfus Energy Services (New England) will focus on linking power buyers and sellers. Over the longer term, Duke/Louis Dreyfus Energy Services (New England) has the potential of controlling - by buying, leasing or building - its own generating capacity. We believe our knowledge of the New England market, our activities with the New England Power Pool, and our entrepreneurial skills within the region combined with the trading skills of Louis Dreyfus and Duke Energy's skills in developing and operating power plants make us a strong team, ready to play in the competitive arena. ENERGY RELATED COMPETITIVE IMPACTS Competition is not new to our Energy Related Business unit. In fact, it was increased competition and changes in the marketplace that had a negative impact on the financial results of the Energy Related Business unit in 1995. The competitive market changes impacted EUA Cogenex, our integrated energy services company, while a more demanding marketplace negatively impacted EUA TransCapacity, our subsidiary that holds an investment in a gas industry software developer. First, during 1995 EUA Cogenex saw continued poor results in its cogeneration business, an erosion of utility-supported demand-side management programs nationwide, and aggressive pricing pressures from competitors in the energy management market. The result was a disappointing year for our most active Energy Related business. Our challenge has been to refocus EUA Cogenex for 1996 so that it can retain its position as one of the major energy services companies in the country. Some of the steps EUA Cogenex has taken and will take as part of its refocusing efforts include: - Divest its cogeneration portfolio. This action was completed in September 1995 and resulted in a one-time after-tax $10.5 million reduction in consolidated net earnings. Elimination of this underperforming portion of its business enables EUA Cogenex to concentrate on its more profitable energy-efficiency business. - Concentrate on traditional markets. EUA Cogenex will concentrate on market sectors where it has been most successful: private educational institutions, hospitals, medium and large industrial and commercial facilities. Sectors such as federal and state facilities and utility demand side management programs have been de-emphasized. - Restructure sales and marketing. Consolidate marketing activities and improve the success, or "hit rate," of turning proposals into signed contracts. - Develop strategic alliances. In 1995, such alliances were announced with Allegheny Power Systems and Western Resources. These alliances are designed to provide EUA Cogenex with a significant presence in states where it historically has done little or no business and provide customers of these utilities an immediate and comprehensive selection of integrated energy services. A third strategic alliance with Monenco-Agra, a major provider of engineering and related services in Canada, awaits regulatory approval. These refocusing efforts should enable EUA Cogenex to enhance its profitability and contribution to EUA system earnings in 1996. Implementation of its redefined strategies should firmly establish EUA Cogenex's leadership position in its traditional markets while maintaining its strong reputation for customer service. A second segment of EUA's Energy Related business is our interest in the TransCapacity Limited Partnership, held by our EUA Energy Investment subsidiary. TransCapacity is a gas industry software developer in which we started making investments in 1993. The software, known as Capacity Scout TM, was designed to computerize the gathering and distribution of millions of pieces of natural gas pipeline capacity data needed to be competitive in the gas industry. We had expected our investment in TransCapacity to produce positive financial results in 1995, but developing market hurdles slowed the progress of this venture. The market indicated that providing data alone was not sufficient to entice users to utilize the Capacity Scout TM system. The market dictated that enhancements that had been planned for the future would be needed immediately in order to entice users. In addition, pipeline companies, the providers of much of the information, have been slow to fully implement FERC- mandated standards. In response to these market pressures, TransCapacity increased its activity at the Gas Industry Standards Board (GISB) to develop standard data and has now introduced its new T/Nominatr TM service. T/Nominatr TM enables clients to better use their pipeline capacity by providing a single interface for making electronic data interchange nominations, or notifications to move gas, to multiple pipelines. Pre-commercial user testing of T/Nominatr TM started in late 1995. Commercial installations began in the first quarter of 1996. T/Nominatr TM should provide TransCapacity with a distinct advantage over its competition. While we do not anticipate that TransCapacity will make a positive contribution to EUA earnings for the full year in 1996 we believe it is possible for its monthly contribution to be positive by year's end. TransCapacity continues to have the potential of being a meaningful contributor to EUA earnings in 1997 and beyond. Finally, EUA Energy Investment also has a 40% ownership interest in the BIOTEN Partnership. Test generation will begin in early 1996 at a prototype biomass-fired combustion turbine generating unit being developed in Tennessee. Additional investments in this venture are dependent upon the success of the prototype, which will not only generate electricity but also help alleviate an environmental disposal problem. The preliminary nature of this undertaking makes assessment of long-term earnings potential premature. Diversification will continue to play a significant role in EUA's future financial success. The long-term goals of our Energy Related Business unit are to provide an increasing percentage of EUA System earnings, maintain EUA Cogenex's leadership in the energy services industry, and investigate and develop new energy related business opportunities that will enhance shareholder value. WE PLAN TO SUCCEED IN THE COMPETITIVE WORLD EUA has already come far in the metamorphosis from utility holding company to diversified energy services company. We have positioned our Core Electric Business to be a positive force in the development of a competitive electric industry, and we will continue to search out niche-type energy related investments to support our non-core diversification efforts. The goal of these efforts is to strengthen our position in the marketplace and sharpen our competitive edge. Our emergence as a leader in diversified energy services gives us the opportunity to offer our customers a variety of energy options and to provide you, our shareholders, enhanced value for your EUA shares.
SELECTED CONSOLIDATED FINANCIAL DATA Years Ended December 31, (In Thousands Except Common Share Data) 1995 1994 1993 1992 1991 INCOME STATEMENT DATA: Operating Revenues $ 563,363 $ 564,278 $ 566,477 $ 541,964 $ 522,583 Operating Income 71,728 73,795 75,649 64,347 66,336 Consolidated Net Earnings(1) 32,626 47,370 44,931 34,111 26,260 BALANCE SHEET DATA: Plant in Service 1,037,662 1,020,859 1,016,453 1,002,717 990,726 Construction Work in Progress 7,570 8,389 8,728 4,943 6,881 Gross Utility Plant 1,045,232 1,029,248 1,025,181 1,007,660 997,607 Accumulated Depreciation and Amortization 324,146 304,034 296,995 274,725 251,503 Net Utility Plant 721,086 725,214 728,186 732,935 746,104 Total Assets 1,200,273 1,234,049 1,203,137 1,203,320 1,163,776 CAPITALIZATION: Long-Term Debt - Net 434,871 455,412 496,816 462,958 488,452 Redeemable Preferred Stock - Net 26,255 25,390 25,053 28,496 29,980 Non-Redeemable Preferred Stock - Net 6,900 6,900 6,900 15,850 15,850 Common Equity 375,229 365,443 333,165 266,855 248,598 Total Capitalization 843,255 853,145 861,934 774,159 782,880 Short-Term Debt 39,540 31,678 37,168 109,936 72,449 COMMON SHARE DATA: Consolidated Earnings per Average Common Share(1) $ 1.61 $ 2.41 $ 2.44 $ 2.00 $ 1.58 Average Number of Shares Outstanding 20,238,961 19,671,970 18,391,147 17,039,224 16,608,090 Return on Average Common Equity 8.8% 13.6% 15.0% 13.2% 10.8% Market Price -High 25 27 3/8 29 7/8 25 1/4 25 -Low 21 1/2 21 3/8 23 7/8 20 3/8 15 3/4 -Year-End 23 5/8 22 28 24 3/4 20 5/8 Dividends Paid per Share $ 1.585 $ 1.515 $ 1.42 $ 1.36 $ 1.45 (1) 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 Net Earnings and Earnings Per Share by business unit for 1995 and 1994 were as follows: 1995 1994 Net Net Earnings Earnings Earnings Earnings (Loss) (Loss) (Loss) (Loss) (000's) Per Share (000's) Per Share Core Electric Business $ 42,062 $ 2.08 $ 36,897 $ 1.88 Energy Related Business 3,658 0.18 7,390 0.37 Corporate 151 0.01 (817) (0.04) From Operations $ 45,871 $ 2.27 $ 43,470 $ 2.21 One-Time Impacts: VRI (2,747) (0.14) Cogen Discontinuance (10,498) (0.52) Tax Credits 3,900 0.20 Consolidated $ 32,626 $ 1.61 $ 47,370 $ 2.41 Major impacts on earnings by business unit are described in the following paragraphs. VOLUNTARY RETIREMENT INCENTIVE (VRI) OFFER In March 1995, Eastern Utilities Associates (EUA) announced a corporate reorganization which, among other things, consolidated management of Eastern Edison Company (Eastern Edison), Blackstone Valley Electric Company (Blackstone) and Newport Electric Corporation (Newport). As part of the reorganization, a VRI was offered to 66 professionals of 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. The estimated payback period is approximately 18 months. DISCONTINUATION OF COGENERATION OPERATIONS In September 1995, EUA announced that EUA Cogenex Corporation (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 cogeneration operations resulted in a one-time, after-tax charge of approximately $10.5 million, or 52 cents per share, to third quarter 1995 earnings. NON-RECURRING TAX CREDITS In 1994 EUA Ocean State Corporation (EUA Ocean State) recognized $3.9 million of Investment Tax Credits (ITC) related to its investment in Ocean State Power (OSP). In 1993 EUA recognized income of approximately $4.9 million, representing a portion of the expected utilization of EUA Power Corporation's (now known as Great Bay Power Corporation) ITC to reduce EUA's 1993 consolidated tax liability. These credits, for both years, are included in Other Income and Deductions-Net on the "Consolidated Statement of Income." The System has no remaining ITC carryforwards available. OPERATING REVENUES The following table sets forth estimates of the factors which contributed to the change in Operating Revenues from 1993 through 1995: Increase (Decrease) From Prior Years ($ in millions) 1995 1994 Operating Revenue change attributable to: Core Electric Business: Purchased Power Recovery $ (2.5) $ (8.0) Recovery of Fuel Costs 11.8 (1.4) Effect of Rate Changes (4.9) (6.4) Unit Contracts and Sales to NEPOOL (8.2) 1.8 Kilowatthour (KWH) Sales and Other (2.1) 4.2 Energy Related Business: EUA Cogenex 5.0 7.6 Total $ (0.9) $ (2.2) 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 result from the operation of fuel adjustment clauses. The change in such revenues reflects corresponding underlying changes in fuel costs. The Effect of Rate Changes reflects a base rate decrease for Montaup Electric Company (Montaup) implemented on May 21, 1994. Revenues attributable to Unit Contracts and sales to the New England Power Pool (NEPOOL) reflect 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 on base revenues and changes in other operating revenues including conservation and load management (C&LM) expense recoveries. Energy Related Business: Revenues of this business unit were generated entirely by EUA Cogenex. The 1995 change is due primarily to the impact of EUA Cogenex's acquisitions of Highland Energy Group (Highland) and Citizens Conservation Corporation (Citizens) in 1995. See "Energy Related Businesses" below. The 1994 increase of $7.6 million was due primarily to increased revenues of James L. Day Co. Inc., renamed EUA Day and Northeast Energy Management, Inc. (NEM) aggregating approximately $8.5 million. EUA Cogenex acquired EUA Day and NEM in December 1993 and January 1994, respectively. Partnership revenues and paid-from-savings contract revenues also increased in 1994. These increases were offset somewhat by a decline in project sales revenues recognized in 1994. CORE ELECTRIC BUSINESS KWH SALES Primary KWH sales of electricity by EUA's Core Electric Business unit increased by a modest 0.7% in 1995 compared to 1994. A 2.0% improvement in 1995 industrial sales is an indication of the continued slow improvement in economic conditions in EUA's service territory. Economic indicators suggest that this moderate trend will continue for the foreseeable future. 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 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. Total primary sales of electricity increased 1.3% in 1994, despite the fourth quarter's mild weather which caused an 18.7% decrease in heating degree days compared to those of the fourth quarter 1993. An on-going review of our customer classes resulted in the reclassification of certain customers from the commercial class to the residential and industrial classes in 1994. The impact of these reclassifications is reflected in the following table. Removing the impacts of these reclassifications results in 1994 sales increases of 1.1%, 0.6% and 3.0% to our residential, commercial and industrial customers, respectively. Percentage Changes in KWH Sales by Class of Customer for the past two years were as follows: Percent Increase (Decrease) From Prior Year 1995 1994 Residential 1.1 3.3 Commercial 0.2 (1.9) Industrial 2.0 4.2 Other Electric Utilities 1.4 20.4 Other (5.7) (7.0) Total Primary Sales 0.7 1.3 Losses and Company Use (2.6) (5.3) Total System Requirements 0.5 1.0 Unit Contracts (59.8) 20.2 Total Energy Sales (11.1) 4.2 EXPENSES 1995 VS. 1994 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 43.9% of total operating expenses for 1995. Fuel expense of the Core Electric Business increased by $3.3 million, or 3.8%, in 1995 compared to 1994. This change 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, as discussed above. Also, purchased power-energy costs, previously recorded as purchased power expense by Newport, were recorded as fuel expense by Montaup as a result of Newport becoming an all-requirements customer of Montaup effective May 21, 1994. This resulted in a classification adjustment which increased fuel expense and decreased purchased power expense by approximately $1.8 million in 1995. Purchased Power demand expense for 1995 decreased $4.5 million, or 3.4%. This change was due primarily to decreases of $6.7 million related to 41 megawatts (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: Other Operation and Maintenance (O&M) expenses for 1995 totaled $187.4 million, an increase of $2.9 million, or 1.6%, over 1994. Total O&M expenses are comprised of three components: Direct Controllable, Indirect and Energy Related. Changes in these components for 1995 were as follows: Increase ($ in millions) 1995 1994 (Decrease) Direct Controllable $ 83.4 $ 87.7 $ (4.3) Indirect 41.3 46.7 (5.4) Energy Related 62.7 50.1 12.6 Total O&M $ 187.4 $ 184.5 $ 2.9 Direct Controllable expenses of our Core Electric and Corporate Business units represent 44.5% of total 1995 O&M and include expense items such as: salaries, fringe benefits, insurance and maintenance. 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 Unit 1 and Millstone Unit 3 (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). The Energy Related component relates to O&M expenses of our Energy Related Business unit where increases are tied to new and expanded 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 1995. The changes in 1995 O&M expenses were due primarily to the following: Direct Controllable: Direct controllable expenses of our Core Electric and Corporate Business units decreased by $4.3 million. 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 were major components of that change. We reduced our Core Electric and Corporate units' workforce level by 6.9% in 1995 which will mitigate future labor cost increases. We remain committed to our efforts to control costs wherever possible. Indirect: Indirect expenses of the Core Electric and Corporate Business units decreased $5.4 million due primarily to $4.2 million of decreased C&LM expense and lower litigation expense. Energy Related: 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 Highland and costs related to new product development of the EUA Day division. Operating and development expenses of EUA Energy Investment Corporation (EUA Energy) increased $2.2 million in 1995 due primarily to development expenses related to the discontinued Home and Family venture and operating costs of EUA Transcapacity. Interest Charges: Net interest charges for 1995 decreased approximately $2.3 million compared to 1994. This change was due primarily to decreased long-term debt interest resulting from normal cash sinking fund payments, increases in capitalized interest of EUA Cogenex related to increased construction activity in 1995, 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. Income Taxes: EUA files a consolidated federal income tax return for the EUA System. EUA's 1995 composite federal and state effective tax rate was approximately 30.1%, versus 29% in 1994. In 1994 EUA Ocean State recognized $3.9 million of ITC as previously discussed. Taxes Other Than Income: Taxes other than income decreased $3.6 million in 1995 compared to 1994. The 1995 reversal of previously over-accrued property taxes and lower Rhode Island gross receipts taxes, related to lower revenues and a decrease in the gross receipts tax rate, account for most of this change. Other Items: Depreciation and Amortization expense decreased by $1.0 million, or 2.1%, in 1995. Decreased EUA Cogenex depreciation and amortization expense resulting from the disposal of cogeneration assets was the primary factor. Other Income (Deductions) - Net decreased by $4.3 million in 1995 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. (Vermont Co-op) 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. EXPENSES 1994 VS. 1993 Fuel and Purchased Power: Fuel expense for 1994 increased $2.4 million from 1993 due primarily to fuel expense previously recorded as purchased power- demand expense by Newport as previously discussed. A 4.8% decrease in the average cost of fuel in 1994 essentially offset the 4.2% increase in total energy sales. Purchased Power expense decreased from 1993 by $9.4 million, or 6.8%. This decrease was due primarily to expiring contracts totaling approximately 41 MW, lower billings by Montaup's suppliers aggregating approximately $8.6 million and the recognition of purchased power-energy as fuel expense (see above). These decreases were offset somewhat by a $1.0 million increase in C&LM expenses recorded as purchased power expense. Other Operation and Maintenance: O&M expenses for 1994 totaled $184.5 million, an increase of $2.4 million over 1993. Changes by O&M components for 1994 were as follows: Increase ($ in millions) 1994 1993 (Decrease) Direct Controllable $ 87.7 $ 86.0 $ 1.7 Indirect 46.7 47.1 (0.4) Energy Related 50.1 49.0 1.1 Total O&M $ 184.5 $ 182.1 $ 2.4 The changes in 1994 O&M expenses were due primarily to the following: Direct Controllable: Direct controllable expenses increased by $1.7 million in 1994 due to our decision to expense one-time computer software development and hardware buy-out costs aggregating $1.9 million. Cost control efforts continued to be successful in 1994, and we reduced our Core Electric workforce by 6.0%. Indirect: Indirect expenses decreased slightly in 1994 due to the offsetting impacts of decreased jointly owned generating unit expenses and pension expenses aggregating $3.8 million and increased FAS 106, C&LM and power contract expenses totaling $3.2 million. Energy Related: EUA Cogenex's O&M expenses for 1994 increased by $1.7 million. This increase was due primarily to the operations of EUA Day and NEM offset by a reduction in expenses related to lower project sales recognized in 1994. Research and development expenses of EUA Energy decreased $700,000 in 1994. Interest Charges: Interest on long-term debt for 1994 decreased approximately $2.5 million, or 6.1%, compared to 1993. This decrease was due primarily to the full year impact of Eastern Edison's 1993 refinancing of $195 million of long-term debt at lower rates and Newport's January 1994 issuance of $7.9 million of variable rate Electric Energy Facilities Revenue Refunding Bonds due 2011. Offsetting these declines somewhat was the issuance by EUA Cogenex of $50 million of 7% Unsecured Notes in October 1993. Income Taxes: EUA's 1994 composite federal and state effective tax rate was approximately 29%, versus 27.3% in 1993. This increase is primarily attributable to the net decrease in the income recognition of ITC in 1994 versus 1993. Other Items: Depreciation and Amortization expense increased by $1.7 million, or 3.9%, in 1994. Increased EUA Cogenex depreciation and amortization expense of $2.4 million was offset somewhat by a decrease in amortization expense of Montaup related to its Seabrook Unit II loss amortization which was completed in 1993. The EUA Cogenex increase was due primarily to the operations of EUA Day and NEM. Equity in Earnings of Jointly Owned Companies decreased in 1994 by approximately $1.7 million due primarily to lower earnings on EUA Ocean State's investment in OSP. Other Income (Deductions) - Net increased by $3.2 million in 1994 due to: (i) a decrease in tax expense recorded as other deductions of approximately $1.6 million; (ii) increased EUA Cogenex interest income and management fee income aggregating approximately $900,000; (iii) the $900,000 Vermont Co-op settlement as previously discussed; and (iv) the 1994 income recognition of $900,000 of capitalized costs previously discussed. These impacts were partially offset by a net decrease of $1.0 million in ITC utilized in 1994 versus 1993. The Preferred Dividend requirement of the retail subsidiaries decreased by approximately $1.0 million, or 29.6%, in 1994 due to a full-year impact of Eastern Edison's 1993 Preferred Stock financing activity. 1995 SYSTEM FINANCING ACTIVITY Core Electric Business: On December 1, 1995, Eastern Edison used available cash to fund maturities of $10 million of First Mortgage Bonds and $25 million of unsecured Medium Term Notes. Corporate: EUA received proceeds of approximately $6.0 million in 1995 from the issuance and sale of 262,115 common shares primarily through its Dividend Reinvestment and Common Share Purchase Plans. In May 1995 EUA issued 176,258 common shares in connection with the acquisition of Highland Energy Group, Inc. by EUA Cogenex. See "Energy Related Businesses" below for more details. "Bar Graph Depicting Cash Construction Expenditures and Internally Generated Funds for the Years 1991 Through 1995 as follows: " $ in Millions 1991 1992 1993 1994 1995 Cash Construction expenditures 57.57 71.365 76.391 50.519 77.922 Internally Generated Funds 63.681 48.933 79.691 79.274 90.883 Financial Condition and Liquidity: The EUA System's need for permanent capital is primarily related to investments in facilities required to meet the needs of its existing and future customers. Core Electric Business: For 1995, 1994 and 1993, the Core Electric Business cash construction expenditures were $31.5 million, $33.0 million and $32.4 million, respectively. Internally generated funds available after the payment of dividends supplied approximately 210%, 150% and 160% of these cash construction requirements in 1995, 1994 and 1993, 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 1996, 1997 and 1998 are estimated to be approximately $38.3 million, $35.3 million and $28.8 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 1996, 1997, 1998, 1999 and 2000 are $9.3 million, $2.3 million, $62.2 million, $11.6 million and $2.3 million, respectively. Energy Related Business: Capital expenditures of our Energy Related Business amounted to $44.7 million, $17.2 million and $43.6 million in 1995, 1994 and 1993, respectively. Internally generated funds supplied 68.8%, 111.9% and 29.6% of cash capital requirements in 1995, 1994 and 1993, respectively. Estimated capital expenditures of the Energy Related Business are $42.8 million, $58.3 million and $64.3 million in 1996, 1997 and 1998, respectively. Internally generated funds are expected to supply approximately 60% of 1996 estimated capital requirements. Continued growth at EUA Cogenex may require some external financing in the 1997-1998 time frame. 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 in 1996, 1997, 1998, 1999 and 2000 are $9.2 million, $24.2 million, $9.2 million, $9.2 million and $59.2 million, respectively. 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 1995 are $1.1 million. Short-Term Lines of Credit: At December 31, 1995, EUA System companies maintained short-term lines of credit with various banks aggregating approximately $150 million. Year-End Short-Term Debt Outstanding by business unit: ($ in thousands) 1995 1994 Core Electric Business $ 6,761 $ 0 Energy Related Business 14,421 23,476 Corporate 18,358 8,202 Total $ 39,540 $ 31,678 EUA expects to repay the outstanding balances of short-term indebtedness through internally generated funds and the possible issuance of additional EUA Cogenex debt securities. ENERGY RELATED BUSINESSES Net Earnings and Earnings Per Share contributions of EUA's Energy Related Businesses for 1995 and 1994, excluding one-time impacts, were as follows: 1995 1994 Net Net Earnings Earnings Earnings Earnings (Loss) (Loss) (Loss) (Loss) (000's) Per Share (000's) Per Share EUA Cogenex $ 2,704(1) $ 0.13(1) $ 4,171 $ 0.21 EUA Ocean State 4,617 0.23 4,456(2) 0.22(2) EUA Energy Investment (3,663) (0.18) (1,237) (0.06) Energy Related Business $ 3,658 $ 0.18 $ 7,390 $ 0.37 (1) Excludes one-time charge of $10.5 million, or 52 cents per share, related to discontinuance of cogeneration operations. (2) Excludes one-time recognition of $3.9 million, or 20 cents per share, of Investment Tax Credits. EUA Cogenex: EUA Cogenex's earnings from continuing operations decreased by approximately $1.5 million in 1995 due to, among other things, lower earnings on project sales and costs related to new product development by its EUA Day division. Also, 1995 saw a significant reduction in demand-side management activity as electric utilities nationwide prepare themselves for the evolution to a competitive marketplace. The discontinuance of its cogeneration operations will allow EUA Cogenex to devote maximum resources to providing integrated energy services. In addition EUA Cogenex has refocused its national sales force toward the private sector. Though governmental projects, such as the Department of Energy, have proven profitable for EUA Cogenex, securing such contracts is significantly more cumbersome, time consuming, and costly than private sector contracts. EUA Cogenex implemented various strategies in 1995 designed to leverage existing resources to broaden its markets, to reduce costs, and to bring new products to market. These efforts will continue in 1996. Specifically, EUA Cogenex will continue to develop its sales and marketing organization, evaluate and enter into strategic alliances, and emphasize cost control. In early 1995, EUA Cogenex completed its acquisitions of Highland Energy Group, Inc. of Boulder, Colorado, and the principal energy services operations of Citizens Conservation Corporation of Boston. Highland engages in conservation and energy management programs principally in Colorado, Texas, Ohio and North Carolina. The renamed EUA Citizens Conservation Services provides energy management services to the public and private multi-family housing sector. Also in 1995, EUA Cogenex announced joint ventures with affiliates of the Allegheny Power System and Western Resources, Inc. to provide energy services in and around the geographic regions served by those companies. In early 1996, EUA Cogenex announced a proposed joint venture with Monenco-Agra of Canada to provide similar services in Canada. EUA Ocean State: EUA Ocean State owns 29.9% of each of the partnerships which developed and operate Units I and II of OSP, twin 250-megawatt, 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, net of the $3.9 million of ITC utilized in 1994, was minimal. EUA Energy Investment: EUA Energy was organized to seek out investments in energy related businesses. The 1995 results reflect an increase in operating and development expenses versus 1994, in particular, expenses related to the Home and Family, L.P. pilot program, operating expenses of EUA Transcapacity, and development costs of BIOTEN's biomass-fired combustion turbine electric generation system. Market analysis results of the Home and Family pilot program led management to discontinue that venture in mid 1995. POWER MARKETING In December 1995, EUA and Duke/Louis Dreyfus LLC signed an agreement to form a company to market energy related services in New England. The new entity - Duke/Louis Dreyfus Energy Services (New England) LLC - plans to engage in electric power and fuels marketing and associated market hedges; own or lease generating facilities; and participate in other energy related activities such as energy-efficiency services and management of energy assets, upon receipt of required regulatory authorizations. This partnership will give EUA the opportunity to increase its share of New England's energy market. ELECTRIC OPERATIONS The 1995 peak demand for electricity, 931 MW on July 27, 1995, surpassed the previous all-time high, 921 MW, set in July 1994. 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 through the year 1999. As shown in the accompanying chart the EUA System's fuel mix continues to be diverse and is projected to remain that way in the future. "Three Pie Charts Depicting EUA Fuel Mix for the Years 1990, 1995, and estimated 2000 as follows: " 1990 1995 2000 Oil 38% 25% 21% Gas 2% 27% 29% Coal 22% 15% 13% Nuclear 38% 28% 33% Other 5% 4% The EUA System offers customers a comprehensive group of C&LM programs. These programs provide EUA with a flexible, cost-effective resource option, while serving customers with valued cost control opportunities to develop and maintain a competitive advantage. The programs also offer opportunities to EUA and its customers to comply with environmental standards and reduce air emissions. During 1995, more than 19,000 customers participated in one or more of the EUA System C&LM programs, resulting in 27,000 megawatthours of annual energy savings. In addition, the programs reduced customers' demand by 6,000 kilowatts in 1995 and provided the long-term benefits of reducing the need to invest in costly new generating facilities. ELECTRIC UTILITY INDUSTRY RESTRUCTURING The electric industry is in a period of transition from a traditional rate-regulated environment to a competitive marketplace. While competition in the wholesale electric market is not new, electric utilities now face impending competition in the retail sector. In 1995, Eastern Edison, Blackstone and Newport participated with collaborative groups in their respective states consisting of other utilities, industrial users, environmental groups and consumer advocates in submitting similar sets of interdependent principles addressing electric utility industry restructuring to their respective state regulatory commissions. These filings were intended to be statements of the consensus position by the signatories of the principles that should underlie any electric industry restructuring proposal and include but are not limited to principles addressing stranded cost recovery, unbundling of services and demand side management programs. Each set of principles was submitted on the condition they be approved in full by the respective Commissions. The Rhode Island Public Utilities Commission (RIPUC) accepted all but one of the principles submitted by the Rhode Island Collaborative with minor modifications to certain language in others and added a new principle which supports negotiation (as opposed to litigation) to resolve conflicts as restructuring moves forward. The RIPUC also directed the Rhode Island Collaborative to proceed with negotiations on the issues presented in the principles and to submit a progress report to the RIPUC, which was submitted in February of 1996. The one principle that was not accepted provided for subsidization of renewable energy sources. In February 1996 a bill was introduced in the Rhode Island legislature that, if enacted, would allow customer choice of electricity supplier commencing January 1, 1998 for large industrial customers and phasing in all customers by January 1, 2001. The proposed legislation also provides for recovery of "stranded investments" through a transition charge initially set at 3 cents per KWH. EUA believes that the development of the proposed legislation should have been conducted in a public forum so that all interested stakeholders could have participated. EUA believes that competition, if done right, can benefit customers. However, there are substantial issues about the proposed legislation which EUA is currently reviewing. The Massachusetts Department of Public Utilities (MDPU) issued an order enumerating principles, similar to those submitted by the Massachusetts Collaborative, that describe the key characteristics of a restructured electric industry and provide for, among other things, customer choice of electric service providers, services, pricing options and payment terms, an opportunity for customers to share in the benefits of increased competition, full and fair competition in the generation markets and incentive regulation for distribution services where competition cannot exist. This order sets out principles for the transition from a regulated to a competitive industry structure and identifies conditions for the transition process which will require investor- owned utilities to unbundle rates, provide consumers with accurate price signals and allow customers choice of generation services. The order also provides for the principle of recovery of net, non-mitigable stranded costs by investor-owned utilities resulting from the industry restructuring. Each Massachusetts investor-owned utility is required to file restructuring proposals for moving from the current regulated industry structure to a competitive generation market. The schedule for the filing requirement is staggered. The initial group of utilities was required to file their proposals in February 1996. The second group is required to file within three months of the MDPU's orders on the first group of submissions. Eastern Edison Company filed its proposal, Choice and Competition (see below) with the first group of proposals and is awaiting MDPU review. In January 1996, EUA unveiled its preliminary proposal for a restructured electric utility industry called Choice and Competition and began discussions with the Rhode Island and Massachusetts Collaboratives. The plan proposes, among other things: choice of power supplier by all customers as early as January 1998; open access transmission services; performance based rates for electric distribution services; all utility generation competing for power sales; and a transition charge allowing regional utilities the opportunity to recover, among other things, the costs of past commitments to nuclear and independent power. We believe the plan, which requires participation by all New England parties, satisfies the principles adopted in both Rhode Island and Massachusetts, and provides a fair and equitable transition to a competitive electric utility marketplace for all parties. 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. 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 such as Choice and Competition could ultimately cause EUA's 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. 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" (FAS 121) issued in March 1995, effective for fiscal year 1996. See "Notes to Consolidated Financial Statements," Note A, for further discussion of FAS 121. 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 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 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, the insurance carrier in these matters. As of December 31, 1995, the EUA System had incurred costs of approximately $4.6 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 $3.0 million may be incurred at these sites through 1997 by its subsidiaries and the other responsible parties. Estimates beyond 1997 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 J of "Notes to Consolidated Financial Statements" for further discussion. A number of scientific studies in the past several years have examined the possibility of health effects from electric and magnetic fields (EMF) that are found everywhere there is electricity. Research to date has not conclusively established a direct causal relationship between EMF exposure and human health. Additional studies, which are intended to provide a better understanding of the subject, are continuing. Management cannot predict the ultimate outcome of the EMF issue. OTHER Montaup is recovering through rates its share of estimated decommissioning costs for the Millstone Unit 3 and Seabrook Unit 1 nuclear generating units. Montaup's share of the currently allowed estimated total costs to decommission Millstone Unit 3 is approximately $19.2 million in 1995 dollars and Seabrook Unit 1 is approximately $12.5 million in 1995 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. 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 Securities and Exchange Commission, 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 22 Consolidated Statement of Cash Flows 23 Consolidated Balance Sheet 24 Consolidated Statement of Retained Earnings 25 Consolidated Statement of Equity Capital and Preferred Stock 25 Consolidated Statement of Indebtedness 26 Notes to Consolidated Financial Statements 27 Report of Independent Accountants 36 Report of Management 36 Quarterly Financial and Common Share Information 37 Consolidated Operating and Financial Statistics 38 Shareholder Information 40 Trustees and Officers Inside Back Cover
CONSOLIDATED STATEMENT OF INCOME Years Ended December 31, 1995 1994 1993 (In Thousands Except Common Shares and per Share Amounts) OPERATING REVENUES $ 563,363 $ 564,278 $ 566,477 OPERATING EXPENSES: Fuel 90,888 87,573 85,218 Purchased Power-Demand 125,616 130,080 139,524 Other Operation 163,907 160,985 156,972 Voluntary Retirement Incentive 4,505 Maintenance 23,468 23,510 25,148 Depreciation and Amortization 45,492 46,455 44,722 Taxes - Other Than Income 20,744 24,337 24,468 Income Taxes 17,015 17,543 14,776 Total Operating Expenses 491,635 490,483 490,828 Operating Income 71,728 73,795 75,649 Equity in Earnings of Jointly Owned Companies 12,063 12,485 14,140 Allowance for Other Funds Used During Construction 538 351 379 Loss on Disposal of Cogeneration Operations (18,086) Income Tax Impact of Loss on Disposal of Cogeneration Operations 7,588 Other Income (Deductions) - Net 2,574 6,847 3,655 Income Before Interest Charges 76,405 93,478 93,823 INTEREST CHARGES: Interest on Long-Term Debt 38,216 38,987 41,530 Amortization of Debt Expense and Premium - Net 2,752 2,729 1,904 Other Interest Expense 3,167 3,849 4,137 Allowance for Borrowed Funds Used During Construction (Credit) (2,677) (1,788) (1,989) Net Interest Charges 41,458 43,777 45,582 Net Income 34,947 49,701 48,241 Preferred Dividends of Subsidiaries 2,321 2,331 3,310 Consolidated Net Earnings $ 32,626 $ 47,370 $ 44,931 Average Common Shares Outstanding 20,238,961 19,671,970 18,391,147 Consolidated Earnings per Share $ 1.61 $ 2.41 $ 2.44 Dividends Paid per Share $ 1.585 $ 1.515 $ 1.42 The accompanying notes are an integral part of the financial statements.
CONSOLIDATED STATEMENT OF CASH FLOWS Years Ended December 31, (In Thousands) 1995 1994 1993 CASH FLOW FROM OPERATING ACTIVITIES: Net Income $ 34,947 $ 49,701 $ 48,241 Adjustments to Reconcile Net Income to Net Cash Provided from Operating Activities: Depreciation and Amortization 52,413 54,091 50,492 Amortization of Nuclear Fuel 3,647 3,310 5,136 Deferred Taxes (985) 8,017 11,099 Non-cash (Gains)/Expenses on Sales of Investments in Energy Savings Projects (1,264) 382 (4,731) Loss on Disposal of Cogeneration Operations 18,086 Investment Tax Credit, Net (1,212) (181) (1,279) Allowance for Other Funds Used During Construction (538) (351) (379) Collections and Sales of Project Notes and Leases Receivable 17,748 11,115 3,512 Other - Net 5,129 (10,360) 6,058 Changes in Operating Assets and Liabilities: Accounts Receivable 5,729 (4,509) (9,609) Materials and Supplies (1,280) (2,035) 452 Accounts Payable 1,543 (2,668) (1,885) Taxes Accrued (1,921) (5,834) 3,382 Other - Net (19,079) 9,641 (8,405) Net Cash Provided from Operating Activities 112,963 110,319 102,084 CASH FLOW FROM INVESTING ACTIVITIES: Construction Expenditures (77,923) (50,519) (76,391) Collections on Notes and Lease Receivables of EUA Cogenex 3,125 1,635 1,210 Proceeds from Disposal of Cogeneration Assets 11,501 Increase in Other Investments (2,300) (11,329) Net Cash (Used in) Investing Activities (65,597) (60,213) (75,181) CASH FLOW FROM FINANCING ACTIVITIES: Issuances: Common Shares 5,985 9,538 46,313 Long-Term Debt 7,925 245,000 Preferred Stock 30,000 Redemptions: Long-Term Debt (42,725) (13,233) (214,809) Preferred Stock (100) (100) (41,700) Premium on Reacquisition and Financing Expenses (63) (689) (14,956) EUA Common Share Dividends Paid (32,050) (29,795) (26,101) Subsidiary Preferred Dividends Paid (2,324) (2,333) (3,316) Net Increase (Decrease) in Short-Term Debt 7,862 (5,490) (72,768) Net Cash (Used in) Financing Activities (63,415) (34,177) (52,337) NET (DECREASE) INCREASE IN CASH AND TEMPORARY CASH INVESTMENTS: (16,049) 15,929 (25,434) Cash and Temporary Cash Investments at Beginning of Year 20,109 4,180 29,614 Cash and Temporary Cash Investments at End of Year $ 4,060 $ 20,109 $ 4,180 Cash Paid during the year for: Interest (Net of Amounts Capitalized) $ 39,306 $ 39,650 $ 45,057 Income Taxes $ 9,412 $ 15,233 $ 12,919 Conversion of Investments in Energy Savings Projects to Notes and Leases Receivable $ 19,324 $ 10,914 $ 16,591 The accompanying notes are an integral part of the financial statements.
CONSOLIDATED BALANCE SHEET December 31, (In Thousands) 1995 1994 ASSETS Utility Plant and Other Investments: Utility Plant in Service $ 1,037,662 $ 1,020,859 Less Accumulated Provisions for Depreciation and Amortization 324,146 304,034 Net Utility Plant in Service 713,516 716,825 Construction Work in Progress 7,570 8,389 Net Utility Plant 721,086 725,214 Non-utility Property - Net 82,347 107,803 Investments in Jointly Owned Companies 70,210 70,675 Other 67,157 55,416 Total Utility Plant and Other Investments 940,800 959,108 Current Assets: Cash and Temporary Cash Investments 4,060 20,109 Accounts Receivable: Customers, Net 61,096 63,709 Accrued Unbilled Revenues 11,311 10,178 Other 11,969 15,461 Notes Receivable 18,663 13,906 Materials and Supplies (at average cost): Fuel 7,450 6,413 Plant Materials and Operating Supplies 9,066 8,755 Other Current Assets 11,804 8,517 Total Current Assets 135,419 147,048 Other Assets 124,054 127,893 Total Assets $1,200,273 $ 1,234,049 LIABILITIES AND CAPITALIZATION Capitalization: Common Equity $ 375,229 $ 365,443 Non-Redeemable Preferred Stock of Subsidiaries - Net 6,900 6,900 Redeemable Preferred Stock of Subsidiaries - Net 26,255 25,390 Long-Term Debt - Net 434,871 455,412 Total Capitalization 843,255 853,145 Current Liabilities: Notes Payable - Banks 39,540 31,678 Long-Term Debt Due Within One Year 19,506 41,601 Accounts Payable 35,769 33,442 Redeemable Preferred Stock Sinking Fund Requirement 50 50 Taxes Accrued 4,544 6,465 Interest Accrued 10,861 10,889 Other Current Liabilities 19,931 29,566 Total Current Liabilities 130,201 153,691 Other Liabilities 86,077 89,313 Accumulated Deferred Taxes 140,740 137,900 Commitments and Contingencies (Note J) Total Liabilities and Capitalization $1,200,273 $ 1,234,049 The accompanying notes are an integral part of the financial statements.
CONSOLIDATED STATEMENT OF RETAINED EARNINGS 1995 1994 1993 Years Ended December 31, (In Thousands) Retained Earnings - Beginning of Year $ 56,617 $ 39,642 $ 21,434 Consolidated Net Earnings 32,626 47,370 44,931 Total 89,243 87,012 66,365 Dividends Paid - EUA Common Shares 32,050 29,795 26,101 Other 965 600 622 Retained Earnings - Accumulated since June 1991 Accounting Reorganization $ 56,228 $ 56,617 $ 39,642
CONSOLIDATED STATEMENT OF EQUITY CAPITAL & PREFERRED STOCK December 31, (Dollar Amounts In Thousands) 1995 1994 EASTERN UTILITIES ASSOCIATES: Common Shares: $5 par value 36,000,000 shares authorized, 20,436,764 shares outstanding in 1995 and 19,936,980 shares in 1994 $ 102,184 $ 99,685 Other Paid-In Capital 220,730 212,990 Common Share Expense (3,913) (3,849) Retained Earnings - Accumulated since June 1991 Accounting Reorganization 56,228 56,617 Total Common Equity 375,229 365,443 CUMULATIVE PREFERRED STOCK OF SUBSIDIARIES: Non-Redeemable Preferred: Blackstone Valley Electric Company: 4.25% $100 par value 35,000 shares (1) 3,500 3,500 5.60% $100 par value 25,000 shares (1) 2,500 2,500 Premium 129 129 Newport Electric Corporation: 3.75% $100 par value 7,689 shares (1) 769 769 Premium 2 2 Total Non-Redeemable Preferred Stock 6,900 6,900 Redeemable Preferred: Eastern Edison Company: 6 5/8% $100 par value 300,000 shares (2) 30,000 30,000 Expense, Net of Premium (335) (335) Preferred Stock Redemption Costs (3,447) (4,408) Newport Electric Corporation: 9.75% $100 par value 900 shares (1) 90 190 Expense (3) (7) Sinking Fund Requirement Due Within One Year (50) (50) Total Redeemable Preferred Stock 26,255 25,390 Total Preferred Stock of Subsidiaries $ 33,155 $ 32,290 (1) Authorized and Outstanding. (2) Authorized 400,000 shares. Outstanding 300,000 at December 31, 1995.
The accompanying notes are an integral part of the financial statements.
CONSOLIDATED STATEMENT OF INDEBTEDNESS December 31, (In Thousands) 1995 1994 EUA Service Corporation: 10.2% Secured Notes due 2008 $ 12,300 $ 14,500 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 19,200 20,000 10.56% Unsecured Notes due 2005 35,000 35,000 EUA Ocean State Corporation: 9.59% Unsecured Notes due 2011 33,544 36,020 Blackstone Valley Electric Company: First Mortgage Bonds: 9 1/2% due 2004 (Series B) 13,500 15,000 10.35% due 2010 (Series C) 18,000 18,000 Variable Rate Demand Bonds due 2014(1) 6,500 6,500 Eastern Edison Company First Mortgage and Collateral Trust Bonds: 8.9% Secured Medium Term Notes due 1995 10,000 4 7/8% due 1996 7,000 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 Unsecured Medium Term Notes: 9-9 1/4% due 1995 (Series A) 25,000 Newport Electric Corporation: First Mortgage Bonds: 9.0% due 1999 1,386 1,400 9.8% due 1999 8,000 8,000 8.95% due 2001 3,900 4,550 Small Business Administration Loan: 6.5% due 2005 809 894 Variable Rate Revenue Refunding Bonds due 2011(2) 7,925 7,925 Unamortized (Discount) - Net (687) (776) 454,377 497,013 Less Portion Due Within One Year 19,506 41,601 Total Long-Term Debt - Net $ 434,871 $455,412 (1) Weighted average interest rate was 3.9% for 1995 and 2.9% for 1994. (2) Weighted average interest rate was 3.9% for 1995 and 2.6% for 1994.
The accompanying notes are an integral part of the financial statements. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 1995, 1994 and 1993 (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 2.25% 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 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 $10.1 million at December 31, 1995 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. 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). EUA Ocean State's investment in OSP 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 3.3% in 1995 and 1994, and 3.4% in 1993 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, 1995 and 1994 are detailed as follows: (In Thousands) 1995 1994 Regulatory Assets: Unamortized losses on reacquired debt $ 15,894 $ 17,709 Unrecovered plant and decommissioning costs 10,100 18,400 Deferred FAS 109 costs (Note B) 48,196 43,535 Deferred FAS 106 costs 4,583 4,941 Mendon Road judgment (Note J) 6,591 5,857 Other regulatory assets 5,650 9,505 Total regulatory assets 91,014 99,947 Other deferred charges and assets: Unamortized debt expenses 5,349 6,197 Goodwill 7,054 7,260 Other 20,637 14,489 Total Other Assets $ 124,054 $ 127,893 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 such as "Choice and Competition" 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 as a result of higher depreciation expense. The combined rate used in calculating AFUDC was 9.2% in 1995, 9.7% in 1994, and 9.5% in 1993. 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 incurred 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 contracts are first accounted for as recovery of costs to the extent incurred. Federal Income Taxes: EUA and its subsidiaries generally reflect in income the estimated amount of taxes currently payable, and provide for deferred taxes on certain items subject to temporary timing differences to the extent permitted by the various regulatory agencies. EUA's rate-regulated subsidiaries 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. New Accounting Standard: In March 1995, the FASB issued Statement of Financial Accounting Standard No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of" (FAS 121), effective for fiscal year 1996. FAS 121 requires all regulatory assets, assets which were established as a result of high probability of recovery in a regulated environment, to continue to meet that high probability of recovery at each balance sheet date. Based on the current regulatory framework, management does not expect that adoption of this standard will have a material effect on EUA's financial position or results of operation. However, this assumption may change in the future as changes are made in the current regulatory framework or as competitive factors influence wholesale and retail pricing in the electric utility industry. (B) Income Taxes: EUA adopted FASB statement No. 109, "Accounting for Income Taxes" (FAS 109) 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. At December 31, 1995 and 1994, no valuation allowance was deemed necessary for total deferred tax assets. Total deferred tax assets and liabilities for 1995 and 1994 are comprised as follows: Deferred Tax Deferred Tax ($ in thousands) Assets ($ in thousands) Liabilities 1995 1994 1995 1994 Plant Related Plant Related Differences $21,028 $19,072 Differences $170,562 $164,130 Alternative Refinancing Minimum Tax 9,302 9,446 Costs 1,919 2,196 Litigation 41 902 Pensions 1,496 1,769 Bad Debts 125 234 Pensions 3,392 1,907 Acquisitions 4,281 4,575 Other 7,143 5,127 Other 11,684 10,627 Total $45,312 $41,263 Total $185,661 $178,722 As of December 31, 1995 and 1994, EUA has recorded on its Consolidated Balance Sheet a regulatory liability to ratepayers of approximately $27.2 million and $29.2 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, 1995 and 1994, a regulatory asset of approximately $48.2 million and $43.5 million, respectively, has been recorded, representing the cumulative amount of federal income taxes on temporary depreciation differences which were previously flowed through to ratepayers. EUA has $9.3 million of alternative minimum tax credits which have no expiration and can be utilized to reduce the consolidated regular tax liability. Under the terms of the December 1992 settlement agreement with EUA Power Corporation (EUA Power, now known as Great Bay Power Corporation), EUA was entitled to utilize EUA Power's tax credits to reduce the 1993 consolidated tax liability without compensation to EUA Power. Approximately $6.9 million of such credits were utilized in 1993 of which $4.9 million was charged against 1993 federal income tax expense. In 1994, EUA Ocean State utilized $3.9 million of investment tax credits related to its investment in OSP, which were charged against 1994 federal income tax expense and reduced the consolidated regular tax liability. EUA has no remaining ITC carryforwards available. Components of income tax expense for the year 1995, 1994, and 1993 are as follows: ($ in thousands) 1995 1994 1993 Federal: Current $ 10,335 $ 5,986 $ 9,203 Deferred 6,456 9,199 4,148 Investment Tax Credit, Net (1,130) (99) (1,197) 15,661 15,086 12,154 State: Current 2,579 1,154 2,289 Deferred (1,225) 1,303 333 1,354 2,457 2,622 Charged to Operations 17,015 17,543 14,776 Charged to Other Income: Current 4,353 9,243 1,770 Deferred (6,217) (2,486) 6,618 Investment Tax Credit, Net (82) (3,972) (5,049) (1,946) 2,785 3,339 Total $ 15,069 $ 20,328 $ 18,115 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) 1995 1994 1993 Federal Income Tax Computed at Statutory Rates $ 17,506 $ 24,510 $ 23,224 (Decrease) Increase in Tax From: Equity Component of AFUDC (187) (123) (133) Depreciation Differences 118 50 1,230 Amortization and Utilization of ITC (1,212) (5,115) (6,295) State Taxes, Net of Federal Income Tax Benefit (44) 2,285 2,237 Cost of Removal (36) (404) (583) Other (1,076) (875) (1,565) Total Income Tax Expense $ 15,069 $ 20,328 $ 18,115 (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, 1995, 1994, and 1993 were as follows:
Number of Common Shares Issued Dividend Northeast Highland Common Other Reinvestment Energy Energy Shares Paid-In Public and Employee J.L. Day Co. Management Group At Par Capital Offering Savings Plans Acquisition Acquisition Acquisition (000) (000) 1995 323,526 176,258 $ 2,499 $ 7,683 1994 427,304 12,499 464,579 4,522 10,209 1993 1,300,000 385,825 108,985 8,974 40,339
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, 1995 and 1994, 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 65/8% 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 65/8% 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 65/8% Preferred Stock are entitled to $100 per share plus accrued dividends. Newport's 9.75% Preferred Stock issue is entitled to a mandatory sinking fund sufficient to redeem 500 shares during each twelve-month period until the year 1999. The balance of any shares outstanding must be redeemed by the year 2000. The redemption price is $100 per share plus accrued dividends. In the event of involuntary liquidation, the holders of Newport's redeemable preferred stock are entitled to $100 per share plus accrued dividends. In the event of voluntary liquidation, or if redeemed at the option of Newport, the holders of the 9.75% issue are entitled to $102.44 per share plus accrued dividends prior to October 1, 1998; thereafter no premium is payable upon such redemption. The aggregate amount of redeemable preferred stock sinking fund requirements for each of the five years following 1995 are $50,000 for 1996, $40,000 for 1997 and zero for 1998, 1999 and 2000. (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, 1997. 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, 1997, 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 December, Eastern Edison used available cash to redeem $25 million of 9- 91/4% Unsecured Medium Term Notes at maturity, and $10 million of 8.90% First Mortgage and Collateral Trust 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 1995 are: $19.5 million in 1996, $27.5 million in 1997, $72.5 million in 1998, $21.9 million in 1999, and $62.5 million in 2000. (F) Fair Value Of Financial Instruments: The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate: Cash and Temporary Cash Investments: The carrying amount approximates fair value because of the short-term maturity of these instruments. Long Term Notes Receivable and Net Investment in Sales-Type Leases: The carrying amounts approximate fair value due to the nature of the asset. Preferred Stock and Long-Term Debt of Subsidiaries: The fair value of the System's redeemable preferred stock and long-term debt were based on quoted market prices for such securities at December 31, 1995. The estimated fair values of the System's financial instruments at December 31, 1995, are as follows: Carrying Fair ($ in thousands) Amount Value Cash and Temporary Cash Investments $ 4,060 $ 4,060 Long-Term Notes Receivable 38,635 38,635 Net Investment in Sales-Type Leases 9,565 9,565 Redeemable Preferred Stock 30,090 31,890 Long-Term Debt 455,064 479,242 (G) Lines Of Credit: EUA System companies maintain short-term lines of credit with various banks aggregating approximately $150 million. At December 31, 1995, unused short- term lines of credit were approximately $111 million. In accordance with informal agreements with the various banks, commitment fees are required to maintain certain lines of credit. During 1995, the weighted average interest rate for short-term borrowings was 6.2%. (H) Jointly Owned Facilities: At December 31, 1995, in addition to the stock ownership interests discussed in Note A, Nature of Operations and Summary of Significant Accounting Policies - Jointly Owned Companies, Montaup and Newport had direct ownership interests in the following electric generating facilities: Accumulated Provision For Net Construc- Utility Depreciation Utility tion Percent Plant in and Plant in Work in ($ in thousands) Owned Service Amortization Service Progress Montaup: Canal Unit 2 50.00% $ 71,715 $42,657 $ 29,058 $2,085 Wyman Unit 4 1.96% 4,050 2,020 2,030 Seabrook Unit 1 2.90% 194,735 23,993 170,742 454 Millstone Unit 3 4.01% 178,231 40,482 137,749 42 Newport: Wyman Unit 4 0.67% 1,314 684 630 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, 1995, Montaup's total net investment in nuclear fuel of the Seabrook and Millstone Units amounted to $3.0 million and $2.2 million, respectively. Montaup's and Newport's shares of related operating and maintenance expenses with respect to units reflected in the table above are included in the corresponding operating expenses. (I) Financial Information By Business Segments: The Core Electric Business includes results of the electric utility operations of Blackstone, Eastern Edison, Newport and Montaup. Energy Related Business includes results of our diversified energy related subsidiaries, EUA Cogenex, EUA Ocean State and EUA Energy Investment Corporation (EUA Energy). Corporate results include the operations of EUA Service and EUA Parent.
Pre-Tax Depreciation Cash Equity in Operating Operating Income and Construction Subsidiary ($ in thousands) Revenues Income Taxes Amortization Expenditures Earnings Year Ended December 31, 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 Year Ended December 31, 1993 Core Electric $ 499,565 $ 84,654 $ 18,443 $ 34,035 $ 32,407 $ 1,750 Energy Related 66,912 6,690 (3,766) 10,031 43,604 12,390 Corporate (919) 99 656 380 Total $ 566,477 $ 90,425 $ 14,776 $ 44,722 $ 76,391 $ 14,140
December 31, ($ in thousands) 1995 1994 Total Plant and Other Investments Core Electric $ 716,828 $ 721,840 Energy Related 203,670 217,584 Corporate 20,302 19,684 Total Plant and Other Investments 940,800 959,108 Other Assets Core Electric 188,087 204,982 Energy Related 57,083 55,554 Corporate 14,303 14,405 Total Other Assets 259,473 274,941 Total Assets $1,200,273 $1,234,049 (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 Unit 3 and a 2.9% interest in Seabrook Unit 1. Northeast Utilities, the operator of the units, indicates that Millstone Unit 3 has sufficient on-site storage facilities which, with rack additions, can accommodate its spent fuel for the projected life of the unit. At the Seabrook Project, there is on-site storage capacity which, with rack additions, will be sufficient to at least the year 2011. The Energy Policy Act 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 Unit 3 and Seabrook Unit 1. Montaup's share of the current estimate of total costs to decommission Millstone Unit 3 is $19.2 million in 1995 dollars, and Seabrook Unit 1 is $12.5 million in 1995 dollars. These figures are based on studies performed for the lead owners of the plants. Montaup also pays into decommissioning reserves pursuant to contractual arrangements with other nuclear generating facilities in which it has an equity ownership interest or life of the unit entitlement. Such expenses are currently recoverable through rates. Pensions: EUA maintains a non-contributory defined benefit pension plan covering substantially all employees of the EUA System (Retirement Plan). Retirement Plan benefits are based on years of service and average compensation over the four years prior to retirement. It is the EUA System's policy to fund the Retirement Plan on a current basis in amounts determined to meet the funding standards established by the Employee Retirement Income Security Act of 1974. Net pension expense for the Retirement Plan, including amounts related to the 1995 voluntary retirement incentive offer, for 1995, 1994 and 1993 included the following components: ($ in thousands) 1995 1994 1993 Service cost-benefits earned during the period $ 2,776 $ 3,281 $ 2,567 Interest cost on projected benefit obligations 9,391 8,848 8,761 Actual loss (return) on assets (36,220) 1,523 (18,005) Net amortization and deferrals 24,392 (12,494) 6,795 Net periodic pension expense 339 1,158 118 Voluntary Retirement Incentive 1,653 Total periodic pension expense $ 1,992 $ 1,158 $ 118 Assumptions used to determine pension costs: Discount Rate 8.25% 7.25% 8.75% Compensation Increase Rate 4.75% 4.75% 6.00% Long-Term Return on Assets 9.50% 9.50% 10.00% The following table sets forth the actuarial present value of benefit obligations and funded status at December 31, 1995, 1994 and 1993: ($ in thousands) 1995 1994 1993 Accumulated benefit obligations Vested $ (117,060) $ (96,045) $(101,279) Non-vested (271) (315) (358) Total $ (117,331) $ (96,360) $(101,637) Projected benefit obligations $ (135,415) $ (112,483) $(121,082) Plan assets at fair value, primarily stocks and bonds 152,308 122,816 130,040 Less: Unrecognized net gain on assets (21,769) (13,643) (11,689) Unamortized net assets at January 1 4,939 5,365 5,944 Net pension assets $ 63 $ 2,055 $ 3,213 The discount rate and compensation increase rate used to determine post- retirement benefit costs were changed effective January 1, 1996 to 7.25% and 4.25% respectively, and were used to calculate the plan's funded status at December 31, 1995. 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, 1995, approximately $1.5 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, 1995, approximately $3.4 million was included in accrued expenses and other liabilities for these plans. For the years ended December 31, 1995, 1994 and 1993 expenses related to the Supplemental Plans were $1.5 million, $516,000 and $2.3 million respectively. 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 periods 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 $6.3 million in 1995, $5.8 million in 1994 and $5.3 million in 1993. The total cost of post-retirement benefits other than pensions for 1995, 1994 and 1993 includes the following components: ($ in thousands) 1995 1994 1993 Service cost $ 996 $ 1,537 $ 1,337 Interest cost 4,822 5,381 5,983 Actual return on plan assets (671) (126) (68) Amortization of transition obligation 3,312 3,429 3,429 Other amortizations & deferrals - net (970) (85) (60) Net periodic post-retirement benefit cost 7,489 10,136 10,621 Voluntary Retirement Incentive 832 Total periodic post-retirement benefit costs $ 8,321 $ 10,136 $ 10,621 Assumptions used to determine post-retirement benefit costs Discount rate 8.25% 7.25% 8.75% Health care cost trend rate - near-term 11.00% 13.00% 13.00% - long-term 5.00% 5.00% 6.25% Salary increase rate 4.75% 4.75% 6.00% Rate of return on plan assets - union 8.50% 8.50% 8.50% - non-union 5.50% 5.50% 5.50% Reconciliation of funded status: ($ in thousands) 1995 1994 1993 Accumulated post-retirement benefit obligation (APBO): Retirees $(40,817) $(35,386) $(38,008) Active employees fully eligible for benefits (9,760) (9,778) (15,324) Other active employees (20,115) (23,306) $(25,357) Total $(70,692) $(68,470) $(78,689) Fair value of assets, primarily notes and bonds 12,614 7,722 3,522 Unrecognized transition obligation 56,314 61,718 65,147 Unrecognized net loss (gain) (7,575) (9,098) 5,368 (Accrued)/prepaid post-retirement benefit cost $ (9,339) $ (8,128) $ (4,652) The discount rate and compensation increase rate used to determine post- retirement benefit costs were changed effective January 1, 1996 to 7.25% and 4.25%, respectively, and were used to calculate the funded status of post- retirement benefits at December 31, 1995. Increasing the assumed health care cost trend rate by 1% each year would increase the total post-retirement benefit cost for 1995 by $0.8 million and increase the total accumulated post-retirement benefit obligation by $8.1 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 $7.1 million during 1995, $6.7 million in 1994 and $6.0 million in 1993. 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, 1995, the aggregate annual minimum commitments for such contracts are approximately $129 million in 1996 and 1997, $128 million in 1998, $127 million in 1999, $123 million in 2000 and will aggregate $1.4 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: The Comprehensive Environmental Response, Compensation and 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 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, Blackstone recorded the $5.9 million District Court judgment as a deferred debit. This amount is included with Other Assets at December 31, 1995 and 1994. 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 $1.2 million in connection with this settlement. As of December 31, 1995, the EUA System had incurred costs of approximately $4.6 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 $3.0 million (excluding the $5.9 million Mendon Road judgment) may be incurred at these sites through 1997 by its subsidiaries and the other responsible parties. Of this amount, approximately $2.5 million relates to sites at which Blackstone is a potentially responsible party. Estimates beyond 1997 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 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. 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 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 nitrogen oxide (NOx) controls for existing utility boilers required to meet the ozone non-attainment requirements of the Clean Air Act. The NESCAUM recommendations are more restrictive than the Clean Air Act requirements. The Massachusetts Department of Environmental Management has amended its regulations to require that Reasonably Available Control Technology (RACT) be implemented at all stationary sources potentially emitting 50 tons or more per year of NOx. Similar regulations have been issued in Rhode Island. Montaup has initiated compliance, through, among other things, selective noncatalytic reduction processes. 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. While some of the studies have indicated there may be some association between exposure to EMF and health effects, other studies have indicated no direct association. In addition, 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 the subject, are continuing. 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. There is a bill pending in the Massachusetts Legislature that would authorize the Massachusetts Department of Public Utilities to examine the potential health effects of EMF. 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 $35 million, 10.56% unsecured long-term notes due 2005 and EUA Ocean State's $33.5 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 Unit 1 and any costs of cancellation of Unit 1 or Unit 2. 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 $5.2 million of the outstanding debt of these two companies. In addition, Montaup and Newport have minimum rental commitments which total approximately $13.5 million and $1.7 million, respectively under a noncancelable transmission facilities support agreement for years subsequent to 1995. Other: In December 1992, Montaup commenced a declaratory judgment action in which it sought to have the Massachusetts Superior Court determine its rights under the Power Purchase Agreement between it and Aquidneck Power Limited Partnership. In April 1995 Montaup filed a motion for summary judgement and in June 1995 the court granted Montaup's motion. In July, Aquidneck filed for appeal of the court's decision. Montaup, EUA and EUA Service intend to vigorously contest the appeal and continue to believe that Aquidneck's claims have no basis in law. EUA Cogenex, through its EUA WestCoast (WestCoast) L.P., had under development a cogeneration facility of approximately 1.5 MW. The cogeneration facility experienced numerous start-up delays and cost overruns. The host of the facility has taken the position that the energy services agreement between WestCoast and itself is terminated due to, among other things, failure to complete the project. WestCoast disagrees with the host's right to terminate, but has decided not to contest the host's purported termination. In June 1993, WestCoast filed a lawsuit against the contractors responsible for the design and construction of the facility, as well as the surety which issued a performance bond guaranteeing construction. Certain defendants in that action have filed cross-complaints against WestCoast and EUA Cogenex, seeking, among other things, approximately $300,000 for payments withheld by 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 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. EUA WestCoast has secured defense from insurance carriers for the claims made by the host. EUA Cogenex intends to vigorously prosecute its claims against the contractors, surety and host, and defend itself against any cross-complaints. EUA Cogenex cannot predict the ultimate resolution of this matter. As a result of EUA Cogenex's decision to discontinue cogeneration operations effective as of July 1, 1995, EUA Cogenex has recorded a reserve for its total investment in this project which is included in the one-time after-tax charge to earnings of approximately $10.5 million. REPORT OF INDEPENDENT ACCOUNTANTS To the Trustees and Shareholders of Eastern Utilities Associates We have audited the accompanying consolidated balance sheets and consolidated statements of equity capital and preferred stock and indebtedness of Eastern Utilities Associates and subsidiaries (the Company) as of December 31, 1995 and 1994, and the related consolidated statements of income, retained earnings and cash flows for each of the three years in the period ended December 31, 1995. 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 consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of the Company as of December 31, 1995 and 1994, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 1995 in conformity with generally accepted accounting principles. Coopers & Lybrand L.L.P. Boston, Massachusetts March 5, 1996 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 auditors 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 1995: December 31 $ 135,327 $ 17,274 $ 10,989 $ 10,411 $ 0.51 $ 0.40 25 22 1/2 September 30 143,950 20,687 3,666 3,084 0.15 0.40 24 1/8 21 1/2 June 30 146,119 14,956 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 FOR THE QUARTERS ENDED 1994: December 31 $ 132,953 $ 15,408 $ 8,858 $ 8,277 $ 0.42 $ 0.385 23 1/8 21 3/8 September 30 143,859 18,482 13,900 13,316 0.67 0.385 25 1/8 22 June 30 137,269 18,304 10,770 10,187 0.52 0.385 25 5/8 22 March 31 150,197 21,601 16,173 15,590 0.80 0.36 27 3/8 24 5/8
Consolidated Operating and Financial Statistics (1) Years Ended December 31, 1995 1994 1993 1992 1991 1990 1985 ENERGY GENERATED AND PURCHASED (millions of KWH): Generated - by Somerset Station 679 658 319 936 957 985 1,316 - by Nuclear Units 752 1,008 1,033 1,050 1,109 1,635 1,065 - by Jointly-Owned Units 1,410 1,615 1,809 2,105 2,053 1,793 1,595 - by Life of the Unit Contracts 236 648 602 793 863 753 697 - by Newport 1 1 1 7 Interchange with NEPOOL 573 295 360 157 191 298 (387) Purchased Power - Unit Power 1,463 1,526 1,396 1,489 1,006 380 223 Total Generated and Purchased 5,113 5,750 5,520 6,531 6,180 5,851 4,509 OPERATING REVENUES ($ in thousands): Residential $193,233 $ 190,662 $ 189,470 $ 176,538 $178,812 $ 156,883 $110,682 Commercial 169,841 169,241 179,145 170,034 171,732 149,514 98,826 Industrial 83,061 81,500 81,445 76,946 78,273 69,885 66,707 Other Electric Utilities 5,447 4,900 5,098 5,103 4,828 4,317 15,779 Other 17,482 17,282 21,790 21,314 17,984 22,748 8,990 Total Primary Sales Revenues 469,064 463,585 476,948 449,935 451,629 403,347 330,984 Unit Contracts 14,800 26,213 22,617 47,875 41,225 43,670 32,526 Non-Electric 79,499 74,480 66,912 44,154 29,729 18,668 Total Operating Revenues $563,363 $ 564,278 $ 566,477 $ 541,964 $522,583 $ 465,685 $ 333,510 ENERGY SALES (millions of KWH): Residential 1,697 1,678 1,624 1,575 1,579 1,531 1,212 Commercial 1,674 1,671 1,704 1,704 1,689 1,623 1,169 Industrial 867 850 816 785 777 834 833 Other Electric Utilities 75 74 61 68 66 130 382 Other 128 137 147 147 154 121 29 Total Primary Sales 4,441 4,410 4,352 4,279 4,265 4,239 3,625 Losses and Company Use 227 233 247 241 280 249 197 Total System Requirements 4,668 4,643 4,599 4,520 4,545 4,488 3,822 Unit Contracts 445 1,107 921 2,011 1,635 1,363 687 Total Energy Sales 5,113 5,750 5,520 6,531 6,180 5,851 4,509 NUMBER OF CUSTOMERS: Residential 268,203 263,054 259,654 257,026 255,620 254,928 214,454 Commercial 27,401 29,004 30,805 32,851 32,745 32,836 23,161 Industrial 1,685 1,603 1,294 1,197 1,172 1,175 1,238 Other Electric Utilities 8 12 12 15 15 12 15 Other 34 34 34 34 34 34 30 Total Customers 297,331 293,707 291,799 291,123 289,586 288,985 238,898 Average Annual Revenue per Residential Customer ($) 720 725 730 687 699 636 516 Average Annual Use per Residential Customer (KWH) 6,327 6,379 6,254 6,128 6,177 6,221 5,652 AVERAGE REVENUE PER KWH (cents): Residential 11.39 11.36 11.67 11.21 11.32 10.25 9.13 Commercial 10.15 10.13 10.51 9.98 10.17 9.21 8.45 Industrial 9.58 9.59 9.98 9.80 10.07 8.38 8.01
(1) Includes financial and operating statistics for Newport Electric Corporation from April 1, 1990 and EUA Power Corporation through December 31, 1990 at which time EUA Power Corporation was deconsolidated for financial reporting purposes.
CONSOLIDATED OPERATING AND FINANCIAL STATISTICS Years Ended December 31, 1995 1994 1993 1992 1991 1990 1985 CAPITALIZATION ($ in thousands): Bonds - Net $ 279,374 $ 288,449 $ 300,389 $ 306,898 $ 346,146 $ 363,566 $ 263,500 Other Long-Term Debt - Net 155,497 166,963 196,427 156,060 142,306 80,029 21,991 Total Long-Term Debt - Net 434,871 455,412 496,816 462,958 488,452 443,595 285,491 Preferred Stock - Net 33,155 32,290 31,953 44,346 45,830 50,380 46,536 Common Equity 375,229 365,443 333,165 266,855 248,598 237,393 208,211 Total Capitalization $ 843,255 $ 853,145 $ 861,934 $ 774,159 $ 782,880 $ 731,368 $ 540,238 CAPITALIZATION RATIOS (%) Long-Term Debt 52 53 57 60 62 61 53 Preferred Stock 4 4 4 6 6 7 9 Common Equity 44 43 39 34 32 32 38 COMMON SHARE DATA: Earnings (Loss) per Average Common Share ($) 1.61 2.41 2.44 2.00 1.58 (8.18) 2.67 Dividends per Share ($) 1.585 1.515 1.42 1.36 1.45 2.575 2.03 Payout (%) 98.4 62.9 58.2 68.0 91.8 (31.5) 76.0 Average Common Shares Outstanding 20,238,961 19,671,970 18,391,147 17,039,224 16,608,090 15,917,255 11,156,941 Total Common Shares Outstanding 20,436,764 19,936,980 19,032,598 17,237,788 16,831,062 16,352,708 11,376,471 Book Value per Share ($) 18.36 18.33 17.50 15.48 14.77 14.52 18.30 Percent Earned On Average Common Equity 8.8 13.6 15.0 13.2 10.8 (42.5) 14.9 Market Price ($): High 25 27 3/8 29 7/8 25 1/4 25 41 1/2 26 7/8 Low 21 1/2 21 3/8 23 7/8 20 3/8 15 3/4 20 3/4 16 3/8 Year End 23 5/8 22 28 24 3/4 20 5/8 23 7/8 25 7/8 Miscellaneous ($ in thousands): Total Construction Expenditures ($) 78,461 50,870 76,770 71,914 60,174 133,629 78,192 Cash Construction Expenditures ($) 77,923 50,519 76,391 71,365 57,570 59,929 54,406 Internally Generated Funds ($) 90,883 79,274 79,691 48,933 63,681 35,024 27,501 Internally Generated Funds as a % of Cash Construction (%) 116.6 156.9 104.3 68.6 110.6 58.4 50.5 Installed Capability - MW 1,191 1,212 1,256 1,325 1,349 1,359 987 Less: Unit Contract Sales - MW 35 85 85 85 216 86 110 System Capability - MW 1,156 1,127 1,171 1,240 1,133 1,273 877 System Peak Demand - MW 931 921 854 849 879 850 738 Reserve Margin (%) 24.2 22.4 37.1 46.1 28.9 49.8 18.9 System Load Factor (%) 57.2 57.5 61.5 57.5 59.0 60.3 59.1 Sources of Energy (%): Nuclear 28.2 33.8 34.0 34.1 31.3 37.8 26.2 Coal 14.7 11.7 5.4 18.6 21.0 22.6 34.1 Oil 25.5 20.0 28.3 12.7 26.9 37.9 39.7 Gas 26.5 28.4 26.0 29.3 17.2 1.7 Other 5.1 6.1 6.3 5.3 3.6 Cost of Fuel (Mills per KWH): Nuclear 6.3 6.1 7.5 7.7 8.7 8.3 7.0 Coal 20.3 20.9 24.1 21.2 21.4 21.2 23.7 Oil 30.2 27.1 25.5 26.0 18.9 26.3 41.2 Gas 14.3 14.1 15.1 13.0 16.2 30.6 All Fuels Combined 16.7 14.5 15.5 14.8 15.7 18.4 26.3 Includes financial and operating statistics for Newport Electric Corporation from April 1, 1990 and EUA Power Corporation through December 31, 1990 at which time EUA Power Corporation was deconsolidated for financial reporting purposes. After additional charges to 1990 earnings. Excludes EUA Power Corporation's cash interest payments. 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, 1996, there were 12,161 common shareholders of record. Form 10-K A copy of EUA's 1995 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 1996 Annual Meeting of Shareholders will be held on Monday, May 20, 1996, 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 Mail Stop 450264 Boston EquiServe, L.P. Post Office Box 644 Boston, MA 02102-0644 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 1996 dividends on EUA Common Shares: Record Payment February 1 February 15 May 1 May 15 August 1 August 15 November 1 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., Treasurer/Secretary Eastern Utilities Associates 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. 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) Investor Boston, Massachusetts 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 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 "Picture of EUA Officers as Follows:" Left to Right (seated): Donald G. Pardus, Chairman and Chief Executive Officer; John R. Stevens, President and Chief Operating Officer. Left to Right (standing): Clifford J. Hebert, Jr., Treasurer and Secretary; Robert G. Powderly, Executive Vice President; John D. Carney, Executive Vice President. Not pictured: Richard M. Burns, Comptroller EX-13 10 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 84,000 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) 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 OSP's two gas-fired generating units. The holding company system of EUA, the three retail subsidiaries, Montaup, EUA Service, EUA Cogenex, EUA Energy and EUA Ocean State is referred to as the EUA System. 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 1995 Per Share 1994 Per Share First Quarter $5.35 First Quarter $4.17 Second Quarter 5.69 Second Quarter 4.88 Third Quarter 5.74 Third Quarter 4.93 Fourth Quarter 5.74 Fourth Quarter 5.44 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) 1995 1994 1993 1992 1991 _______________________________________________________________________ Operating Revenues $140,861 $140,611 $143,666 $138,604 $142,276 Net Earnings 4,009 3,438 4,069 2,583 3,192 Total Assets 123,978 121,413 114,552 115,698 117,936 Capitalization: Long-Term Debt 36,500 38,000 39,500 39,500 39,500 Non-Redeemable Preferred Stock 6,130 6,130 6,130 6,130 6,130 Common Equity 37,045 37,180 35,378 34,551 34,755 Total Capitalization $ 79,675 $ 81,310 $ 81,008 $ 80,181 $ 80,385 ======== ======== ======== ======== ======== MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND REVIEW OF OPERATIONS Overview Blackstone's net earnings for 1995 increased $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 voluntary retirement incentive (VRI) offer effective June 1, 1995 (See below). Kilowatthour (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. Blackstone's net earnings for 1994 decreased by $600,000 to $3.4 million and reflect the impacts of increases in other operating and maintenance expenses, and an increase in interest expense related to audits by the Internal Revenue Service on prior year tax returns. Through the third quarter of 1994, KWH sales were showing modest gains, but as a result of a poor fourth quarter in which KWH sales dropped by 1.1%, due to unusually mild weather, overall 1994 KWH sales were flat. 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 voluntary retirement incentive (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. The estimated payback period is approximately 18 months. Comparison of Financial Results Operating Revenues - 1995 vs 1994 Operating Revenues for 1995 increased by approximately $0.3 million 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. Operating Revenues - 1994 vs 1993 Operating Revenues for 1994 declined by approximately $3.1 million or 2.1%. Base revenues, attributable to changes in KWH sales, did not significantly change as compared to 1993, while the level of purchased power expense recoveries decreased approximately $2.8 million. Stagnant base revenues were the result of flat KWH sales in 1994 and the reduction in purchased power expense recoveries is the result of the decrease in the underlying expense, discussed below. Expenses - 1995 vs 1994 Purchased Power expense, which is recovered through Blackstone's purchased power adjustment clause and represented 72% of total 1995 operating expense, 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 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. Net interest charges for 1995 decreased by approximately $400,000 or 8.7%. This decrease was primarily due to decreased customer deposits interest and Internal Revenue Service (IRS) audits of prior years' consolidated income tax returns, which together aggregate over $300,000. Taxes Other than Income for 1995 decreased by $400,000 or 4.0% compared to 1994 due primarily to a 1% decrease in Rhode Island Gross Receipts Tax to industrial customers. Expenses - 1994 vs 1993 Purchased Power expense, decreased approximately $2.8 million or 2.9% from 1993. This decrease was due primarily to a wholesale rate reduction implemented May 21, 1994 by Montaup, Blackstone's supplier. Other Operation and Maintenance expenses in 1994 increased by approximately $300,000 or 2.9% as compared to 1993. Increased controllable expenses primarily consisting of distribution costs caused this increase. Net Interest Charges for 1994 increased by approximately $500,000 or 11.8%. Approximately $200,000 of the increase was as a result of interest incurred related to an IRS audit of prior years' consolidated income tax returns. The remaining $200,000 was primarily due to an increase in EUA Service allocated interest expense. Prior to July 1, 1993, allocated EUA Service interest expense was recorded as other operating expenses by Blackstone. Effective Income Tax Rate Blackstone's 1995 effective income tax rate increased from approximately 34.1% to 35.4% when compared to 1994 due primarily to decreased consolidated tax benefits. 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 1995, 1994 and 1993, the Company's cash construction expenditures were $5.1 million, $5.7 million and $5.3 million, respectively. In 1995 and 1994, internally generated funds provided over 100% of cash construction requirements. Cash Construction expenditures are expected to be $4.3 million in 1996, $4.5 million in 1997 and $4.6 million in 1998 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 $150 million. At December 31, 1995, unused short-term lines of credit amounted to approximately $111 million. These credit lines are available to other EUA System companies under joint credit line arrangements. Blackstone had $1.3 million of short-term borrowings outstanding at year end 1995, and zero at year-end 1994. Blackstone's requirements for sinking fund payments and redemption of securities for each of the five years following 1995 is $1.5 million. Electric Utility Industry Restructuring The electric industry is in a period of transition from a traditional rate regulated environment to a competitive marketplace. While competition in the wholesale electric market is not new, electric utilities are facing impending competition in the retail sector. In 1995, Eastern Edison, Blackstone and Newport participated with collaborative groups in their respective states consisting of other utilities, industrial users, environmental groups and consumer advocates in submitting similar sets of interdependent principles with their respective state regulatory commissions addressing electric utility industry restructuring. These filings were intended to be statements of the consensus position by the signatories of the principles that should underlie any electric industry restructuring proposal and include but are not limited to principles addressing stranded cost recovery, unbundling of services and demand side management programs. Each set of principles was submitted on the condition they be approved in full by the respective Commissions. The Rhode Island Public Utilities Commission (RIPUC) accepted all but one of the principles submitted by the Rhode Island Collaborative with minor modifications to certain language in others and added a new principle which supports negotiation (as opposed to litigation) to resolve conflicts as restructuring moves forward and directed the Rhode Island Collaborative to proceed with negotiations on the issues presented in the principles and to submit a progress report, which was submitted in February 1996. The one principle that was not accepted provided for subsidization of renewable energy sources. In February 1996 a bill was introduced in the Rhode Island legislature that, if enacted, would allow customer choice of electricity supplier commencing January 1, 1998 for large industrial customers and phasing in all customers by January 1, 2001. The proposed legislation also provides for recovery of "stranded investments" through a transition charge initially set at three cents per KWH. EUA believes that the development of the proposed legislation should have been conducted in a public forum so that all interested stakeholders could have participated. EUA believes that competition, if done right, can benefit customers, however, there are substantial issues about the proposed legislation which EUA is currently reviewing. The Massachusetts Department of Public Utilities (MDPU) issued an order enumerating principles, similar to those submitted by the Massachusetts Collaborative, that describe the key characteristics of a restructured electric industry and provides for, among other things, customer choice of electric service providers, services, pricing options and payment terms, an opportunity for customers to share in the benefits of increased competition, full and fair competition in the generation markets and incentive regulation for distribution services where competition cannot exist. This order sets out principles for the transition from a regulated to a competitive industry structure and identifies conditions for the transition process which will require investor- owned utilities to unbundle rates, provide consumers with accurate price signals and allow customers choice of generation services. The order also provides for the principle of recovery of net, non-mitigable stranded costs by investor-owned utilities resulting from the industry restructuring. Each Massachusetts investor-owned utility is required to file restructuring proposals for moving from the current regulated industry structure to a competitive generation market. The schedule for the filing requirement is staggered. The initial group of utilities was required to file their proposals in February 1996. The second group is required to file within three months of the MDPU's orders on the first group of submissions. Eastern Edison Company filed its proposal, "Choice and Competition" (see below) with the first group of proposals and is awaiting MDPU review. In January 1996, EUA unveiled its preliminary proposal for a restructured electric utility industry called "Choice and Competition" and began discussions with the Rhode Island and Massachusetts Collaboratives. The plan proposes, among other things: choice of power supplier by all customers as early as January 1998; open access transmission services; performance based rates for electric distribution services; all utility generation competing for power sales and; a transition charge allowing regional utilities the opportunity to recover, among other things, the costs of past commitments to nuclear and independent power. The company believes the plan, which requires participation by all New England parties, satisfies the principles adopted in both Rhode Island and Massachusetts, and provides a fair and equitable transition to a competitive electric utility marketplace for all parties. 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. 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 such as "Choice and Competition" could ultimately cause EUA's 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. 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, effective for fiscal year 1996. See "Notes to Consolidated Financial Statements", Note A for further discussion of FAS121. 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, 1995, Blackstone had incurred costs of approximately $4.1 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 $2.5 million may be incurred at these sites through 1997 by it and the other responsible parties. Estimates beyond 1997 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 Consolidated Financial Statements" for further discussion. A number of scientific studies in the past several years have examined the possibility of health effects from electric and magnetic fields (EMF) that are found everywhere there is electricity. Research to date has not conclusively established a direct causal relationship between EMF exposure and human health. Additional studies, which are intended to provide a better understanding of the subject, are continuing. Management cannot predict the ultimate outcome of the EMF issue. 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 Securities and Exchange Commission, 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. Managements' 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 complete understanding of such matters. Blackstone Valley Electric Company Statement of Income Years Ended December 31, (In Thousands)
1995 1994 1993 Operating Revenues $ 140,861 $ 140,611 $ 143,666 Operating Expenses: Purchased Power (princ. from an affiliate) 95,725 94,970 97,804 Other Operation and Maintenance 10,938 13,405 12,712 Voluntary Retirement Incentive 912 Affiliated Company Transactions 8,280 7,787 8,220 Depreciation 5,501 5,303 5,122 Taxes - Other than Income 8,821 9,202 9,508 Income and Deferred Taxes 2,347 1,885 1,988 Total Operating Expenses 132,524 132,552 135,354 Operating Income 8,337 8,059 8,312 Allowance for Other Funds Used During Construction 33 39 43 Other Income (Deductions) - Net (38) 78 (18) Income Before Interest Charges 8,332 8,176 8,337 Interest Charges: Interest on Long-Term Debt 3,481 3,476 3,449 Other Interest Expense 612 1,009 568 Allowance for Borrowed Funds Used During Construction (Credit) (59) (36) (38) Net Interest Charges 4,034 4,449 3,979 Net Income 4,298 3,727 4,358 Preferred Dividend Requirements 289 289 289 Net Earnings Applicable to Common Stock $ 4,009 $ 3,438 $ 4,069 Statement of Retained Earnings 1994 1993 1995 (Restated) (Restated) Retained Earnings - Beginning of Year $ 10,069 $ 10,204 $ 9,378 Net Income 4,298 3,727 4,358 Total 14,367 13,931 13,736 Dividends Paid: Preferred 289 289 289 Common 4,144 3,573 3,243 Retained Earnings - End of Year $ 9,934 $ 10,069 $ 10,204 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)
1995 1994 1993 CASH FLOW FROM OPERATING ACTIVITIES: Net Income $ 4,298 $ 3,727 $ 4,358 Adjustments to Reconcile Net Income to Net Cash Provided from Operating Activities: Depreciation and Amortization 5,953 6,157 5,918 Deferred Taxes 1,200 176 397 Investment Tax Credit, Net (183) 253 (176) Allowance for Funds Used During Construction (34) (39) (43) Other - Net 643 (6,072) (30) Net Changes in Operating Assets and Liabilities: Accounts Receivable (2,324) (603) 372 Materials and Supplies (172) (27) 124 Accounts Payable 7,540 1,484 (2,399) Accrued Taxes 337 (1,280) (83) Other - Net (7,239) 5,454 436 Net Cash Provided from Operating Activities 10,019 9,230 8,874 CASH FLOW FROM INVESTING ACTIVITIES: Construction Expenditures (5,064) (5,653) (5,344) Net Cash (Used in) Investing Activities (5,064) (5,653) (5,344) CASH FLOW FROM FINANCING ACTIVITIES: Redemptions: Long-Term Debt (1,500) Premium on Reacquisition and Financing Expenses (100) Common Share Dividends Paid (4,144) (3,573) (3,243) Preferred Dividends Paid (289) (289) (289) Net Increase in Short-Term Debt 1,259 Net Cash (Used in) Financing Activities (4,674) (3,862) (3,632) Net Increase (Decrease) in Cash 281 (285) (102) Cash and Temporary Cash Investments at Beginning of Year 472 757 859 Cash and Temporary Cash Investments at End of Year $ 753 $ 472 $ 757 Cash paid during the year for: Interest (Net of Amounts Capitalized) $ 3,565 $ 3,506 $ 3,480 Income Taxes $ 690 $ 1,836 $ 2,430 The accompanying notes are an integral part of the financial statements.
Blackstone Valley Electric Company Balance Sheet December 31, (In Thousands)
ASSETS 1994 1995 (Restated) Utility Plant and Other Investments: Utility Plant $ 136,503 $ 133,415 Less Accumulated Provision for Depreciation 48,023 44,112 Net Utility Plant 88,480 89,303 Non-Utility Property - Net 47 48 Total Utility Plant and Other Investments 88,527 89,351 Current Assets: Cash and Temporary Cash Investments 753 472 Accounts Receivable: Customers, Net 11,254 11,002 Accrued Unbilled Revenue 1,339 1,217 Others 4,726 2,736 Associated Companies 429 470 Plant Materials and Operating Supplies (at average cost) 939 767 Other Current Assets 393 422 Total Current Assets 19,833 17,086 Other Assets (Note A) 15,618 14,976 Total Assets $ 123,978 $ 121,413 LIABILITIES AND CAPITALIZATION Capitalization: Common Equity $ 37,045 $ 37,180 Non-Redeemable Preferred Stock 6,130 6,130 Long-Term Debt 36,500 38,000 Total Capitalization 79,675 81,310 Current Liabilities: Long-Term Debt Due Within One Year 1,500 1,500 Notes Payable 1,259 Accounts Payable: Public 282 603 Associated Companies 17,371 9,509 Customer Deposits 992 1,210 Taxes Accrued 1,777 1,441 Dividends Accrued 72 72 Interest Accrued 981 1,070 Other Current Liabilities 431 7,391 Total Current Liabilities 24,665 22,796 Deferred Credits: Unamortized Investment Credit 2,743 2,927 Other Deferred Credits 7,979 6,814 Total Deferred Credits 10,722 9,741 Accumulated Deferred Taxes 8,916 7,566 Commitments and Contingencies (Note H) Total Liabilities and Capitalization $ 123,978 $ 121,413 The accompanying notes are an integral part of the financial statements.
Blackstone Valley Electric Company Statement of Capitalization December 31, (In Thousands)
1994 1995 (Restated) 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 9,934 10,069 Total Common Equity 37,045 37,180 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) 13,500 15,000 10.35% due 2010 (Series C) 18,000 18,000 Variable Rate Demand Bonds Due 2014 6,500 6,500 38,000 39,500 Less Portion Due Within One Year 1,500 1,500 Total Long-Term Debt 36,500 38,000 Total Capitalization $ 79,675 $ 81,310 Authorized and Outstanding. Weighted average interest rate was 3.9% for 1995 and 2.9% for 1994. The accompanying notes are an integral part of the financial statements.
BLACKSTONE VALLEY ELECTRIC COMPANY NOTES TO FINANCIAL STATEMENTS December 31, 1995, 1994 and 1993 (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. Restatement: The Company has restated prior period balance sheets to correct an error in the accrual of property tax expense. The Company had previously over-accrued property tax expense. This correction increased retained earnings by $1.9 million, lowered taxes accrued by $3.0 million and increased accumulated deferred taxes by $1.1 million. 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 three other non-utility companies. Transactions between Blackstone and other affiliated companies include the following: purchased power costs billed by Montaup of approximately $95,683,000 in 1995, $94,944,000 in 1994 and $97,774,000 in 1993; accounting, engineering and other services rendered by EUA Service of approximately $10,448,000 in 1995, $9,524,000 in 1994 and $9,335,000 in 1993; and operating revenue from the rental of transmission facilities to Montaup of approximately $3,047,000 in 1995, $2,665,000 in 1994 and $2,884,000 in 1993. 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 1995, 1994, and 1993 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, 1995 and 1994 are detailed as follows (in thousands): 1995 1994 Regulatory Assets: Unamortized losses on reacquired debt $ 455 $ 486 Deferred SFAS 109 costs (Note B) 1,996 2,164 Deferred SFAS 106 costs (Note H) 1,017 1,017 Mendon Road Judgment (Note H) 6,591 5,857 Other regulatory assets 959 1,590 Total regulatory assets 11,018 11,114 Other deferred charges and assets: Unamortized debt expenses 710 795 Other 3,890 3,067 Total Other Assets $15,618 $14,976 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 such as "Choice and Competition" 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 8.6% in 1995, 10.0% in 1994 and 9.8% in 1993. 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. Federal Income Taxes: The general policy of Blackstone with respect to accounting for federal 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. New Accounting Standard: In March 1995, the Financial Accounting Standards Board issued Statement of Financial Accounting Standard No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of" (FAS 121), effective for fiscal year 1996. FAS 121 requires all regulatory assets, assets which were established as a result of high probability of recovery in a regulated environment, to continue to meet that high probability of recovery at each balance sheet date. Based on the current regulatory framework, management does not expect that adoption of this standard will have a material effect on Blackstone's financial position or results of operation. However, this assumption may change in the future as changes are made in the current regulatory framework or as competitive factors influence wholesale and retail pricing in the electric utility industry. (B) Income Taxes: Components of income and deferred tax expense for the years 1995, 1994, and 1993 are as follows: _________________________________________________________________ (In Thousands) 1995 1994 1993 Federal: Current $1,329 $1,436 $1,751 Deferred 1,133 176 409 Investment Tax Credit, Net (184) 253 (176) $2,278 1,865 1,984 State: Current 1 20 15 Deferred 68 (11) 69 20 4 Charged to Operations 2,347 1,885 1,988 Charged to Other Income: Current 3 46 (9) Total $2,350 $1,931 $1,979 ====== ====== ====== 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) 1995 1994 1993 Federal Income Tax Computed at Statutory Rates $2,327 $1,980 $2,217 (Decreases) Increases in Tax from: Equity Component of AFUDC (12) (14) (15) Consolidated Tax Savings (15) (125) (51) Depreciation Differences 262 260 358 Amortization of ITC (184) (194) (176) State Taxes, Net of Federal Income Tax Benefit 45 13 3 Cost of Removal (67) (110) (245) Other (6) 121 (113) Total Income Tax Expense $2,350 $1,931 $1,978 ====== ====== ====== 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. At December 31, 1995 and 1994 no valuation allowance was deemed necessary for total deferred tax assets. Total deferred tax assets and liabilities for 1995 and 1994 are comprised as follows: Deferred Tax Deferred Tax Assets Liabilities ($000) ($000) 1995 1994 1995 1994 Plant Related Plant Related Differences $1,730 $1,980 Differences $ 8,540 $8,192 Alternative Refinancing Minimum Tax 0 69 Costs 155 165 Revenue Clauses 0 203 Pensions 556 536 Pensions 501 201 Other 609 642 Other 2,496 712 Total $2,840 $3,095 Total $11,747 $9,605 ====== ====== ======= ====== Blackstone has recorded on its Balance Sheets as of December 31, 1995 and 1994 a regulatory liability to ratepayers of approximately $3.4 million and $3.7 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, 1995 and 1994, a regulatory asset of approximately $2.0 million and $2.2 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, 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. 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, 1995 and 1994, 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 $4,937,576 were unrestricted as to the payment of cash dividends on its common stock at December 31, 1995. (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, 1997. 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 1995 is $1.5 million. (F) Lines of Credit: The EUA System Companies, which include Blackstone, maintain short-term lines of credit with various banks aggregating approximately $150 million. At December 31, 1995, unused short-term lines of credit amounted to approximately $111 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 $1.3 million of short-term borrowings outstanding at year end. During 1995, Blackstone's weighted average interest rate for short-term borrowings was 6.1%. (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. 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, 1995 are as follows (dollars in thousands): Carrying Fair Amount Value Cash and Temporary Cash Investments $ 753 $ 753 Long-Term Debt $38,000 $39,366 (H) Commitments and Contingencies: Pensions: Blackstone participates with other EUA System companies in retirement plans which are non-contributory, defined benefit plans 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. Net pension expense (income) for the Retirement Plan, including amounts related to the 1995 voluntary retirement incentive, was $271,682 in 1995, $38,487 in 1994 and $(175,796) in 1993 and included the following components: 1995 1994 1993 Service cost - benefits earned during the period $ 605,703 $ 696,133 $ 567,204 Interest cost on projected benefit obligation 2,346,136 2,186,115 2,186,619 Act. loss (return) on assets (9,560,143) 396,900 (4,710,888) Net amortization and deferrals 6,470,282 (3,240,661) 1,781,269 Net periodic pension expense (income) $ (138,022) $ 38,487 $ (175,796) Voluntary retirement incentive 409,704 Total periodic pension expense (income) $ 271,682 $ 38,487 $ (175,796) ========== =========== =========== Assumptions used to determine pension cost: Discount Rate 8.25% 7.25% 8.75% Compensation Increase Rate 4.75% 4.75% 6.00% Long-Term Return on Assets 9.50% 9.50% 10.00% The discount rate and compensation increase rate used to determine pension costs were changed effective January 1, 1996 to 7.25% and 4.25%, respectively. 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, 1995, approximately $185,000 is included in other liabilities for the 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, 1995, 1994 and 1993 expenses related to the Supplemental Plans were approximately $306,000, $147,000 and $568,000, respectively. 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 $1.3 million in 1995, $1.5 million in 1994 and $1.3 million in 1993. The total cost of Post-Retirement Benefits other than Pensions for 1995, 1994 and 1993 includes the following components (in thousands): 1995 1994 1993 Service cost $ 191 $ 299 $ 266 Interest cost 1,170 1,323 1,504 Actual return on plan assets (111) (20) (10) Amortization of transition obligation 829 866 866 Net other amortization & deferrals (239) (10) (3) Net periodic post-retirement benefit costs 1,840 2,458 2,623 Voluntary Retirement Incentive 90 Total periodic post-retirement benefit costs $1,930 $2,458 $2,623 Assumptions: Discount rate 8.25% 7.25% 8.75% Health care cost trend rate-near-term 11.00% 13.00% 13.00% Health care cost trend rate-long-term 5.00% 5.00% 6.25% Compensation increase rate 4.75% 4.75% 6.00% Rate of return on plan assets 5.50% 5.50% 5.50% Reconciliation of funded status: 1995 1994 1993 Accumulated post-retirement benefit obligation (APBO): Retirees $(8,235) $ (7,498) $ (8,783) Active employees fully eligible for benefits (2,825) (2,589) (3,327) Other active employees (3,052) (4,093) (4,622) Total $(14,112) $(14,180) (16,732) Fair Value of assets (primarily notes and bonds) 924 364 84 Unrecognized transition obligation 12,083 13,328 14,068 Unrecognized net (gain) loss (2,217) (2,358) 956 (Accrued) prepaid post-retirement benefit cost $ (3,322) $(2,846) $ (1,624) The discount rate and compensation increase rate used to determine post- retirement benefit costs were changed effective January 1, 1996 to 7.25% and 4.25%, respectively and were used to calculate the funded status of Post- Retirement benefits at December 31, 1995. Increasing the assumed health care cost trend rate by 1% each year would increase the total post-retirement benefit cost for 1995 by approximately $177,000 and increase the total accumulated post-retirement benefit obligation by $1.5 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 $1.1 million during 1995, $800,000 during 1994 and $600,000 during 1993. 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, 1995 and 1994. 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 $1.2 million in connection with this settlement. As of December 31, 1995, Blackstone had incurred costs of approximately $4.1 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 and is recovering certain of those costs in rates. As a general matter, Blackstone will seek to recover costs relating to environmental proceedings in its rates. Blackstone applied for and received authority to recover in rates certain of the incurred costs over a five-year period. The Company estimates that additional costs (excluding the Mendon Road judgment) may be incurred at these sites through 1997 of up to approximately $2.5 million by it and the other responsible parties. Estimated amounts after 1997 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, 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 of the 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. 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/or 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 oxides of nitrogen 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 DEP 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 requiring that RACT be implemented at all stationary sources potentially emitting 50 or more tons per year of oxides of nitrogen. Montaup has initiated compliance through, among other things, selective, noncatalytic reduction processes. Report of Independent Accountants To the Directors and Shareholder of Blackstone Valley Electric Company: We have audited the accompanying balance sheets and statement of capitalization of Blackstone Valley Electric Company (the Company) as of December 31, 1995 and 1994, and the related statements of income, retained earnings and cash flows for each of the three years in the period ended December 31, 1995. 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, 1995 and 1994, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1995 in conformity with generally accepted accounting principles. Coopers & Lybrand L.L.P. Boston, Massachusetts March 5, 1996 EX-13 11 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 178,000 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) 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 OSP's two gas-fired generating units. The holding company system of EUA, the three retail subsidiaries, Montaup, EUA Service, EUA Cogenex, EUA Energy and EUA Ocean State is referred to as the EUA System. 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 1995 Per Share 1994 Per Share First Quarter $2.53 First Quarter $2.22 Second Quarter 0.43 Second Quarter 2.46 Third Quarter 0.46 Third Quarter 2.49 Fourth Quarter 0.45 Fourth Quarter 2.77 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) 1995 1994 1993 1992 1991 _______________________________________________________________________ Operating Revenues $420,069 $418,424 $417,021 $420,188 $414,609 Net Earnings 31,455 31,395 28,145 29,231 23,763 Total Assets 739,198 756,045 742,273 776,510 785,365 Capitalization: Long-Term Debt 222,313 229,224 264,134 269,995 304,991 Redeemable Preferred Stock-Net 26,218 25,257 24,824 28,171 29,558 Non-Redeemable Preferred Stock 8,949 8,949 Common Equity 244,368 225,064 223,005 220,257 211,126 Total Capitalization $492,899 $479,545 $511,963 $527,372 $554,624 ======== ======== ======== ======== ======== MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND REVIEW OF OPERATIONS Overview Consolidated Net Earnings for 1995 of $31.5 million were slightly higher than 1994 net earnings of $31.4 million. The 1995 net earnings include a one- time charge of approximately $1.5 million, on an after tax basis, related to the voluntary retirement incentive offer. Also impacting 1995 earnings was Montaup's $13.9 million annual wholesale rate reduction effective May 21, 1994. Offsetting these impacts somewhat were lower litigation expenses resulting from favorable court decisions rendered in 1995, lower interest expense and successful cost control efforts including ongoing savings of the voluntary retirement incentive (See below). 1994 Consolidated Net Earnings represented a $3.3 million increase over the prior year. Growth of 1.8% in primary kilowatthour (KWH) sales and lower long-term debt interest and preferred dividend requirements in 1994 as compared to 1993 were the major factors contributing to this increase. Early KWH sales gains in the year were offset somewhat by unusually mild weather in the fourth quarter. 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 voluntary retirement incentive (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. The estimated payback period is approximately 18 months. Comparison of Financial Results Operating Revenues - 1995 vs 1994 Operating Revenues for 1995 increased by approximately $1.6 million as compared to 1994. This change is 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 conservation and load management (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. Operating Revenues - 1994 vs 1993 Operating Revenues for 1994 increased by approximately $1.4 million from those of 1993. Contributing to this increase were the recoveries of increased fuel expense of approximately $2.9 million and higher primary KWH sales of 1.8% resulting in approximately $2.7 million of growth in base revenues. Offsetting these positive impacts somewhat was a decrease in revenues of approximately $3.2 million resulting from the net impact of Montaup's 1994 rate decrease. Expenses - 1995 vs 1994 The Company's most significant expense items continue to be fuel and purchased power expenses which together comprised about 58.9% of total operating expenses for 1995. 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 for 1995 increased $2.6 million to $125.6 million from 1994 amounts. 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 Unit 1 and Millstone Unit 3, 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 for 1995 decreased by approximately $5.7 million or 5.6% from 1994 levels. This decrease is 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 $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. Expenses - 1994 vs 1993 Fuel expense for 1994 increased $2.4 million from 1993. Approximately $2.1 million of 1994's increase in fuel expense relates to the assumed Newport contracts. A 4.8% decrease in the average cost of fuel in 1994 essentially offset the Company's 6.6% increase in total energy requirements. Purchased Power expense increased from 1993 by $1.6 million or 1.3%. This increase was primarily due to the impact of Montaup's assumption of Newport's purchased power contracts aggregating approximately $9.8 million. Offsetting this increase somewhat were expired purchased power contracts totaling approximately 41 MW and lower billings by Montaup suppliers aggregating approximately $8.6 million. Total Other Operating and Maintenance expenses decreased by approximately $1.7 million or 1.7% in 1994 due primarily to decreases in indirect expenses including approximately $2.3 million in maintenance expense of Montaup's jointly owned units and an additional $2.3 million reduction related to allocated charges from EUA Service Corporation recorded as other operating and maintenance expenses by the company. Partially offsetting these reductions were increases of $2.4 million in conservation and load management expenses and $400,000 of increased transmission and distribution expenses. Depreciation and Amortization expense decreased by $900,000 or 3.4% in 1994. The decrease was due primarily to Montaup's Seabrook Unit II loss amortization which was completed in 1993. Other Income & (Deductions) - Net increased $1.2 million or over 100% in 1994. The increase is due primarily to the recognition of approximately $900,000 of capitalized costs on nuclear fuel contract buy-out costs that had previously been deferred. Interest Expense on Long-Term Debt decreased by $4.1 million or 18.1% for 1994 as compared to 1993 primarily due to Eastern Edison's 1993 refinancing of $195 million of long-term debt at lower rates. Other Interest Expense increased $1.7 million or 58.1% in 1994 compared to 1993. The increase was a result of the recognition of approximately $1.0 million in interest related to Internal Revenue Service audits and the allocation methodology adopted in mid 1993 by EUA Service Corporation. Under this new methodology, EUA Service Corporation interest expenses are being allocated to other interest expense. They had previously been recorded as other operating expenses. Preferred Dividend Requirements decreased $1.0 million or 32.7% in 1994 due to a full-year impact of Eastern Edison's 1993 Preferred Stock financing activity. Electric Utility Industry Restructuring The electric industry is in a period of transition from a traditional rate regulated environment to a competitive marketplace. While competition in the wholesale electric market is not new, electric utilities are facing impending competition in the retail sector. In 1995, Eastern Edison, Blackstone and Newport participated with collaborative groups in their respective states consisting of other utilities, industrial users, environmental groups and consumer advocates in submitting similar sets of interdependent principles with their respective state regulatory commissions addressing electric utility industry restructuring. These filings were intended to be statements of the consensus position by the signatories of the principles that should underlie any electric industry restructuring proposal and include but are not limited to principles addressing stranded cost recovery, unbundling of services and demand side management programs. Each set of principles was submitted on the condition they be approved in full by the respective Commissions. The Rhode Island Public Utilities Commission (RIPUC) accepted all but one of the principles submitted by the Rhode Island Collaborative with minor modifications to certain language in others and added a new principle which supports negotiation (as opposed to litigation) to resolve conflicts as restructuring moves forward and directed the Rhode Island Collaborative to proceed with negotiations on the issues presented in the principles and to submit a progress report, which was submitted in February 1996. The one principle that was not accepted provided for subsidization of renewable energy sources. In February 1996 a bill was introduced in the Rhode Island legislature that, if enacted, would allow customer choice of electricity supplier commencing January 1, 1998 for large industrial customers and phasing in all customers by January 1, 2001. The proposed legislation also provides for recovery of "stranded investments" through a transition charge initially set at three cents per KWH. EUA believes that the development of the proposed legislation should have been conducted in a public forum so that all interested stakeholders could have participated. EUA believes that competition, if done right, can benefit customers, however, there are substantial issues about the proposed legislation which EUA is currently reviewing. The Massachusetts Department of Public Utilities (MDPU) issued an order enumerating principles, similar to those submitted by the Massachusetts Collaborative, that describe the key characteristics of a restructured electric industry and provides for, among other things, customer choice of electric service providers, services, pricing options and payment terms, an opportunity for customers to share in the benefits of increased competition, full and fair competition in the generation markets and incentive regulation for distribution services where competition cannot exist. This order sets out principles for the transition from a regulated to a competitive industry structure and identifies conditions for the transition process which will require investor- owned utilities to unbundle rates, provide consumers with accurate price signals and allow customers choice of generation services. The order also provides for the principle of recovery of net, non-mitigable stranded costs by investor-owned utilities resulting from the industry restructuring. Each Massachusetts investor-owned utility is required to file restructuring proposals for moving from the current regulated industry structure to a competitive generation market. The schedule for the filing requirement is staggered. The initial group of utilities was required to file their proposals in February 1996. The second group is required to file within three months of the MDPU's orders on the first group of submissions. Eastern Edison Company filed its proposal, "Choice and Competition" (see below) with the first group of proposals and is awaiting MDPU review. In January 1996, EUA unveiled its preliminary proposal for a restructured electric utility industry called "Choice and Competition" and began discussions with the Rhode Island and Massachusetts Collaboratives. The plan proposes, among other things: choice of power supplier by all customers as early as January 1998; open access transmission services; performance based rates for electric distribution services; all utility generation competing for power sales and; a transition charge allowing regional utilities the opportunity to recover, among other things, the costs of past commitments to nuclear and independent power. The company believes the plan, which requires participation by all New England parties, satisfies the principles adopted in both Rhode Island and Massachusetts, and provides a fair and equitable transition to a competitive electric utility marketplace for all parties. 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. Eastern Edison 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 such as "Choice and Competition" could ultimately cause Eastern Edison 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. 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, effective for fiscal year 1996. See "Notes to Consolidated Financial Statements", Note A for further discussion of FAS121. Rate Activity On March 21, 1994, Montaup filed an application with the Federal Energy Regulatory Commission (FERC) for authorization to reduce its wholesale rates by $10.1 million, or three percent. Montaup supplies electricity at wholesale to EUA's retail electric utilities - Eastern Edison, Blackstone and Newport - and to two non-affiliated municipal utilities. This application was designed to match more closely Montaup's revenues with its decreasing cost of doing business resulting from, among other things, a reduced rate base, lower interest costs and successful cost control efforts. On May 21, 1994, Montaup began billing the reduced rates, and on April 14, 1995, FERC approved a settlement agreement between Montaup and the intervenors in the case calling for an annual reduction of approximately $13.9 million (inclusive of the filed $10.1 million reduction). Montaup refunded to its customers the difference collected between the $10.1 million filed reduction and the $13.9 million settled reduction in April 1995. Montaup had previously reserved for that refund. 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 1995, 1994 and 1993, Eastern Edison's and Montaup's combined cash construction expenditures were $23.4 million, $23.6 million and $23.0 million, respectively. Internally generated funds provided approximately 236% of Eastern Edison's and Montaup's combined cash construction requirements in 1995. Cash construction expenditures are expected to be approximately $28.1 million, $25.9 million and $17.9 million in 1996, 1997 and 1998, respectively, and will 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 $150 million. These credit lines are available to other affiliated companies under joint credit line arrangements. At December 31, 1995, unused short-term lines of credit amounted to approximately $111 million. At December 31, 1995, Eastern Edison had $4.2 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 2000 are: $7 million in 1996 and $60 million in 1998. The Company has no sinking fund requirements until the year 2003. 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 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 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, 1995, Eastern Edison and Montaup had incurred costs of approximately $500,000, 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 $500,000 may be incurred at these sites through 1997 by themselves and the other responsible parties. Estimates beyond 1997 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 everywhere there is electricity. Research to date has not conclusively established a direct causal relationship between EMF exposure and human health. Additional studies, which are intended to provide a better understanding of the subject, are continuing. Management cannot predict the ultimate outcome of the EMF issue. Other Montaup is recovering through rates its share of estimated decommissioning costs for the Millstone Unit 3 and Seabrook Unit 1 nuclear generating units. Montaup's share of the currently allowed estimated total costs to decommission Millstone Unit 3 is approximately $19.2 million in 1995 dollars and Seabrook Unit 1 is approximately $12.5 million in 1995 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. 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 Securities and Exchange Commission, 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. Managements' 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 complete understanding of such matters. Eastern Edison Company and Subsidiary Consolidated Statement of Income Years Ended December 31, (In Thousands)
1995 1994 1993 Operating Revenues: From Affiliated Companies $ 133,388 $ 126,481 $ 121,934 Other 286,681 291,943 295,087 Total Operating Revenues 420,069 418,424 417,021 Operating Expenses: Fuel 90,881 87,522 85,066 Purchased Power - Demand 125,594 122,995 121,379 Other Operation and Maintenance 73,638 80,300 80,781 Voluntary Retirement Incentive 2,413 Affiliated Company Transactions 23,386 22,446 23,700 Depreciation and Amortization 26,039 25,546 26,450 Taxes - Other than Income 10,233 10,543 9,287 - Income 15,653 15,830 15,945 Total Operating Expenses 367,837 365,182 362,608 Operating Income 52,232 53,242 54,413 Equity in Earn. of Jointly Owned Companies 1,646 1,700 1,750 Allowance for Other Funds Used During Construction 473 263 289 Other Income (Deductions) - Net 407 897 (289) Income Before Interest Charges 54,758 56,102 56,163 Interest Charges: Interest on Long-Term Debt 18,277 18,488 22,584 Other Interest Expense 3,541 4,525 2,863 Allowance for Borrowed Funds Used During Construction (Credit) (503) (294) (385) Net Interest Charges 21,315 22,719 25,062 Net Income 33,443 33,383 31,101 Preferred Dividend Requirements 1,988 1,988 2,956 Consolidated Net Earnings Applicable to Common Stock $ 31,455 $ 31,395 $ 28,145 Consolidated Statement of Retained Earnings Years Ended December 31, (In Thousands) 1995 1994 1993 Retained Earnings - Beginning of Year $ 105,574 $ 103,515 $ 100,767 Net Income 33,443 33,383 31,101 Amort. of Preferred Stock Redemption Premium (961) (596) (597) Total 138,056 136,302 131,271 Dividends Paid: Preferred 1,988 1,988 2,977 Common 11,190 28,740 24,779 Retained Earnings - End of Year $ 124,878 $ 105,574 $ 103,515 The accompanying notes are an integral part of the financial statements.
Eastern Edison Company and Subsidiary Consolidated Statements of Cash Flows Years Ended December 31, (In Thousands)
1995 1994 1993 CASH FLOW FROM OPERATING ACTIVITIES: Net Income $ 33,443 $ 33,383 $ 31,101 Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities: Depreciation and Amortization 29,852 28,981 29,477 Amortization of Nuclear Fuel 3,647 3,310 5,136 Deferred Taxes 2,694 5,500 2,981 Investment Tax Credit, Net (942) (348) (1,016) All. for Funds Used During Construction (473) (263) (289) Other - Net 1,219 (3,285) (3,331) Changes to Operating Assets and Liabilities: Accounts Receivable (7,055) (7,667) (7) Fuel, Materials and Supplies (1,678) 194 899 Accounts Payable 827 3,495 (792) Accrued Taxes 1,807 (2,814) 835 Other - Net (6,630) 4,485 (5,063) Net Cash Provided from Operating Activities 56,711 64,971 59,931 CASH FLOW FROM INVESTING ACTIVITIES: Construction Expenditures (23,423) (23,613) (22,967) Net Cash (Used in) Investing Activities (23,423) (23,613) (22,967) CASH FLOW FROM FINANCING ACTIVITIES: Issuances: Long-Term Debt 0 195,000 Preferred Stock 0 30,000 Long-Term Debt (35,000) 0 (205,000 Preferred Stock 0 (41,600) Premium on Reacquisition and Financing Expenses (62) (12,430) Common Stock Dividends Paid (11,190) (28,740) (24,779) Preferred Dividends Paid (1,988) (1,988) (2,977) Net Increase in Short Term Debt 4,158 Net Cash (Used in) Financing Activities (44,020) (30,790) (61,786) Net (Decrease) Increase in Cash and Temporary Cash Investments (10,732) 10,568 (24,822) Cash and Temporary Cash Investments at Beginning of Year 11,265 697 25,519 Cash and Temporary Cash Investments at End of Year $ 533 $ 11,265 $ 697 Cash paid during the year for: Interest (Net of Amts. Capitalized) $ 18,343 $ 18,406 $ 27,200 Income Taxes $ 9,044 $ 15,877 $ 13,372 The accompanying notes are an integral part of the financial statements.
Eastern Edison Company and Subsidiary Consolidated Balance Sheets December 31, (In Thousands)
ASSETS 1995 1994 Utility Plant and Other Investments: Utility Plant $ 798,706 $ 789,596 Less Accumulated Provision for Depreciation 241,673 228,241 Net Utility Plant 557,033 561,355 Non-Utility Property - Net 2,705 2,705 Investment in Jointly Owned Companies 13,223 13,488 Other Investments (at cost) 50 50 Total Utility Plant and Other Investments 573,011 577,598 Current Assets: Cash and Temporary Cash Investments 533 11,265 Accounts Receivable: Customers 25,730 25,896 Others 2,348 3,800 Accrued Unbilled Revenue 9,158 8,283 Associated Companies 25,861 18,061 Fuel (at average cost) 7,385 6,344 Plant Materials and Operating Supplies (at avg. cost) 3,937 3,300 Prepayments and Other Current Assets 4,170 5,952 Total Current Assets 79,122 82,901 Other Assets (Note A) 87,065 95,546 Total Assets $ 739,198 $ 756,045 LIABILITIES AND CAPITALIZATION Capitalization: Common Equity $ 244,368 $ 225,064 Redeemable Preferred Stock - Net 29,665 29,665 Preferred Stock Redemption Cost (3,447) (4,408) Long-term Debt - Net 222,313 229,224 Total Capitalization 492,899 479,545 Current Liabilities: Long-term Debt Due Within One Year 7,000 35,000 Notes Payable 4,158 Accounts Payable: Public 27,242 24,578 Associated Companies 3,913 5,749 Customer Deposits 1,103 1,101 Taxes Accrued 3,219 1,411 Interest Accrued 4,999 5,486 Other Current Liabilities 7,332 15,259 Total Current Liabilities 58,966 88,584 Deferred Credits: Unamortized Investment Credit 17,842 18,784 Other Deferred Credits 40,725 49,476 Total Deferred Credits 58,567 68,260 Accumulated Deferred Taxes 128,766 119,656 Commitments and Contingencies (Note J) Total Liabilities and Capitalization $ 739,198 $ 756,045 The accompanying notes are an integral part of the financial statements.
Eastern Edison Company and Subsidiary Consolidated Statement of Capitalization December 31, (In Thousands)
1995 1994 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 (43) (43) Retained Earnings 124,878 105,574 Total Common Equity 244,368 225,064 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 (3,447) (4,408) Total Redeemable Preferred Stock 26,218 25,257 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 7,000 7,000 8.90% Secured Medium-Term Notes due 1995 10,000 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 Unsecured Medium-Term Notes: 9-9 1/4% due 1995 - Series A 25,000 Unamortized (Discount) - Net (687) (776) 229,313 264,224 Less Portion Due Within One Year 7,000 35,000 Total Long-Term Debt 222,313 229,224 Total Capitalization $ 492,899 $ 479,545 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, 1995, 1994, and 1993 (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 2.25 to 4.50 percent. Montaup is entitled to the electricity produced from these facilities based on its ownership interests and is billed pursuant to contractual agreements which are approved by FERC. One of the four nuclear generating facilities 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 $10.1 million at December 31, 1995 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. 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 three 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 $133,841,000 in 1995, $126,237,000 in 1994, and $121,447,000 in 1993; accounting, engineering and other services rendered by EUA Service Corporation to Eastern Edison and Montaup of approximately $29,264,000, $27,365,000, and $27,418,000 in 1995, 1994 and 1993, respectively; and operating expense from the rental of transmission and generation facilities by Blackstone and Newport to Montaup aggregating approximately $4,351,000 in 1995, $3,627,000 in 1994, and $2,884,000 in 1993. Montaup rental of transmission facilities to Newport for the years 1995, 1994 and 1993 amounted to zero, $149,000 and $487,000, 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 1995, 1994 and 1993 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, 1995 and 1994 are detailed as follows: (in Thousands) 1995 1994 Regulatory Assets: Unamortized losses on reacquired debt $14,981 $16,693 Unrecovered plant and decommissioning cost 10,100 18,400 Deferred SFAS 109 costs (Note B) 44,387 39,506 Deferred SFAS 106 costs (Note J) 2,365 2,723 Other regulatory assets 4,790 7,280 Total regulatory assets 76,623 84,602 Other deferred charges and assets: Unamortized debt expenses 2,847 3,345 Other 7,595 7,599 Total Other Assets $87,065 $95,546 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 such as "Choice and Competition" 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 9.4% in 1995, 9.6% in 1994 and 9.3% in 1993. 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. Income Taxes: The general policy of Eastern Edison and Montaup with respect to accounting for federal 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. New Accounting Standard: In March 1995, the Financial Accounting Standards Board issued Statement of Financial Accounting Standard No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of" (FAS 121), effective for fiscal year 1996. FAS 121 requires all regulatory assets, assets which were established as a result of high probability of recovery in a regulated environment, to continue to meet that high probability of recovery at each balance sheet date. Based on the current regulatory framework, management does not expect that adoption of this standard will have a material effect on Eastern Edison's financial position or results of operation. However, this assumption may change in the future as changes are made in the current regulatory framework or as competitive factors influence wholesale and retail pricing in the electric utility industry. (B) Income Taxes: Components of income tax expense for the years 1995, 1994, and 1993 are as follows: _________________________________________________________________ (In Thousands) 1995 1994 1993 Federal: Current $11,387 $ 9,143 $11,554 Deferred 3,679 4,697 2,841 Investment Tax Credit, Net (942) (348) (1,016) $14,124 13,492 13,379 State: Current 2,447 1,468 2,359 Deferred (918) 870 207 1,529 2,338 2,566 Charged to Operations 15,653 15,830 15,945 Charged to Other Income: Current 522 617 392 Deferred (67) (67) (67) Total $16,108 $16,380 $16,270 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) 1995 1994 1993 Federal Income Tax Computed at Statutory Rates $17,343 $17,417 $16,580 (Decreases) Increases in Tax from: Equity Component of AFUDC (165) (92) (101) Consolidated Tax Savings (108) (651) (314) Depreciation Differences (264) (321) 851 Amortization and Utilization of ITC (942) (945) (1,066) State Taxes, Net of Federal Income Tax Benefit (2,625) 1,614 1,735 Cost of Removal 58 (226) (273) Other 2,811 (416) (1,142) Total Income Tax Expense $16,108 $16,380 $16,270 (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. At December 31, 1995 and 1994 no valuation allowance was deemed necessary for total deferred tax assets. The total deferred tax assets and liabilities at December 31, 1995 and 1994 are comprised as follows: Deferred Tax Deferred Tax Assets Liabilities ($000) ($000) 1995 1994 1995 1994 Plant Related Plant Related Differences $16,181 $16,221 Differences $146,632 $137,072 Alternative Refinancing Minimum Tax 4,470 4,479 Costs 1,691 1,772 Litigation Provisions 0 795 Pensions 940 1,233 Pensions 1,070 514 Other 1,060 1,866 Other 1,901 3,024 Total $22,781 $23,875 Total $151,164 $143,101 As of December 31, 1995 and 1994, the Company had recorded on its Consolidated Balance Sheet a regulatory liability to ratepayers of approximately $23.6 million and $25.2 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, 1995 and 1994, a regulatory asset of approximately $44.4 million and $39.5 million, respectively, has been recorded, representing the cumulative amount of federal income taxes on temporary depreciation differences which were previously flowed through to ratepayers. Eastern Edison and Montaup have approximately $92,000 and $4.4 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: 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, 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 $120,723,852 as of December 31, 1995 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. 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 1995 are: $7 million in 1996, none in 1997, $60 million in 1998 and none in 1999 and 2000. (G) Lines of Credit: EUA System companies including Eastern Edison maintain short-term lines of credit with various banks aggregating approximately $150 million. At December 31, 1995, unused short-term lines of credit were approximately $111 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 1995, the weighted average interest rate for short-term borrowings by the Company was 6.1%. (H) Jointly Owned Facilities: At December 31, 1995, 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 (dollars in thousands): Accumulated Provision For Net Construc- Utility Depreciation Utility tion Percent Plant in and Plant in Work in Owned Service Amortization Service Progress Montaup: Canal Unit 2 50.00% $ 71,715 $42,657 $29,058 $2,085 Wyman Unit 4 1.96% 4,050 2,020 2,030 Seabrook Unit 1 2.90% 194,735 23,993 170,742 454 Millstone Unit 3 4.01% 178,231 40,482 137,749 42 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, 1995, Montaup's total net investment in nuclear fuel of the Seabrook and Millstone Units amounted to $3.0 million and $2.2 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, 1995 are as follows (dollars in thousands): Carrying Fair Amount Value Cash and Temporary Cash Investments $ 11,265 $ 11,265 Redeemable Preferred Stock 30,000 31,800 Long-Term Debt $ 230,000 $233,292 (J) Commitments and Contingencies: 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 (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 Unit 3 and a 2.9% interest in Seabrook Unit 1. Northeast Utilities, the operator of the units, indicates that Millstone Unit 3 has sufficient on-site storage facilities which with rack additions can accommodate its spent fuel for the projected life of the unit. At the Seabrook Project, there is on-site storage capacity which, with rack additions, will be sufficient to at least the year 2011. The Energy Policy Act 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 Unit 3 and Seabrook Unit 1. Montaup's share of the current estimate of total costs to decommission Millstone Unit 3 is $19.2 million in 1995 dollars, and Seabrook Unit 1 is $12.5 million in 1995 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 non-contributory defined benefit pension plans 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. Net pension expense (income) for the Retirement Plan, including amounts related to the 1995 voluntary retirement incentive, was $632,566 in 1995, $249,858 in 1994 and $(326,517) in 1993 and included the following components: 1995 1994 1993 Service cost - benefits earned during the period $ 1,503,804 $ 1,783,085 $ 1,414,382 Interest cost on projected benefit obligation 5,574,660 5,217,393 5,133,080 Actual loss (return) on assets (22,158,215) 926,980 (10,891,951) Net amortization and deferrals 14,855,399 (7,677,600) 4,017,972 Net periodic pension (income) expense $ (224,352) $ 249,858 $ ( 326,517) Voluntary retirement incentive 856,918 Total periodic pension expense (income) $ 632,566 $ 249,858 $ (326,517) ========= ======== ========= Assumptions used to determine pension cost: 1995 1994 1993 Discount Rate 8.25% 7.25% 8.75% Compensation Increase Rate 4.75% 4.75% 6.00% Long-Term Return on Assets 9.50% 9.50% 10.00% The discount rate and compensation increase rate used to determine pension costs were changed effective January 1, 1996 to 7.25% and 4.25%, respectively. 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, 1995, approximately $449,000 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 three years ended December 31, 1995, 1994 and 1993 expenses related to the supplemental plan were approximately $825,000, $266,000, and $1.3 million, respectively. 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 $4.0 million in 1995, $3.4 million in 1994 and $3.4 million in 1993. The total cost of Post-Retirement Benefits other than Pensions for 1995, 1994 and 1993 includes the following components (in thousands): 1995 1994 1993 Service cost $ 565 $ 880 $ 767 Interest cost 2,926 3,252 3,556 Actual return on plan assets (388) (75) (41) Amortization of transition obligation 1,965 2,026 2,040 Net other amortization & deferrals (632) (50) (40) Net periodic post-retirement benefit costs 4,436 6,033 6,282 Voluntary retirement incentive 470 Total post-retirement benefit costs $ 4,906 $6,033 $6,282 Assumptions Discount rate 8.25% 7.25% 8.75% Health care cost trend rate-near-term 11.00% 13.00% 13.00% -long-term 5.00% 5.00% 6.25% Compensation increase rate 4.75% 4.75% 6.00% Rate of return on plan assets-union 8.50% 8.50% 8.50% - non-union 5.50% 5.50% 5.50% Reconciliation of funded status: 1995 1994 1993 Accumulated post-retirement benefit obligation (APBO): Retirees $(23,223) $(20,227) $(20,556) Active employee fully eligible for benefits (3,649) (4,116) (7,669) Other active employees (7,711) (9,255) (9,488) Total (34,583) (33,598) (37,713) Fair Value of assets (primarily notes and bonds) 3,830 2,169 747 Unrecognized transition obligation 27,726 30,007 31,674 Unrecognized net (gain) loss (2,142) (3,158) 2,597 (Accrued)/prepaid post-retirement benefit cost $ (5,169) $ (4,580) $ (2,695) The discount rate and compensation increase rate used to determine post- retirement benefit costs were changed effective January 1, 1996, to 7.25% and 4.25%, respectively and were used to calculate the funded status of Post- Retirement Benefits at December 31, 1995. Increasing the assumed health care cost trend rate by 1% each year would increase the total post-retirement benefit cost for 1995 by approximately $478,000 and increase the total accumulated post-retirement benefit obligation by approximately $3.7 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 totaling approximately $3.2 million and $2.9 million were made during 1995 and 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, 1995, the aggregate annual minimum commitments for such contracts are approximately $129 million in 1996 and 1997, $128 million in 1998, $127 million in 1999, $123 million in 2000 and will aggregate $1.4 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: 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 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, 1995, Eastern Edison and Montaup have incurred costs of approximately $500,000 in connection with the foregoing environmental matters and estimate that additional expenditures may be incurred through 1997 up to $500,000. 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 1997 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 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 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 oxides of nitrogen 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 DEP 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 oxides of nitrogen. 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 nitrogen oxide. 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 of the 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. 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. There is a bill pending in the Massachusetts legislature that would authorize the MDPU to examine the potential health effects of EMF. Management cannot predict the impact, if any, which legislation or other developments concerning EMF may have on Eastern Edison or Montaup. 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 $5.2 million of the outstanding debt of these two companies. In addition, Montaup has a minimum rental commitment which totals approximately $13.5 million under a noncancellable transmission facilities support agreement for years subsequent to 1995. Other In December 1992, Montaup commenced a declaratory judgment action in which it sought to have the Massachusetts Superior Court determine its rights under the Power Purchase Agreement between it and Aquidneck Power Limited Partnership (Aquidneck). In April 1995, Montaup filed a motion for summary judgement, and in June 1995, the court granted Montaup's motion. In July, Aquidneck filed for appeal of the court's decision. Montaup, EUA and EUA Service intend to vigorously contest the appeal and continue to believe that Aquidneck's claims have no basis in law. Report of Independent Accountants To the Directors and Shareholder of Eastern Edison Company and Subsidiary: We have audited the accompanying consolidated balance sheets and consolidated statement of capitalization of Eastern Edison Company and its subsidiary (the Company) as of December 31, 1995 and 1994, and the related consolidated statements of income, retained earnings and cash flows for each of the three years in the period ended December 31, 1995. 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, 1995 and 1994, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1995 in conformity with generally accepted accounting principles. Coopers & Lybrand L.L.P. Boston, Massachusetts March 5, 1996 EX-23 12 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, 1996, on our audits of the consolidated financial statements and financial statement schedule of Eastern Utilities Associates and subsidiaries as of December 31, 1995 and 1994, and for the years ended December 31, 1995, 1994 and 1993, which reports are incorporated by reference or included in this Annual Report on Form 10-K. /s/Coopers & Lybrand L.L.P. Coopers & Lybrand L.L.P. Boston, Massachusetts March 19, 1996 EX-27 13 EUA FDS
UT 0000031224 EASTERN UTILITIES ASSOCIATES 1000 12-MOS DEC-31-1995 DEC-31-1995 PER-BOOK 721086 219714 135419 124054 0 1200273 102184 216817 56228 375229 26218 6937 434871 39540 0 0 19506 50 0 0 297922 1200273 563363 17015 474620 491635 71728 4677 76405 41458 34947 2321 32626 32050 38216 112963 1.61 0
EX-27 14 BVE FDS
UT 0000012473 BLACKSTONE VALLEY ELECTRIC COMPANY 1000 12-MOS DEC-31-1995 DEC-31-1995 PER-BOOK 88480 47 19833 15618 0 123978 9203 17908 9934 37045 0 6130 36500 1259 0 0 1500 0 0 0 41544 123978 140861 2347 130177 132524 8337 (5) 8332 4034 4298 289 4009 4144 3481 10019 0 0
EX-27 15 EECO FDS
UT 0000014407 EASTERN EDISON COMPANY 1000 12-MOS DEC-31-1995 DEC-31-1995 PER-BOOK 557033 15978 79122 87065 0 739198 72284 47206 124878 244368 26218 0 222313 4158 0 0 7000 0 0 0 235141 739198 420069 15653 352184 367837 52232 2526 54758 21315 33443 1988 31455 11190 18277 56711 0 0
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