-----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, RCNQWzWsExFpvOkPaft0jDOvJRqzCWfRO13PIPhiyq5i+oR6lw9SoRPg+NQAx0Kg A5VrQ+iAvSD9RYkLt2XW+g== 0000072741-96-000049.txt : 19960315 0000072741-96-000049.hdr.sgml : 19960315 ACCESSION NUMBER: 0000072741-96-000049 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 26 CONFORMED PERIOD OF REPORT: 19951231 FILED AS OF DATE: 19960314 SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: NORTHEAST UTILITIES CENTRAL INDEX KEY: 0000072741 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 042147929 STATE OF INCORPORATION: MA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-05324 FILM NUMBER: 96534650 BUSINESS ADDRESS: STREET 1: 174 BRUSH HILL AVE CITY: WEST SPRINGFIELD STATE: MA ZIP: 01090-0010 BUSINESS PHONE: 2036655000 MAIL ADDRESS: STREET 1: 107 SELDON ST CITY: BERLIN STATE: CT ZIP: 06037-1616 FILER: COMPANY DATA: COMPANY CONFORMED NAME: CONNECTICUT LIGHT & POWER CO CENTRAL INDEX KEY: 0000023426 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 060303850 STATE OF INCORPORATION: CT FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-11419 FILM NUMBER: 96534651 BUSINESS ADDRESS: STREET 1: 707 SELDEN ST CITY: BERLIN STATE: CT ZIP: 06037-1616 BUSINESS PHONE: 2036655000 FILER: COMPANY DATA: COMPANY CONFORMED NAME: WESTERN MASSACHUSETTS ELECTRIC CO CENTRAL INDEX KEY: 0000106170 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 041961130 STATE OF INCORPORATION: MA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 000-07624 FILM NUMBER: 96534652 BUSINESS ADDRESS: STREET 1: 174 BRUSH HILL AVE CITY: WEST SPRINGFIELD STATE: MA ZIP: 01090 BUSINESS PHONE: 4137855871 MAIL ADDRESS: STREET 1: 107 SELDON ST CITY: BERLIN STATE: CT ZIP: 06037-1616 FILER: COMPANY DATA: COMPANY CONFORMED NAME: PUBLIC SERVICE CO OF NEW HAMPSHIRE CENTRAL INDEX KEY: 0000315256 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 020181050 STATE OF INCORPORATION: NH FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-06392 FILM NUMBER: 96534653 BUSINESS ADDRESS: STREET 1: 1000 ELM ST CITY: MANCHESTER STATE: NH ZIP: 03105 BUSINESS PHONE: 6036694000 MAIL ADDRESS: STREET 1: 107 SELDON ST CITY: BERLIN STATE: CT ZIP: 06037-1616 FILER: COMPANY DATA: COMPANY CONFORMED NAME: NORTH ATLANTIC ENERGY CORP /NH CENTRAL INDEX KEY: 0000880416 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 061339460 STATE OF INCORPORATION: NH FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 033-43508 FILM NUMBER: 96534654 BUSINESS ADDRESS: STREET 1: 1000 ELM ST CITY: MANCHESTER STATE: NH ZIP: 03105 BUSINESS PHONE: 6036694000 MAIL ADDRESS: STREET 1: 107SELDEN ST CITY: BERLIN STATE: CT ZIP: 06037-1616 10-K 1 NORTHEAST UTILITIES AND SUBS - FORM 10-K NORTHEAST UTILITIES THE CONNECTICUT LIGHT AND POWER COMPANY PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE WESTERN MASSACHUSETTS ELECTRIC COMPANY NORTH ATLANTIC ENERGY CORPORATION 1995 Form 10-K Annual Report Table of Contents PART I Page Item 1. Business............................................... 1 The Northeast Utilities System.............................. 1 Public Utility Regulation................................... 2 Competition and Marketing................................... 3 Competition and Cost Recovery.......................... 3 Retail Marketing....................................... 4 Wholesale Marketing.................................... 5 Rates....................................................... 7 Connecticut Retail Rates............................... 7 New Hampshire Retail Rates............................. 9 Massachusetts Retail Rates............................. 14 Resource Plans.............................................. 16 Construction........................................... 16 Future Needs........................................... 17 Financing Program........................................... 17 1995 Financings........................................ 17 1996 Financing Requirements............................ 18 1996 Financing Plans................................... 18 Financing Limitations.................................. 19 Electric Operations......................................... 22 Distribution and Load.................................. 22 Regional and System Coordination....................... 25 Transmission Access.................................... 26 Fossil Fuels........................................... 26 Nuclear Generation..................................... 27 Nonutility Businesses....................................... 38 Private Power Development.............................. 38 Energy Management Services............................. 39 Regulatory and Environmental Matters........................ 39 Environmental Regulation............................... 39 Electric and Magnetic Fields........................... 48 FERC Hydro Project Licensing........................... 49 Employees................................................... 49 Item 2. Properties............................................. 51 Item 3. Legal Proceedings...................................... 56 Item 4. Submission of Matters to a Vote of Security Holders.... 61 PART II Item 5. Market for Registrants' Common Equity and Related Shareholder Matters.................................... 61 Item 6. Selected Financial Data................................ 61 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.................... 62 Item 8. Financial Statements and Supplementary Data............ 62 Item 9. Changes in Disagreements with Accountants on Accounting and Financial Disclosure.................... 63 PART III Item 10. Directors and Executive Officers of the Registrants.... 64 Item 11. Executive Compensation................................. 68 Item 12. Security Ownership of Certain Beneficial Owners and Management............................................. 73 Item 13. Certain Relationships and Related Transactions......... 76 PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.................................... 77 GLOSSARY OF TERMS The following is a glossary of frequently used abbreviations or acronyms that are found throughout this report: NU............................ Northeast Utilities CL&P.......................... The Connecticut Light and Power ompany Charter Oak................... Charter Oak Energy, Inc. WMECO......................... Western Massachusetts Electric Company HWP........................... Holyoke Water Power Company NUSCO or the Service Company.. Northeast Utilities Service Company NNECO......................... Northeast Nuclear Energy Company NAEC.......................... North Atlantic Energy Corporation NAESCO or North Atlantic...... North Atlantic Energy Service Corporation PSNH.......................... Public Service Company of New Hampshire RRR........................... The Rocky River Realty Company HEC........................... HEC Inc. Quinnehtuk.................... The Quinnehtuk Company the System.................... The Northeast Utilities System CYAPC......................... Connecticut Yankee Atomic Power Company MYAPC......................... Maine Yankee Atomic Power Company VYNPC......................... Vermont Yankee Nuclear Power Corporation YAEC.......................... Yankee Atomic Electric Company the Yankee Companies.......... CYAPC, MYAPC, VYNPC, and YAEC GENERATING UNITS Millstone 1................... Millstone Unit No. 1, a 660-MW nuclear generating unit completed in 1970 Millstone 2................... Millstone Unit No. 2, an 870-MW nuclear electric generating unit completed in 1975 Millstone 3................... Millstone Unit No. 3, a 1,154-MW nuclear electric generating unit completed in 1986 Seabrook or Seabrook 1........ Seabrook Unit No. 1, a 1,148-MW nuclear electric generating unit completed in 1986. Seabrook 1 went into service in 1990. REGULATORS DOE........................... U.S. Department of Energy DPU........................... Massachusetts Department of Public Utilities DPUC.......................... Connecticut Department of Public Utility Control MDEP.......................... Massachusetts Department of Environmental Protection CDEP.......................... Connecticut Department of Environmental Protection EPA........................... U.S. Environmental Protection Agency FERC.......................... Federal Energy Regulatory Commission NHDES......................... New Hampshire Department of Environmental Services NHPUC......................... New Hampshire Public Utilities Commission NRC........................... Nuclear Regulatory Commission SEC........................... Securities and Exchange Commission Other 1935 Act...................... Public Utility Holding Company Act of 1935 CAAA.......................... Clean Air Act Amendments of 1990 DSM........................... Demand-Side Management Energy Policy Act............. Energy Policy Act of 1992 EWG........................... Exempt wholesale generator FAC........................... Fuel adjustment clause FPPAC......................... Fuel and purchased power adjustment clause (PSNH) FUCO.......................... Foreign utility company GUAC.......................... Generation utilization adjustment clause (CL&P) IRM........................... Integrated resource management kWh........................... Kilowatt-hour MW............................ Megawatt NBFT.......................... Niantic Bay Fuel Trust, lessor of nuclear fuel used by CL&P and WMECO NEPOOL........................ New England Power Pool NUGs.......................... Nonutility generators NUG&T......................... Northeast Utilities Generation and Transmission Agreement QF............................ Qualifying facility NORTHEAST UTILITIES THE CONNECTICUT LIGHT AND POWER COMPANY PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE WESTERN MASSACHUSETTS ELECTRIC COMPANY NORTH ATLANTIC ENERGY CORPORATION PART I ITEM 1. BUSINESS THE NORTHEAST UTILITIES SYSTEM Northeast Utilities (NU) is the parent company of the Northeast Utilities system (the System). NU is not an operating company. The System furnishes retail electric service in Connecticut, New Hampshire and western Massachusetts through four of NU's wholly owned subsidiaries (The Connecticut Light and Power Company [CL&P], Public Service Company of New Hampshire [PSNH], Western Massachusetts Electric Company [WMECO] and Holyoke Water Power Company [HWP]). In addition to their retail electric service, CL&P, PSNH, WMECO and HWP (including its wholly owned subsidiary, Holyoke Power and Electric Company [HPE]) (the System companies) together furnish firm wholesale electric service to five municipal electric systems and one investor-owned utility. The System companies also supply other wholesale electric services to various municipalities and other utilities. The System serves about 30 percent of New England's electric needs and is one of the 20 largest electric utility systems in the country as measured by revenues. North Atlantic Energy Corporation (NAEC) is a special-purpose subsidiary of NU that owns a 35.98 percent interest in the Seabrook nuclear generating facility (Seabrook) in Seabrook, New Hampshire and sells its share of the capacity and output from Seabrook to PSNH under two life-of-unit, full-cost recovery contracts. Several wholly owned subsidiaries of NU provide support services for the System companies and, in some cases, for other New England utilities. Northeast Utilities Service Company (NUSCO) provides centralized accounting, administrative, information resources, engineering, financial, legal, operational, planning, purchasing and other services to the System companies. North Atlantic Energy Service Corporation (NAESCO) has operational responsibility for Seabrook. Northeast Nuclear Energy Company (NNECO) acts as agent for the System companies and other New England utilities in operating the Millstone nuclear generating facilities in Connecticut. Three other subsidiaries construct, acquire or lease some of the property and facilities used by the System companies. NU has two other principal subsidiaries, Charter Oak Energy, Inc. (Charter Oak) and HEC Inc. (HEC), which have nonutility businesses. Directly and through subsidiaries, Charter Oak develops and invests in cogeneration, small- power production and other forms of nonutility generation and in exempt wholesale generators (EWGs)(collectively, NUGs) and foreign utility companies (FUCOs) as permitted under the Energy Policy Act of 1992 (Energy Policy Act). HEC provides energy management services for the System's commercial, industrial and institutional electric customers and others. See "Nonutility Businesses." NU is functionally organized into two core business groups. The first group, the Energy Resources Group, is devoted to energy resource acquisition, nuclear, fossil and hydroelectric generation and wholesale marketing. The second group, the Retail Business Group, oversees all customer service, transmission and distribution operations and retail marketing in Connecticut, New Hampshire and Massachusetts. These two core business groups receive services from various support functions known collectively as the Corporate Center. PUBLIC UTILITY REGULATION The System is regulated by various federal and state agencies. NU is regulated as a registered electric utility holding company under the Public Utility Holding Company Act of 1935 (1935 Act). Accordingly, the Securities and Exchange Commission (SEC) has jurisdiction over NU and its subsidiaries with respect to, among other things, securities issues, sales and acquisitions of securities and utility assets, intercompany loans, services performed by and for associated companies, certain accounts and records, involvement in nonutility operations and dividends. The 1935 Act limits the System, with certain exceptions, to the business of being an electric utility in the Northeastern region of the country. In 1995, the staff of the SEC recommended "conditional repeal" of the 1935 Act and substantial loosening of rules presently restricting NU's capital-raising and diversification activities. In 1995, a bill was introduced in the United States Senate to repeal the 1935 Act. To date these proposals have not been acted on. The System companies are also subject to the Federal Power Act as administered by the Federal Energy Regulatory Commission (FERC). FERC regulates the wholesale power sales and interstate transmission service of the System. The Energy Policy Act amended the Federal Power Act to authorize FERC to order wholesale transmission wheeling services and under certain circumstances to require electric utilities to enlarge transmission capacity necessary to provide such services. FERC's authority to order wheeling does not extend to retail wheeling, and FERC may not issue a wheeling order that is inconsistent with state laws governing the retail marketing areas of electric utilities. For more information regarding retail wheeling, see "Competition and Marketing-Retail Marketing" and "Rates." The Nuclear Regulatory Commission (NRC) has broad jurisdiction over the System's nuclear units. Each of the System companies is subject to broad regulation by its respective state and/or local regulatory authorities with jurisdiction over the service areas in which each company operates. For more information regarding recent NRC actions taken with respect to the System's nuclear units, including the recent designation of Millstone Station on the NRC's watch list, see "Electric Operations-Nuclear Generation-Nuclear Plant Performance." The System incurs substantial capital expenditures and operating expenses to identify and comply with environmental, energy, licensing and other regulatory requirements, including those described herein, and it expects to incur additional costs to satisfy further requirements in these and other areas of regulation. For more information regarding specific regulatory actions and proceedings, see generally "Rates," "Electric Operations" and "Regulatory and Environmental Matters." COMPETITION AND MARKETING COMPETITION AND COST RECOVERY Competition in the energy industry continues to grow as a result of legislative and regulatory action, surplus generating capacity, technological advances, relatively high prices in certain regions of the country, including New England, and the increased availability of natural gas. A major risk of competition for many utilities, including the System, is "strandable costs." These are costs that have been incurred by utilities in the past to meet their public service obligations, with the expectation that they would be recovered from customers in the future, and yet under certain circumstances might not be recoverable from customers in a fully competitive electric utility industry. The System's exposure to the risk of strandable costs is primarily based on: (i) the System's relatively high investment in nuclear generating capacity, which has a high initial cost to build; (ii) state-mandated purchased-power arrangements priced above market and (iii) significant regulatory assets, which are those costs (including purchased-power costs) that have been deferred by state regulators for future collection from customers. As of December 31, 1995, the System's regulatory assets totaled approximately $2 billion. The System expects to recover substantially all of its regulatory assets from customers, and unless amortization is changed from currently scheduled rates, the System's regulatory assets are expected to be substantially decreased in the next five years. There are many contingencies, however, that may affect the System's ability to recover strandable costs, including the results of various electric utility restructuring initiatives in the System's service territory and the uncertainty of future rate schedules for CL&P, WMECO and PSNH. In 1995, regulators in both Connecticut and Massachusetts concluded that electric utilities should be allowed a reasonable opportunity to recover strandable costs. There has been no such finding in New Hampshire; however, on February 22, 1996, PSNH and the staff of the New Hampshire Public Utilities Commission (NHPUC) reached an agreement, subject to further approvals, on a limited, retail wheeling program under which PSNH would recover all of its strandable costs allocable to this program. The System believes that its assets would be worth more than their net depreciated value if all segments of the industry, not only generation, were to be deregulated and become competitive. These assets could include the transmission and distribution system and much of the System's coal-fired and hydroelectric generation. The worst case scenario for the System would be for a rapid movement to an openly competitive market on terms such that all of its strandable costs cannot be recovered with little opportunity to realize the true value of below-market assets if such assets remain subject to traditional regulation. The System cannot predict at this time what will be the ultimate result of the various legislative and regulatory restructuring initiatives. Competitive forces in the utility industry also create a risk that customers may choose alternative energy suppliers or relocate outside of the System's service territory. In response, the System has developed, and is continuing to develop, a number of marketing initiatives to retain and continue to serve its existing customers. In late 1994 the System began a reengineering process, which is ongoing, to become more competitive while improving customer service and maintaining a high level of operational performance. The System's strandable cost risk and exposure to revenue loss from competitive forces are somewhat mitigated by a diverse customer retail base and lack of significant dependence on any one retail customer or industry. RETAIL MARKETING The System companies continue to operate predominantly in state-approved franchise territories under traditional cost-of-service regulation. Retail wheeling, under which a retail customer would be permitted to select an electricity supplier other than its local electric utility and require the local electric utility to transmit the power to the customer's site, is not generally required in any of the System's jurisdictions. Emphasis on developing approaches to deregulation, however, is growing nationwide. For additional information regarding retail wheeling and electric industry restructuring initiatives in the System's service territory, see "Rates." While retail wheeling is not yet generally required in the System's retail service territory, competitive forces nonetheless are influencing retail pricing. The System companies have been devoting increasing attention in recent years to negotiating long-term power supply arrangements with certain retail customers. Such arrangements are offered to customers who require an incentive to locate or expand their operations in the System's service territory, are considering leaving or reducing operations in the service territory, are facing short-term financial problems or are considering generating their own electricity. Approximately 6 percent of the System's retail revenues were under negotiated rate agreements at the end of 1995, up from 4 percent at the end of 1994. In 1995, those negotiated rate reductions amounted to approximately $35 million, up from $20 million in 1994. CL&P accounted for approximately $19 million of the 1995 rate reductions, PSNH for $7.5 million, WMECO for $7 million and HWP for $1.5 million. Management believes that the level of contractual rate reductions is likely to increase further in 1996, but that these agreements provide long-term benefits to the System by helping to stabilize retail revenues and attract additional retail load to its service territory. Currently, the costs of providing these discounts are borne by NU shareholders through reduced earnings prior to rate changes in the System's various jurisdictions. The System companies may request that such costs be shared by their customers during subsequent rate proceedings. Regulators in both Connecticut and New Hampshire took steps in 1995 that allowed electric utilities additional flexibility in negotiating special rate agreements with electric customers. In March 1995, the Connecticut Department of Public Utility Control (DPUC) approved new guidelines for CL&P's general rate riders that (i) allow CL&P to enter into special rate agreements of up to ten years with eligible customers, (ii) expand the eligibility for such rate agreements, (iii) authorize CL&P to provide additional services instead of rate concessions and (iv) lower the minimum pricing for such rate agreements. The Connecticut Consumer Counsel (CCC) appealed the DPUC's decision to the Connecticut Superior Court in May 1995, and the matter is pending. Previously, agreements with existing customers that were longer than five years had to be individually approved by the DPUC. CL&P's ten-year agreement with Pratt & Whitney, CL&P's largest industrial customer, was approved by the DPUC in June 1995 under the DPUC's previous rules. In November 1995, the NHPUC issued guidelines permitting electric utilities to offer economic development and business retention rates. On February 23, 1996, the NHPUC issued an order accepting a package of rates submitted by PSNH that would result in rate reductions of up to 20 percent for existing manufacturers, who may close their business or move out of the state, and up to 30 percent for manufacturers creating new or expanded electric load. The order, however, includes a condition that prevents PSNH from recovering from other customers the difference between the economic development rates and full tariff rates, which would have the effect of PSNH losing money on each sale. As a result, PSNH will seek reconsideration by the NHPUC before deciding whether to offer an economic development rate. The order does not include the same restriction for business retention rates, and therefore, PSNH will proceed with the necessary tariff filings to offer these rates. In 1994, the Massachusetts Department of Public Utilities (DPU) authorized WMECO to reduce rates by 5 percent for all customers whose demand exceeds one megawatt (MW) as long as those customers agree to give WMECO at least five years notice before generating their own power or purchasing it from an alternative supplier. The DPU also permits WMECO to offer specified discounts with a five- year term to attract new businesses and encourage business expansion in the state. The DPU must approve all other special rate agreements individually. Demand-side management (DSM) programs are also used by the System to make its customers more efficient and viable employers in its service territory. The System companies expect to spend approximately $50 million in 1996 on DSM programs. These programs help customers improve the efficiency of their electric lighting, manufacturing and heating, ventilating and air conditioning systems. DSM program costs are recovered from customers through various cost recovery mechanisms. For further information on the System's DSM programs, see "Rates." The System is continuing to expand its Retail Marketing organization to provide better customer service. Beginning in 1996, the System expects to devote significantly more resources to its retail marketing efforts. Much of the increased spending will be for developing new energy-related products and services and investing in technology that will be used to support new initiatives. WHOLESALE MARKETING The System acts as both a buyer and a seller of electricity in the highly competitive wholesale electricity market in the Northeastern United States (Northeast). Because economic growth in this region has been modest since 1989 and because many new sources of power have become operational since that time, a significant surplus of generating capacity currently exists in New England and New York. As a result, wholesale electricity pricing is now significantly lower than it was in the late 1980s. As a result of the continued expiration of some older, higher priced contracts, the System's wholesale revenues decreased to $303 million in 1995 from $331 million in 1994. Over the same period, sales of energy declined from 9.12 billion kilowatt-hours (KWh) in 1994 to 8.72 billion KWh in 1995. As a result of new contracts entered into in recent years, wholesale revenues in 1996 are expected to be comparable in amount to 1995. The System's most important wholesale market at this time remains New England. Of the $303 million in total 1995 wholesale revenues, approximately $280 million came from sales to investor-owned, cooperative and municipal utilities in New England. Because most investor-owned utilities in New England have surplus generation, sales to those utilities have declined in recent years while sales to municipal utilities have increased. In 1995, revenues from sales to one new municipal customer, Madison Electric Works in Madison, Maine, were approximately $7 million. That load is expected to grow in the coming years as a paper company in Madison expands its operations. The largest cooperative served by the System is the Connecticut Municipal Electric Energy Cooperative (CMEEC), which accounted for $71 million of wholesale revenues in 1995. Half of those sales resulted from a new ten-year agreement signed in January 1995 under which CMEEC buys power from CL&P on behalf of the Town of Wallingford, Connecticut. The contract price includes amortization of a lump sum payment to CL&P for early termination of a prior agreement with Wallingford directly for a comparable amount of System power sales. In 1995, the System also had sales of $52 million to the New Hampshire Electric Cooperative (NHEC), approximately 90 percent of PSNH's wholesale revenues. NHEC is a party to a full-requirements power supply agreement with PSNH that cannot be terminated by its terms prior to November 1, 2006. In 1995, PSNH filed a complaint against NHEC with FERC challenging NHEC's decision to take bids on 20 megawatts (MW) of power, representing 14 percent of NHEC's total load, from qualifying facilities (QFs) to replace a comparable amount of capacity from PSNH supplied under the power supply agreement. PSNH believes that the solicitation of such bids violated the terms of its power supply agreement. That complaint is still pending at FERC and NHEC has not yet accepted any bids from new suppliers. The System's second-largest wholesale market is New York State. In 1995, the System's sales to utilities in New York accounted for $14 million of revenues. Also in 1995, the Suffolk County Electric Agency announced that the System had won 200 MW of a 300-MW bid to provide base-load generation to customers in Suffolk County, Long Island. This contract, however, is subject to FERC approval and could be contested by other parties. Accordingly, it is unclear whether or when that contract will take effect. The System also plans to expand its wholesale market through electric brokering activities and wholesale sales at market-based rates. On August 18, 1995, CL&P, PSNH, WMECO, NAEC and NUSCO received an order from the SEC under the 1935 Act allowing them to engage in electric brokering and marketing activities primarily throughout New England, New York, Pennsylvania, New Jersey and Maryland with both interconnected and remote parties. This order will allow the companies to arrange to both broker or buy and sell electricity from owned and contracted sources outside the System's retail service area. To date, the System has not received approval from FERC permitting it to sell power outside of New England at market-based rates. The System's transmission system is an open-access wholesale transmission system: other parties, either utilities or independent power producers, can use NU's transmission system to move power from a seller to a wholesale buyer at FERC-approved rates, provided adequate capacity across those lines is available and service reliability is not endangered. See "Electric Operations- Transmission Access" for further information on pending FERC proceedings relating to the System's transmission tariffs. RATES CONNECTICUT RETAIL RATES GENERAL CL&P's retail rates are subject to the jurisdiction of the DPUC. Connecticut law provides that revised rates may not be put into effect without the prior approval of the DPUC. Connecticut law also authorizes the DPUC to order a rate reduction under certain circumstances before holding a full-scale rate proceeding. The DPUC is further required to review a utility's rates every four years if there has not been a rate proceeding during such period. The DPUC issued a decision in CL&P's most recent rate case in June 1993 (1993 Decision) approving a multi-year rate plan that provided for annual retail rate increases of $46.0 million, or 2.01 percent, in July 1993, $47.1 million, or 2.04 percent, in July 1994 and $48.2 million, or 2.06 percent, in July 1995. These rate increases were implemented as scheduled. CL&P's rates in place as of July 1995 will remain in effect after July 1, 1996 unless a rate change is approved by the DPUC. For more information regarding the 1993 Decision, see "Item 3. Legal Proceedings." ELECTRIC INDUSTRY RESTRUCTURING IN CONNECTICUT Throughout the first half of 1995, the DPUC conducted a generic proceeding studying the restructuring of the electric industry and competition in order to develop findings and recommendations to be presented to legislative policymakers. In March 1995, as part of this proceeding, CL&P introduced its plan, entitled "Path to a Competitive Future," for the future of the electric industry and related regulation in Connecticut. The plan calls for full recovery of all existing plant and regulatory assets and a fully competitive market for electricity by approximately 2003. On July 14, 1995, the DPUC issued its final decision in this proceeding. The decision stressed the importance of retaining the benefits of the existing electric system, which it described as the "least costly and most reliable in the world." One key conclusion was that retail access could result in benefits to customers under certain circumstances, but addressing the many transition issues must precede such access. In addition, the decision concluded that utilities are entitled to a reasonable opportunity to recover costs potentially strandable by the evolution toward competitive markets. The decision did not specify any particular time-frame for competition. In February 1996, the Connecticut Legislative Task Force for restructuring the electric industry issued its interim report to the legislature. The report broadly establishes certain restructuring goals, including lowering electric prices (possibly through, among other things, a reduction in the gross earnings tax on electric revenues) and assuring reliable electric service to all customers. A final report to the legislature is due by January 1, 1997. CL&P ADJUSTMENT CLAUSES CL&P has a fossil fuel adjustment clause (FAC) which adjusts retail rates for changes in the price of fossil fuel reflected in base rates. If the price of fossil fuel increases above the level reflected in base rates, CL&P can recover the amount of the increase from retail customers on a current basis, subject to periodic review by the DPUC. Conversely, if the price of fossil fuel decreases below the level reflected in base rates, CL&P must credit the amount of the decrease on a current basis to its customers through the FAC. The FAC also adjusts retail rates for the costs of power purchased from third parties, including NUGs. On December 28, 1995, the DPUC approved, in significant part, CL&P's request to exclude from the calculation of the FAC rate both the fuel costs and the KWh sales of CL&P's firm and non-firm wholesale sales, thus neutralizing the effect of these sales on the fuel clause and eliminating a critical disincentive to making such sales. CL&P's current retail rates also assume that the nuclear units in which CL&P has entitlements will operate at a 72 percent composite capacity factor. A generation utilization adjustment clause (GUAC) levels the effect on rates of fuel costs incurred or avoided due to variations in nuclear generation above and below that performance level. Because nuclear fuel is less expensive than any other fuel utilized by the System, when actual nuclear performance is above the specified level, net fuel costs are lower than the costs reflected in base rates and when nuclear performance is below the specified level, net fuel costs are higher than the costs reflected in base rates. At the end of each 12-month period ending July 31, these net variations from the costs reflected in base rates are, with DPUC approval, generally refunded to or collected from customers over the subsequent 12-month period beginning September 1. For the 1992-1993 and 1993-1994 GUAC periods, the DPUC issued decisions that disallowed $7.9 million and $7.8 million, respectively, of the GUAC deferrals accrued during these periods, finding that CL&P had overrecovered those amounts through base rate fuel recoveries. CL&P appealed both of these decisions and prevailed in the Connecticut Superior Court. The DPUC and other parties then appealed that court's decisions to the Connecticut Supreme Court. Oral argument before the Supreme Court will be held in the Spring of 1996. On January 17, 1995, the DPUC issued a decision that allowed CL&P to continue to recover $80 million of the GUAC costs for the 1994-95 GUAC period (net of $19 million of asserted base fuel overrecoveries for the period) over an 18-month period (instead of the usual 12 months) beginning in September 1995. CL&P has appealed the $19 million that was set aside from its allowed recovery and will seek to join its appeal on this decision to the appeals currently pending before the Connecticut Supreme Court. The DPUC's decision on the 1994- 1995 GUAC period is also subject to the results of prudence reviews of the extended 1994-1995 outage at Millstone 2 and another 1994 Millstone 2 outage discussed below. For additional information regarding recent nuclear outages, see "Electric Operations-Nuclear Generation-Nuclear Plant Performance." In August 1995, the DPUC began investigating the adoption of a fuel clause designed to track and recover all costs of energy incurred to serve customers, which would supersede the current FAC and GUAC. A final decision is scheduled for April 1996. The DPUC has conducted several reviews to examine the prudence of certain costs, including purchased-power costs, incurred in connection with outages at various nuclear units located in Connecticut, that occurred during the period July 1991 to February 1992. Three of these prudence reviews are still pending at the DPUC. Approximately $92 million of costs are at issue in these remaining cases. Management believes its actions with respect to these outages have been prudent and does not expect the outcome of the appeals to result in material disallowances. On April 10, 1995, the DPUC initiated a proceeding to investigate the prudence of an extended outage at Millstone 2, which ended on June 18, 1994, involving the repair of damage to a reactor coolant pump. Approximately $13 million of replacement power costs related to the outage are at issue in this proceeding. Hearings in this proceeding are expected to begin in March 1996. DEMAND-SIDE MANAGEMENT CL&P participates in a collaborative process for the development and implementation of DSM programs for its residential, commercial and industrial customers. CL&P is allowed to recover DSM costs in excess of costs reflected in base rates over periods ranging from approximately four to ten years. On April 12, 1995, the DPUC issued an order approving CL&P's budget of $36.7 million for 1995 DSM expenditures and an amortization period for new expenditures of approximately four years. On October 3, 1995, CL&P filed its 1996-1997 DSM programs and budgets with the DPUC. CL&P proposed a budget level of $37.1 million for 1996 DSM expenditures and an amortization period for new expenditures of approximately 2.4 years. CL&P's unrecovered DSM costs at December 31, 1995, excluding carrying costs, which are collected currently, were approximately $117 million. NEW HAMPSHIRE RETAIL RATES GENERAL PSNH's 1989 Rate Agreement (Rate Agreement) with the state of New Hampshire provides for seven base rate increases of 5.5 percent per year beginning in 1990 and a comprehensive fuel and purchased power adjustment clause (FPPAC). The first six base rate increases went into effect as scheduled and the remaining base rate increase is scheduled to be put into effect on June 1, 1996, concurrently with the semiannual adjustment for the FPPAC. Political and economic pressures, caused by PSNH's high retail electric rates, may force PSNH to accept less than an additional 5.5 percent rate increase scheduled for 1996, including an FPPAC increase; may lead to challenges to the Rate Agreement in the future; and may make recoveries of deferred costs after June 1, 1997 more difficult. The Rate Agreement provides that PSNH's rates will be subject to traditional rate regulation after the fixed rate period expires on June 1, 1997, but that the FFPAC will continue through June 1, 2000. The base rates effective as of June 1, 1996 will remain in effect after June 1, 1997 unless a rate change is approved by the NHPUC. For additional information regarding a recent lawsuit concerning the Rate Agreement, see "Item 3. Legal Proceedings." ELECTRIC INDUSTRY RESTRUCTURING IN NEW HAMPSHIRE On February 22, 1996, PSNH and the staff of the NHPUC reached an agreement that, if approved by the NHPUC, would resolve the terms of PSNH's participation in an Electric Retail Competition Pilot Program (Program) in New Hampshire. Under this agreement, PSNH will provide access to approximately 3 percent of its retail customers (35.13 MW) to other electric suppliers. PSNH will charge participating customers for delivery services, comprised of distribution, transmission, acquisition premium and access charge components. PSNH would recover all strandable costs through these charges. Only the energy portion of its tariffs, which account for approximately 20 percent of PSNH's typical retail bill, would be exposed to alternative suppliers. Program participants will also receive a 10 percent "incentive rebate" off PSNH's traditional rates to encourage participation in the Program. The System estimates that, due to the 10 percent incentive feature, the Program, if implemented as proposed, could cost PSNH approximately $5 million over its two-year term. The settlement terms are not binding on any future restructuring programs. The System companies also need FERC approval to allow Program participants access to the System's transmission system. Although the Program is scheduled to begin on May 28, 1996, this date is subject to both state and federal regulatory approvals. If the above-settlement is not approved by the NHPUC, PSNH could be subject to the final guidelines for the Program issued by the NHPUC on February 28, 1996. The guidelines propose a two-year retail wheeling experiment under which a selected group of retail customers aggregating 50 MW of demand would be free to purchase power from suppliers other than their franchised local utility. Strandable costs resulting from the Program would be split equally between utility investors and participating customers, but, if requested, the NHPUC would allow for a review of these costs after the conclusion of a separate strandable cost proceeding. On January 9, 1996, legislation was introduced in New Hampshire, requiring electric utilities to submit restructuring plans to the NHPUC by June 30, 1996, with final approval by June 30, 1997. The NHPUC would be further directed to implement full retail competition by June 30, 1998 or at the earliest date determined to be in the public interest by the NHPUC. Under the New Hampshire's Limited Electrical Energy Producers Act (LEEPA), a qualifying generator of not greater than 5-MW capacity is permitted to sell its output to up to three retail customers. LEEPA also provides that the local franchised utility could be ordered to wheel the energy to these retail customers. On January 8, 1996, the NHPUC issued an order stating that the LEEPA retail wheeling provision was not pre-empted by federal law and that it had authority to order such retail wheeling service if it was found to be in the public good. In 1994, Freedom Electric Power Company, now known as Freedom Energy Company, LLC (Freedom), filed a petition with the NHPUC for permission to operate as a retail electric utility selling to large industrial customers in New Hampshire, including customers of PSNH. On June 6, 1995, the NHPUC determined that electric utility franchises in New Hampshire are not exclusive as a matter of law. PSNH appealed this decision to the New Hampshire Supreme Court. Oral arguments on the appeal were heard on February 8, 1996. Pending this appeal and the related FERC proceeding referenced below, the NHPUC has delayed further activity in the underlying proceeding, including whether to allow Freedom to operate as a retail electric utility. On July 14, 1995, Freedom filed a petition for declaratory ruling with FERC requesting a ruling that it is entitled to transmission access from PSNH. PSNH and numerous parties seeking intervenor status in this proceeding have filed comments with FERC opposing Freedom's petition as a sham transaction prohibited by the Energy Policy Act. FPPAC The FPPAC provides for the recovery or refund by PSNH, for the ten-year period beginning on May 16, 1991, of the difference between its actual prudent energy and purchased power costs and the estimated amounts of such costs included in base rates established by the Rate Agreement. The FPPAC amount is calculated for a six-month period based on forecasted data and is reconciled to actual data in subsequent FPPAC billing periods. For the period December 1, 1994 through November 30, 1995, the NHPUC approved a continuation of the FPPAC rate that had been in effect during the last half of 1994. This rate treatment allowed PSNH to limit overall rate increases in 1995 to a level that did not exceed an overall 5.5 percent increase, while maintaining an FPPAC rate level sufficient to collect 1994 Seabrook refueling costs. On November 27, 1995, the NHPUC approved a zero rate for the FPPAC period December 1, 1995 through May 31, 1996 that resulted in a 2.6 percent decrease in rates. On April 4, 1995, the NHPUC opened a proceeding to consider whether under the Rate Agreement PSNH may recover its $28 million of expenditures-including approximately $22 million for pollution control additions at the Merrimack fossil generating station-and approximately $3.5 million of annual operating and maintenance expenses necessary for current compliance with the Clean Air Act Amendments of 1990 (CAAA) at PSNH's fossil generating stations. Also at issue is the prudence of PSNH's use of the selective catalytic reduction technology at Merrimack Station's Unit 2. Since June 1, 1995, the NHPUC has allowed PSNH to collect its CAAA costs through FPPAC until there is a final decision in this proceeding. For more information regarding the CAAA, see "Regulatory and Environmental Matters-Environmental Regulation-Air Quality Requirements." NUGs The costs associated with purchases by PSNH from certain NUGs at prices above the level assumed in rates are deferred and recovered through the FPPAC over ten years. As of December 31, 1995, NUG deferrals, including the remaining buy-out of two wood-fired NUGs discussed below, totaled approximately $192 million. Under the Rate Agreement, PSNH and the State of New Hampshire have an obligation to use their best efforts to renegotiate burdensome purchased power arrangements with 13 specified NUGs that were selling their output to PSNH under long-term rate orders. If authorized, PSNH will exchange near-term cash payments for partial relief from high-cost purchased power obligations to the NUGs, with such payments and an associated return on the unamortized portion being recoverable from customers in a future amortization period. In 1994, the NHPUC approved new purchased power agreements with five hydroelectric NUGs, which management anticipates will result in a decrease in payments to these NUGs during a year with normal waterflow of approximately 14 percent, or $1.4 million per year. The first of these new power purchase agreements will expire in 2022. In addition, PSNH has been involved in negotiations with eight wood-fired NUGs. In September 1994, the NHPUC approved settlement agreements with two of these wood-fired NUGs covering approximately 20 MW of capacity. Pursuant to the settlement agreements, PSNH paid the owners approximately $40 million in exchange for the cancellation of the rate orders under which these NUGs sold their entire output at rates in excess of PSNH's replacement power costs. As of December 31, 1995, PSNH had not yet recovered the approximately $34.2 million of deferred costs remaining to be collected on these settlement agreements. These NUGs also agreed not to compete with PSNH or other System subsidiaries in New Hampshire. PSNH has reached agreements, subject to NHPUC approval, with the six remaining NUGs. The NHPUC will conduct hearings on four of the final settlement agreements during the first half of 1996, while the parties finalize the terms of the two remaining agreements. The six agreements could result in net savings of approximately $430 million to PSNH's customers over a period of 20 years following guaranteed payments of approximately $250 million. If the NHPUC fails to provide for full recovery of strandable costs, however, management would reevaluate whether to proceed with the NUG buydown agreements. UNAMORTIZED PSNH ACQUISITION COSTS The Rate Agreement also provides for the recovery by PSNH through rates of unamortized PSNH acquisition costs, which is the aggregate value placed by PSNH's reorganization plan on PSNH's assets in excess of the net book value of its non-Seabrook assets and the value assigned to Seabrook. The unrecovered balance of the unamortized PSNH acquisition costs at December 31, 1995 was approximately $588.9 million. In accordance with the Rate Agreement, approximately $143 million of this amount is scheduled to be amortized and recovered through rates by 1998, and the remaining amount, approximately $446 million, is being amortized and will be recovered through rates by 2011. PSNH earns a return each year on the unamortized portion of the cost. For more information regarding PSNH's recovery of these costs after 1997, see "Unamortized PSNH Acquisition Costs" in the notes to NU's financial statements and "Unamortized Acquisition Costs" in the notes to PSNH's financial statements. DEMAND-SIDE MANAGEMENT/LEAST COST PLANNING On January 29, 1996, the NHPUC approved a settlement in PSNH's DSM proceeding authorizing a 1996 budget of approximately $4.3 million, including direct program costs plus the recovery of certain lost revenues attributable to the program of approximately $2.8 million. On April 10, 1995, in connection with PSNH's 1994 integrated least-cost resource plan filing, the NHPUC ordered PSNH to conduct future least-cost planning by evaluating resource options available to PSNH based on the economics of only the PSNH system, rather than the combined NU system. This ruling could have an adverse effect on the System's future resource planning. SEABROOK POWER CONTRACTS PSNH and NAEC have entered into two power contracts that obligate PSNH to purchase NAEC's 35.98 percent ownership of the capacity and output of Seabrook for the term of Seabrook's NRC operating license and to pay NAEC's "cost of service" during this period, whether or not Seabrook continues to operate. NAEC's cost of service includes all of its prudently incurred Seabrook-related costs, including maintenance and operation expenses, cost of fuel, depreciation of NAEC's recoverable investment in Seabrook and a phased-in return on that investment. The payments by PSNH to NAEC under these contracts constitute purchased power costs for purposes of the FPPAC and are recovered from customers under the Rate Agreement. Decommissioning costs are separately collected by PSNH in its base rates. See "Rates-New Hampshire Retail Rate-General" and "- FPPAC" for information relating to the Rate Agreement. At December 31, 1995, NAEC's net utility plant investment in Seabrook was approximately $707.1 million. If Seabrook were retired prior to the expiration of its NRC operating license term, NAEC would continue to be entitled under the contracts to recover its remaining Seabrook investment and a return on that investment and its other Seabrook-related costs over a 39-year period, less the period during which Seabrook has operated. The contracts provide that NAEC's return on its "allowed investment" in Seabrook (its investment in working capital, fuel, capital additions after the date of commercial operation and a portion of the initial investment) is calculated based on NAEC's actual capitalization over the term of the contracts, its actual debt and preferred equity costs and a common equity cost of 12.53 percent for the first ten years of the contracts, and thereafter at an equity rate of return to be fixed in a filing with FERC. The portion of the initial investment, which is included in the allowed investment, has increased annually since May 1991 and will reach 100 percent by May 31, 1996. As of December 31, 1995, 85 percent of the initial investment was included in rates. NAEC is entitled to earn a deferred return on the portion of the initial investment not yet phased into rates. The deferred return on the excluded portion of the initial investment, together with a return on it, will be recovered between 1997 and 2001. At December 31, 1995, the amount of this deferred return was $162.4 million. For additional information regarding the contracts, see "Seabrook Power Contracts" in the notes to PSNH's financial statements. MASSACHUSETTS RETAIL RATES GENERAL WMECO's retail rates are subject to the jurisdiction of the DPU. The rates charged under HWP's contracts with industrial customers are not subject to the ratemaking jurisdiction of any state or federal regulatory agency. In 1994, the DPU approved a settlement offer from WMECO and the Massachusetts Attorney General (AG) that, among other things, provided that WMECO's customers' overall bills would be reduced by approximately $13.3 million over a 20-month period from June 1, 1994 to January 31, 1996. Under the 1994 settlement agreement, base rates would revert to their pre-settlement level after February 1, 1996, resulting in a 2.4 percent rate increase. WMECO, however, did not increase its rates on February 1, 1996, pending settlement negotiations. On February 27, 1996, WMECO and the AG submitted a proposed settlement to the DPU that would continue the rate reduction first instituted in June 1994. The settlement provides, among other things, that WMECO's rates remain about 2.4 percent lower than otherwise authorized (a reduction of approximately $8 million per year) through February 1998. In addition, the agreement accelerates WMECO's recovery of strandable costs by an additional $5.8 million in 1996 and $10 million in 1997. The terms of the settlement were put into effect as of March 1, 1996, but are subject to final DPU approval. ELECTRIC INDUSTRY RESTRUCTURING IN MASSACHUSETTS In February 1995, the DPU began an investigation into electric industry restructuring in Massachusetts. On March 31, 1995, WMECO submitted its plan for the future of the electric industry entitled "Path To A Competitive Future" to the DPU. WMECO's comments paralleled those submitted by CL&P to the DPUC in March 1995. See "Rates-Connecticut Retail Rates-Electric Industry Restructuring in Connecticut." On August 16, 1995, the DPU found that it was in the public interest that electric utilities have an opportunity to recover net, nonmitigatable strandable costs during a transition to full competition, which period is to be no longer than ten years. Strandable costs are to be recovered by a mandatory charge. The DPU also ordered WMECO and two other Massachusetts utilities to submit, by February 16, 1996, plans for moving to a competitive generation market, retail choice of electric suppliers and incentive regulation for transmission and distribution. On February 16, 1996, WMECO filed its restructuring plan with the DPU. WMECO's plan, if implemented, would institute a stable five-year rate path based on performance incentives; a universal service charge to recover "net" strandable costs; a comprehensive approach to pay off rapidly strandable costs; and rate design modifications that reflect more market influence. In addition, WMECO's plan would put into place the structural changes needed for a more competitive retail marketplace by proposing illustrative rates which unbundle charges for generation, distribution, transmission and ancillary services; building the information system necessary to provide customers the data to make informed choices within a competitive market; developing rules necessary to provide fair competition and adequate customer protection in a competitive retail market; and proposing pilot programs to test customer choice of alternate suppliers of energy. Several other utilities and the Massachusetts Division of Energy Resources (DOER) also filed restructuring plans with the DPU. The DOER plan requires, among other things, (i) total retail choice by January 1, 1998; (ii) the separation of presently regulated electric utility into unregulated generation and regulated distribution companies by January 1, 2001; and (iii) the use of a market-based valuation process (e.g., auction) for identifying and mitigating strandable costs. A final schedule for implementation of a Massachusetts restructuring plan has not yet been issued. WMECO FUEL ADJUSTMENT CLAUSE AND GENERATING UNIT OPERATING PERFORMANCE In Massachusetts, all fuel costs are collected on a current basis by means of a forecasted semi-annual fuel clause, which is trued up periodically. The DPU must hold public hearings before permitting semi-annual adjustments in WMECO's retail fuel adjustment clause. In addition to energy costs, the fuel adjustment clause includes capacity and transmission charges and credits that result from short-term transactions with other utilities and from certain FERC- approved contracts among the System operating companies. Massachusetts law establishes an annual performance program related to fuel procurement and use and requires the DPU to review generating unit performance and related fuel costs. Fuel clause revenues collected in Massachusetts are subject to potential refund, pending the DPU's examination of the actual performance of WMECO's generating units. The DPU has found that possession of a minority ownership interest in a generating plant does not relieve a company of its responsibilities for the prudent operation of that plant. Accordingly, the DPU has established goals for the three Millstone units and for the three regional nuclear operating units (the Yankee plants) in which WMECO has ownership interests. The DPU has initiated prudence reviews of WMECO's 1993-1994 and 1994-1995 generating unit performances. Pursuant to the terms of the February 27, 1996 settlement proposal discussed above and subject to DPU approval, these prudence reviews would be terminated. In addition the settlement precludes any prudence review concerning the extended 1994-1995 Millstone 2 outage. DEMAND-SIDE MANAGEMENT In 1992, the DPU established a conservation charge (CC) to be included in WMECO's customers' bills. The CC includes incremental DSM program costs above or below base rate recovery levels, lost fixed-cost recovery adjustments and the provision for a DSM incentive mechanism. On August 24, 1995 and November 27, 1995, the DPU issued decisions limiting WMECO's recovery of lost base revenues in calendar year 1996 to those revenues lost due to implementation of conservation-related costs in the most recent three-year period. The DPU decision did not affect 1995 revenues, but the three-year limit on recovery is expected to reduce 1996 revenues by approximately $5.5 million. On January 17, 1996, the DPU approved a two-year settlement proposal that resolves WMECO's DSM-related proceedings before the DPU. The settlement resolves: (i) DSM budget levels for 1996 and 1997 (at $12.4 million and $11.9 million, respectively); (ii) the CC for each rate class for 1996 and 1997; and (iii) energy savings associated with past DSM activity. The DSM budget levels agreed upon for 1996 and 1997 are considerably lower than the $15.8 million in effect for 1995. The February 27, 1996 settlement proposal of WMECO and the AG, however, modifies, in part, the above-referenced DSM decisions. If approved by the DPU, the settlement would shift $8 million now included in the CC as lost base revenues into base rates. RESOURCE PLANS CONSTRUCTION The System's construction program in the period 1996 through 2000 is estimated as follows: 1996 1997 1998 1999 2000 (Millions) CL&P $154.6 $172.9 $155.3 $146.0 $147.6 PSNH 51.5 38.2 36.9 41.8 32.5 WMECO 30.4 44.2 42.4 34.0 33.8 NAEC 6.0 6.6 6.9 7.2 7.4 OTHER 22.6 5.1 3.2 2.0 1.9 TOTAL $265.1 $267.0 $244.7 $231.0 $223.2 ====== ====== ====== ====== ====== The construction program data shown above include all anticipated capital costs necessary for committed projects and for those reasonably expected to become committed, regardless of whether the need for the project arises from environmental compliance, nuclear safety, reliability requirements or other causes. The construction program's main focus is maintaining and upgrading the existing transmission and distribution system and nuclear and fossil-generating facilities. The construction program data shown above generally include the anticipated capital costs necessary for fossil generating units to operate at least until their scheduled retirement dates. Whether a unit will be operated beyond its scheduled retirement date, be deactivated or be retired on or before its scheduled retirement date is regularly evaluated in light of the System's needs for resources at the time, the cost and availability of alternatives and the costs and benefits of operating the unit compared with the costs and benefits of retiring the unit. Retirement of certain of the units could, in turn, require substantial compensating expenditures for other parts of the System's bulk power supply system. Those compensating capital expenditures have not been fully identified or evaluated and are not included in the table. FUTURE NEEDS The System periodically updates its long-range resource needs through its integrated demand and supply planning process. The System does not foresee the need for any new major generating facilities at least until 2011. The System's long-term plans rely, in part, on certain DSM programs. These System company sponsored measures, including installations to date, are projected to lower the System summer peak load in 2011 by 752 MW and lower the winter peak load as of January 1, 2012 by 495 MW. See "Rates" for information about rate treatment of DSM costs. In addition, System companies have long-term arrangements to purchase the output from certain NUGs under federal and state laws, regulations and orders mandating such purchases. NUGs supplied 649 MW of firm capacity in 1995. This is the maximum amount that the System companies expect to purchase from NUGs for the foreseeable future. See "Rates-New Hampshire Retail Rates- NUGs" for information concerning PSNH's efforts to renegotiate its agreements with 13 NUGs and "CL&P Cogeneration Costs" in the notes to NU's financial statements and "Cogeneration Costs" in the notes to CL&P's financial statements for information regarding CL&P's termination of one of its purchased-power agreements. The System's long-term resource plan also considers the economic viability of continuing the operation of certain of the System's fossil fuel generating units beyond their current book retirement dates. Continued operation of existing fossil fuel units past their book retirement dates (and replacing certain critically located peaking units if they fail) is expected to provide approximately 2,300 MW of resources by 2011 that would otherwise have been retired. The System's need for new resources may be affected by unscheduled retirements of its existing generating units, regulatory approval of the continued operation of fossil fuel units and nuclear units past scheduled retirement dates and deactivation of plants resulting from environmental compliance or licensing decisions. FINANCING PROGRAM 1995 FINANCINGS On January 23, 1995, CL&P Capital, L.P. (CL&P LP) issued $100 million of 9.3 percent Cumulative Monthly Income Preferred Securities (MIPS), Series A. CL&P is the sole general partner of CL&P LP and is the guarantor of the MIPS securities. The net proceeds from the issuance and sale of MIPS, along with the proceeds of short-term debt, were used to retire $67.5 million of CL&P's 1989 Series 9 percent preferred stock and $50 million of variable-rate 1989 Dutch Auction Rate Transferable Securities. In December 1995, NAEC completed a $225 million variable rate note facility with a group of banks. NAEC retired $205 million principal amount of its 15.23 percent notes, due 2000, in early November 1995, with funding in early December 1995 from the proceeds of the variable rate note facility. Interest rate swap agreements were entered into to effectively convert the interest rate on the new notes from variable to fixed. Under the terms of the interest rate swap agreements, the effective interest rate on the new notes is 7.05 percent. The refinancing is expected to save approximately $4 million annually over the next five years. Total System debt, including short-term and capitalized leased obligations, was $4.25 billion as of December 31, 1995, compared with $4.54 billion as of December 31, 1994 and $4.88 billion as of December 31, 1993. For more information regarding 1995 financings, see Notes to Consolidated Statements of Capitalization of NU's financial statements and "Short-Term Debt" in the notes to CL&P's, PSNH's, WMECO's and NAEC's financial statements. 1996 FINANCING REQUIREMENTS The System's aggregate capital requirements for 1996, exclusive of requirements under the Niantic Bay Fuel Trust (NBFT) and a one percent sinking and improvement fund for CL&P and WMECO, are as follows: Total CL&P PSNH WMECO NAEC Other System (Millions) Construction........... $154.6 $51.5 $30.4 $6.0 $22.6 $265.1 Nuclear Fuel...... - 1.8 - 0.6 - 2.4 Maturities............. - 172.5 - - - 172.5 Cash Sinking-funds..... 9.4 - 1.5 20.0 16.3 47.2 ------ ------ ----- ----- ----- ------ Total............ $164.0 $225.8 $31.9 $26.6 $38.9 $487.2 ====== ====== ===== ===== ===== ====== For further information on NBFT and the System's financing of its nuclear fuel requirements, see "Leases" in the notes to NU's, CL&P's and WMECO's financial statements. For further information on the System's 1996 and five-year financing requirements, see "Notes to Consolidated Statements of Capitalization" in NU's financial statements and "Long-Term Debt" in the notes to CL&P's, PSNH's and WMECO's financial statements. 1996 FINANCING PLANS The System Companies propose to finance their 1996 requirements, through both internal cash flow and external funds, with internally generated funds expected to provide substantially all of the necessary funds for the System. This estimate excludes the nuclear fuel requirements financed through the NBFT and any additional financing needed in connection with the PSNH NUGs settlements, but includes assumed funding of liability for prior spent nuclear fuel in the amounts of $160.2 million for CL&P and $38.6 million for WMECO. For more information regarding the NUGs settlements, see "Rates-New Hampshire Retail Rates-NUGs." In addition to financing their 1996 requirements, the System companies intend, if market conditions permit, to continue to refinance a portion of their outstanding long-term debt and preferred stock, if that can be done advantageously. In April 1995, NU began issuing NU common stock to fund its Dividend Reinvestment Plan (DRP). The total amount financed through the DRP in 1995 was approximately $41 million. NU expects to raise approximately the same amount of capital through the DRP in 1996. CL&P intends to issue through the Connecticut Development Authority $62 million principal amount of Pollution Control Revenue Bonds in the first half of 1996. The net proceeds of these bonds will be used to reimburse CL&P for its share of the cost of pollution control and solid waste disposal facilities at Millstone 3. PSNH also intends to establish a new $225 million revolving credit agreement in the second quarter of 1996 to replace its existing $125 million revolving credit agreement, which expires in May 1996. This credit facility will be used by PSNH primarily for refunding of a $172.5 million principal amount issue of maturing first mortgage bonds and for working capital purposes. On October 18, 1995, Moody's Investors Service lowered its ratings of PSNH and NAEC securities, bringing the rating for PSNH's First Mortgage Bonds below investment grade. Standard and Poor's had previously downgraded PSNH's first mortgage bonds below investment grade. NAEC's securities have never been rated investment grade by either agency. With both of the major nationally recognized securities rating organizations that rate PSNH and NAEC securities rating them below investment grade, PSNH's and NAEC's borrowing costs have increased and the future availability and cost of funds for those companies could be restricted. FINANCING LIMITATIONS The amounts of short-term borrowings that may be incurred by NU, CL&P, PSNH, WMECO, HWP and NAEC are subject to periodic approval by the SEC under the 1935 Act. Effective June 28, 1995, the SEC no longer regulates the short-term borrowings of NU's non-utility subsidiary companies from nonaffiliates or through the Northeast Utilities System Money Pool (Money Pool). The following table shows the amount of short-term borrowings authorized by the SEC for each company as of January 1, 1996 and the amounts of outstanding short-term debt of those companies at the end of 1995. Maximum Authorized Short-Term Debt Short-Term Debt Outstanding at 12/31/95* (Millions) NU.................. $ 150 $ 58 CL&P ............... 325 52 PSNH ............... 175 - WMECO............... 60 24 HWP................. 5 - NAEC................ 50 8 NNECO............... ** - RRR................. ** 17 Quinnehtuk.......... ** 5 HEC................. ** 2 --- Total $ 166 * This column includes borrowings of various System companies from NU and other System companies through the Money Pool. Total System short-term indebtedness to unaffiliated lenders was $99 million at December 31, 1995. ** Effective June 28, 1995, the SEC no longer regulates the short-term debt issuances of these companies. The supplemental indentures under which NU issued $175 million in principal amount of 8.58 percent amortizing notes in December 1991 and $75 million in principal amount of 8.38 percent amortizing notes in March 1992 contain restrictions on dispositions of certain System companies' stock, limitations of liens on NU assets and restrictions on distributions on and acquisitions of NU stock. Under these provisions, neither NU, CL&P, PSNH nor WMECO may dispose of voting stock of CL&P, PSNH or WMECO other than to NU or another System company, except that CL&P may sell voting stock for cash to third persons if so ordered by a regulatory agency so long as the amount sold is not more than 19 percent of CL&P's voting stock after the sale. The restrictions also generally prohibit NU from pledging voting stock of CL&P, PSNH or WMECO or granting liens on its other assets in amounts greater than 5 percent of the total common equity of NU. As of December 31, 1995, no NU debt was secured by liens on NU assets. Finally, NU may not declare or make distributions on its capital stock, acquire its capital stock (or rights thereto), or permit a System company to do the same, at times when there is an event of default under the supplemental indentures under which the amortizing notes were issued. The charters of CL&P and WMECO contain preferred stock provisions restricting the amount of unsecured debt those companies may incur. As of December 31, 1995, CL&P's charter would permit CL&P to incur an additional $466 million of unsecured debt and WMECO's charter would permit it to incur an additional $112 million of unsecured debt. In connection with NU's acquisition of PSNH, certain financial conditions intended to prevent NU from relying on CL&P resources if the PSNH acquisition strains NU's financial condition were imposed by the DPUC. The principal conditions provide for a DPUC review if CL&P's common equity falls to 36 percent or below, require NU to obtain DPUC approval to secure NU financings with CL&P stock or assets and obligate NU to use its best efforts to sell CL&P preferred or common stock to the public if NU cannot meet CL&P's need for equity capital. At December 31, 1995, CL&P's common equity ratio was 42.8 percent. While not directly restricting the amount of short-term debt that CL&P, WMECO, RRR, NNECO and NU may incur, credit agreements to which CL&P, WMECO, HWP, RRR, NNECO and NU are parties provide that the lenders are not required to make additional loans, or that the maturity of indebtedness can be accelerated, if NU (on a consolidated basis) does not meet a common equity ratio test that requires, in effect, that NU's consolidated common equity (as defined) be at least 30 percent for three consecutive quarters. At December 31, 1995, NU's common equity ratio was 35.7 percent. Under a certain credit agreement, PSNH is prohibited from incurring additional debt unless it is able to demonstrate, on a pro forma basis for the prior quarter and going forward, that its equity ratio (as defined) will be at least 27 percent of total capitalization (as defined) through June 30, 1996 and 28.5 percent through June 30, 1997. In addition, PSNH must demonstrate that its ratio of operating income to interest expense will be at least 1.75 to 1 for the end of each fiscal quarter for the remaining term of the agreement. At December 31, 1995, PSNH's common equity ratio was 36.4 percent and its operating income to interest expense ratio for the 12-month period was 2.74 to 1. During 1995, NAEC entered into a credit agreement that prohibits the incurrence of additional debt unless NAEC demonstrates that at all times its common equity (as defined) will be at least 25 percent and its ratio of adjusted net income (as defined) to interest expense will be at least 1.35 to 1 through December 31, 1997 and 1.50 to 1 thereafter. At December 31, 1995, NAEC's common equity ratio was 28.3 percent and its adjusted net income to interest expense ratio for the 12-month period was 1.51 to 1. See "Short-Term Debt" in the notes to NU's, CL&P's, PSNH's and WMECO's financial statements for information about credit lines available to System companies. The indentures securing the outstanding first mortgage bonds of CL&P, PSNH, WMECO and NAEC provide that additional bonds may not be issued, except for certain refunding purposes, unless earnings (as defined in each indenture and before income taxes, and, in the case of PSNH, without deducting the amortization of PSNH's regulatory asset) are at least twice the pro forma annual interest charges on outstanding bonds and certain prior lien obligations and the bonds to be issued. The preferred stock provisions of CL&P's, PSNH's and WMECO's charters also prohibit the issuance of additional preferred stock (except for refinancing purposes) unless income before interest charges (as defined and after income taxes and depreciation) is at least 1.5 times the pro forma annual interest charges on indebtedness and the annual dividend requirements on preferred stock that will be outstanding after the additional stock is issued. NU is dependent on the earnings of, and dividends received from, its subsidiaries to meet its own financial requirements, including the payment of dividends on NU common shares. At the current indicated annual dividend of $1.76 per share, NU's aggregate annual dividends on common shares outstanding at December 31, 1995, including unallocated shares held by the Employee Stock Option Plan, would be approximately $239 million. Dividends are payable on common shares only if, and in the amounts, declared by the NU Board of Trustees. SEC rules under the 1935 Act require that dividends on NU's shares be based on the amounts of dividends received from subsidiaries, not on the undistributed retained earnings of subsidiaries. The SEC's order approving NU's acquisition of PSNH under the 1935 Act approved NU's request for a waiver of this requirement through June 1997. PSNH and NAEC were effectively prohibited from paying dividends to NU through May 1993. Through the remainder of 1993 and 1994, PSNH did not pay dividends, to allow it to build up the common equity portion of its capitalization and to fund the buyout of certain NUGs operating in New Hampshire. See "Rates-New Hampshire Retail Rates-FPPAC and NUGs." PSNH and NAEC paid dividends to NU of $52 million and $24 million, respectively, in 1995. If PSNH does not fund its pro rata share of NU's dividend requirements, NU expects to fund that portion of its dividend requirements with the proceeds of borrowings. The supplemental indentures under which CL&P's and WMECO's first mortgage bonds and the indenture under which PSNH's first mortgage bonds have been issued limit the amount of cash dividends and other distributions these subsidiaries can make to NU out of their retained earnings. As of December 31, 1995, CL&P had $245.3 million, WMECO had $93.8 million and PSNH had $143.0 million of unrestricted retained earnings. PSNH's preferred stock provisions also limit the amount of cash dividends and other distributions PSNH can make to NU if after taking the dividend or other distribution into account, PSNH's common stock equity is less than 25 percent of total capitalization. The indenture under which NAEC's Series A Bonds have been issued also limits the amount of cash dividends or distributions NAEC can make to NU to retained earnings plus $10 million. At December 31, 1995, $69.6 million was available to be paid under this provision. PSNH's credit agreement prohibits it from declaring or paying any cash dividends or distributions on any of its capital stock, except for dividends on the preferred stock, unless minimum interest coverage and common equity ratio tests are satisfied. At December 31, 1995, $201 million was available to be paid under these provisions. NAEC's common equity covenant referred to above could also operate to restrict NAEC's ability to pay common dividends. Certain subsidiaries of NU established the Money Pool to provide a more effective use of the cash resources of the System and to reduce outside short- term borrowings. NUSCO administers the Money Pool as agent for the participating companies. Short-Term borrowing needs of the participating companies (except NU) are first met with available funds of other member companies, including funds borrowed by NU from third parties. NU may lend to, but not borrow from, the Money Pool. Investing and borrowing subsidiaries receive or pay interest based on the average daily Federal Funds rate, except that borrowings based on loans from NU bear interest at NU's cost. Funds may be withdrawn or repaid to the Money Pool at any time without prior notice. ELECTRIC OPERATIONS DISTRIBUTION AND LOAD The System companies own and operate a fully integrated electric utility business. The System operating companies' retail electric service territories cover approximately 11,335 square miles (4,400 in CL&P's service area, 5,445 in PSNH's service area and 1,490 in WMECO's service area) and have an estimated total population of approximately 4 million (2.5 million in Connecticut, 963,000 in New Hampshire and 582,000 in Massachusetts). The companies furnish retail electric service in 149, 198 and 59 cities and towns in Connecticut, New Hampshire and Massachusetts, respectively. In December 1995, CL&P furnished retail electric service to approximately 1.1 million customers in Connecticut, PSNH provided retail electric service to approximately 405,000 customers in New Hampshire and WMECO served approximately 194,000 retail electric customers in Massachusetts. HWP serves 38 retail customers in Holyoke, Massachusetts. The following table shows the sources of 1995 electric revenues based on categories of customers: CL&P PSNH WMECO NAEC Total System Residential........ 41% 34% 37% - 37% Commercial.......... 35 29 32 - 31 Industrial .......... 13 18 20 - 15 Wholesale* .......... 8 17 7 100% 14 Other ................ 3 2 4 - 3 ---- ---- --- --- --- Total ................ 100% 100% 100% 100% 100% * Includes capacity sales. NAEC's 1995 electric revenues were derived entirely from sales to PSNH under the Seabrook power contracts. See "Rates-New Hampshire Retail Rates- Seabrook Power Contracts" for a discussion of the contracts. Through December 31, 1995, the all-time peak demand on the System was 6,358 MW, which occurred on August 2, 1995. The System was also selling approximately 1,217 MW of capacity to other utilities at that time. At the time of the peak, the System's generating capacity, including capacity purchases, was 8,035 MW. System energy requirements were met in 1995 and 1994 as set forth below: Source 1995 1994 Nuclear .................................... 52% 54% Oil ........................................ 4 7 Coal ....................................... 10 8 Hydroelectric .............................. 3 4 Natural gas ................................ 5 3 NUGs ....................................... 13 14 Purchased-power............................. 13 10 -- -- 100% 100% The actual changes in retail KWh sales for the last two years and the forecasted sales growth estimates for the ten-year period 1995 through 2005, in each case exclusive of wholesale revenues, for the System, CL&P, PSNH and WMECO are set forth below: 1995 over 1994 over Forecast 1995-2005 1994 1993 Compound Rate of Growth System......... (.1)% 2.9% 1.2% CL&P........... (.3)% 3.4% 1.1% PSNH........... .4 % 2.0% 1.6% WMECO.......... (.1)% 1.4% 0.6% The actual changes in total KWh sales for the last two years, including wholesale KWh sales, for the System, CL&P, PSNH and WMECO are set forth below: 1995 over (under) 1994 1994 over (under) 1993 System ................... (1.24)% 2.53% CL&P ..................... (2.21)% 3.66% PSNH ..................... 1.08 % 1.70% WMECO .................... 0.33 % 1.49% For a discussion of trends in wholesale sales, see "Competition and Marketing- Wholesale Marketing." The combination of much milder winter temperatures and slower economic growth caused retail electric sales to fall by 0.1 percent in 1995, compared with 1994. The most significant reduction was in residential electric sales, which are most affected by summer and winter temperature variations. Residential sales were down 1.8 percent in 1995. By comparison, commercial sales were up by .8 percent for the year and industrial sales rose 1.7 percent. Had weather patterns in 1995 been similar to those in 1994, the System estimates its total retail sales would have risen by 0.3 percent. The reduced level of retail sales also resulted from a continued slowdown of economic growth in New England, particularly in Connecticut. Retail sales at CL&P fell by 0.3 percent in 1995. If weather effects were removed, CL&P's sales would have been flat when compared with 1994. The lack of growth is primarily attributable to the continued contraction of the manufacturing, defense, insurance and financial services sectors in Connecticut. PSNH's retail sales rose by 0.4 percent in 1995, largely because of a 4.4 percent increase in industrial sales. Higher industrial sales were due primarily to the continued growth of manufacturing activity in New Hampshire and a summer drought that reduced hydroelectric self-generation by some of PSNH's larger customers. WMECO retail sales were essentially flat in 1995 with 2.6 percent growth in commercial sales partially offsetting lower residential sales. For more information on the effect of competition on sales growth rates, see "Competition and Marketing." In spite of further defense and insurance curtailments moderate growth is forecasted to resume over the next ten years. The System forecasts a 1.0 percent growth rate of sales over this period. This growth rate is significantly below historic rates due to fewer young people entering the workforce and, in part, because of forecasted savings from System-sponsored DSM programs that are designed to minimize operating expenses for System customers and postpone the need for new capacity on the System. The forecasted ten-year growth rate of System sales would be approximately 1.5 percent if the System did not pursue DSM programs at the forecasted levels. See "Rates" for information about rate treatment of DSM costs. With the System's generating capacity of 7,956 MW as of January 1, 1996 (including the net of capacity sales to and purchases from other utilities, and approximately 649 MW of capacity purchased from NUGs under existing contracts), the System expects to meet reliably its projected annual peak load growth of 1.0 percent until at least the year 2011. Taking into account projected load growth for the System and committed capacity sales, but not taking into account future potential capacity sales to other utilities or purchases from other utilities that are not subject to firm commitments, the System's installed reserve is expected to be approximately 1,614 MW in the summer of 1996. The System companies operate and dispatch their generation as provided in the NEPOOL Agreement. In 1995, the peak demand on the NEPOOL system was 20,499 MW in July, which was 20 MW below the 1994 peak load of 20,519 MW in July of that year. NEPOOL has projected that there will be an increase in demand in 1996 and estimates that the summer 1996 peak load could reach 22,368 MW. NEPOOL projects that sufficient capacity will be available to meet this anticipated demand. REGIONAL AND SYSTEM COORDINATION The System companies and most other New England utilities with electric generating facilities are parties to the NEPOOL Agreement, which coordinates the planning and operation of the region's generation and transmission facilities. System transmission lines form part of the New England transmission system linking System generating plants with one another and with the facilities of other utilities in the Northeastern United States and Canada. The generating facilities of all NEPOOL participants are dispatched as a single system through the New England Power Exchange, a central dispatch facility. The NEPOOL Agreement provides for a determination of the generating capacity responsibilities of participants and certain transmission rights and responsibilities. NEPOOL's objectives are to assure that the bulk power supply of New England and adjoining areas conforms to proper standards of reliability, to attain maximum practical economy in the bulk power supply system consistent with such reliability standards and to provide for equitable sharing of the resulting benefits and costs. Since 1994, NEPOOL has been studying its own restructuring. On January 5, 1996, NEPOOL adopted a vision statement for the future called "NEPOOL Plus." NEPOOL Plus, if implemented, will maintain the pool's current strengths and adds key structural changes, including bid-based central energy dispatch, a changed and expanded basis for governance and increased independence of the operational function of NEPOOL staff as an independent system operator. The final NEPOOL restructuring plan will be subject to approval by FERC. Representatives of the System played an active role in the development of the plan. The System believes that NEPOOL Plus is an important component of electric industry restructuring in New England, providing the basis for a more efficient wholesale market for electricity and offering the potential for retail market efficiencies in the future. There are two agreements that determine the manner in which costs and savings are allocated among the System companies. Under the NUG&T, CL&P, WMECO and HWP (Initial System Companies) pool their electric production costs and the costs of their principal transmission facilities. Pursuant to the merger agreement, the Initial System Companies and PSNH entered into a ten-year, sharing agreement, expiring in June 2002, that provides, among other things, for the allocation of the capability responsibility savings and energy expense savings resulting from a single-system dispatch through NEPOOL. TRANSMISSION ACCESS In accordance with FERC's 1992 decision approving NU's acquisition of PSNH, NU made compliance filings with FERC, including transmission tariffs. FERC made all tariffs effective as of the merger date based on interim rates and terms of service established by FERC pursuant to summary determinations (without hearing). NU filed for rehearing of FERC's compliance tariff order in an effort to reinstate the originally proposed rates. FERC has not yet acted on NU's rehearing petition. In 1995, the System companies collected approximately $40 million in transmission revenues for transmission of power sales for the System companies and other electric utility generators. For information regarding the appeal of FERC's approval of NU's acquisition of PSNH, see "Item 3. Legal Proceedings." On March 29, 1995, FERC issued a Notice of Proposed Rulemaking (Mega-NOPR) on industry restructuring that would require, among other things, utilities to provide transmission access and certain ancillary services on the same terms as the utility provides those services to itself. The Mega-NOPR also supports full recovery of strandable costs as a result of retail wheeling with respect to those customers under FERC's jurisdiction. A final rule is not expected until June 1996. On September 5, 1995, the System filed with FERC its four transmission tariffs to meet the comparability standards articulated in the Mega-NOPR. On October 31, 1995, FERC accepted for filing the System's revised transmission tariffs and made them effective November 1, 1995. In the order, however, FERC noted that certain terms and conditions for such tariffs were not fully consistent with the Mega-NOPR pro forma tariffs and made the tariffs subject to the final order in its Mega-NOPR proceeding. FERC also stated that the System may use levelized rates rather than previously used depreciated embedded cost rate methods. On February 29, 1996, NU filed a settlement with FERC in this proceeding. The settlement resolves all issues except two rate design issues, which will be resolved through expedited paper hearing procedures over the next several months. If NU's rate design is confirmed, the System could collect approximately $2 million of additional transmission revenues annually. FOSSIL FUELS The System's residual oil-fired generation stations used approximately 5.6 million barrels of oil in 1995. The System obtained the majority of its oil requirements in 1995 through contracts with several large, independent oil companies. Those contracts allow for some spot purchases when market conditions warrant. Spot purchases represented approximately 10 percent of the System's fuel oil purchases in 1995. The contracts expire annually or biennially. The System currently does not anticipate any difficulties in obtaining necessary fuel oil supplies on economic terms. The System has five generating stations, aggregating approximately 800 MW, which can fully or partially burn either residual oil or natural gas/coals, as economics, environmental concerns or other factors dictate. CL&P is considering converting its oil-fired Middletown Station in Connecticut to a dual-fuel generating facility. Approximately 551 MW of capacity is capable of being converted at the Middletown Station. CL&P, PSNH and WMECO have contracts with the local gas distribution companies where the dual-fuel generating units are located, under which natural gas is made available by those companies on an interruptible basis. In addition, gas for CL&P'S Devon and Montville generating stations is being purchased directly from producers and brokers on an interruptible basis and transported through the interstate pipeline system and the local gas distribution company. The System expects that interruptible natural gas will continue to be available for its dual-fuel electric generating units on economic terms and will continue to supplement fuel oil requirements. See "Derivative Financial Instruments" in the notes to NU's and CL&P's financial statements for information about CL&P's oil and natural gas swap agreements that hedge against fuel price risk on certain long-term, fixed-price energy contracts. The System companies obtain their coal through long-term supply contracts and spot market purchases. The System companies currently have an adequate supply of coal. Because of changes in federal and state air quality requirements, the System may be required to use lower sulfur coal in its plants in the future. See "Regulatory and Environmental Matters-Environmental Regulation-Air Quality Requirements." NUCLEAR GENERATION GENERAL Certain System companies have interests in seven operating nuclear units: Millstone 1, 2 and 3, Seabrook 1 and three other units, Connecticut Yankee (CY), Maine Yankee (MY) and Vermont Yankee (VY), owned by regional nuclear generating companies (the Yankee companies). System companies operate the three Millstone units and Seabrook 1 and have operational responsibility for CY. Certain System companies also have interests in Yankee Rowe owned by the Yankee Atomic Electric Company (YAEC), which was permanently removed from service in 1992. CL&P and WMECO own 100 percent of Millstone 1 and 2 as tenants in common. Their respective ownership interests are 81 percent and 19 percent. CL&P, PSNH and WMECO have agreements with other New England utilities covering their joint ownership as tenants in common of Millstone 3. CL&P's ownership interest in the unit is 52.93 percent, PSNH's ownership interest in the unit is 2.85 percent and WMECO's interest is 12.24 percent. NAEC and CL&P have 35.98 percent and 4.06 percent ownership interests, respectively, in Seabrook. The Millstone 3 and Seabrook joint ownership agreements provide for pro-rata sharing by the owners of each unit of the construction and operating costs, the electrical output and the associated transmission costs. CL&P, PSNH, WMECO and other New England electric utilities are the stockholders of the Yankee companies. Each Yankee company owns a single nuclear generating unit. The stockholder-sponsors of each Yankee company are responsible for proportional shares of the operating costs of the respective Yankee company and are entitled to proportional shares of the electrical output. The relative rights and obligations with respect to the Yankee companies are approximately proportional to the stockholders' percentage stock holdings, but vary slightly to reflect arrangements under which nonstockholder electric utilities have contractual rights to some of the output of particular units. The Yankee companies and CL&P's, PSNH's and WMECO's stock ownership percentages in the Yankee companies are set forth below: CL&P PSNH WMECO System Connecticut Yankee Atomic Power Company (CYAPC) ...... 34.5% 5.0% 9.5% 49.0% Maine Yankee Atomic Power Company (MYAPC) ............ 12.0% 5.0% 3.0% 20.0% Vermont Yankee Nuclear Power Corporation (VYNPC)... 9.5% 4.0% 2.5% 16.0% Yankee Atomic Electric Company (YAEC) ............ 24.5% 7.0% 7.0% 38.5% CL&P, PSNH and WMECO are obligated to provide their percentages of any additional equity capital necessary for the Yankee companies, but do not expect to need to contribute additional equity capital in the future. CL&P, PSNH and WMECO believe that the Yankee companies, excluding YAEC, could require additional external financing in the next several years to finance construction expenditures, nuclear fuel and for other purposes. Although the ways in which each Yankee company would attempt to finance these expenditures, if they are needed, have not been determined, CL&P, PSNH and WMECO could be asked to provide direct or indirect financial support for one or more Yankee companies. For information regarding additional capital requirements at MY, see "Electric Operations-Nuclear Generation-Nuclear Plant Performance." On February 1, 1996, the System instituted a reorganization of its nuclear organization that puts in place a six person team to lead the five nuclear units that the System operates. The new nuclear management team is in charge of overseeing safety, efficiency and community relations at all five nuclear units. The new structure pools the expertise and strengths from each unit to manage issues to be addressed at all the units. NUCLEAR PLANT LICENSING AND NRC REGULATION The operators of Millstone 1, 2 and 3, CY, MY, VY, and Seabrook 1 hold full power operating licenses from the NRC. As holders of licenses to operate nuclear reactors, CL&P, WMECO, NAESCO, NNECO, and the Yankee companies are subject to the jurisdiction of the NRC. The NRC has broad jurisdiction over the design, construction and operation of nuclear generating stations, including matters of public health and safety, financial qualifications, antitrust considerations and environmental impact. The NRC issues 40-year initial operating licenses to nuclear units and NRC regulations permit renewal of licenses for an additional 20-year period. In addition, activities related to nuclear plant operation are routinely inspected by the NRC for compliance with NRC regulations. The NRC has authority to enforce its regulations through various mechanisms which include the issuance of notices of violation (NOV) and civil monetary penalties. One regulatory enforcement action, with an associated penalty of $50,000, was taken by the NRC in 1995 for certain violations involving the operability of motor-operated valves at Millstone 2. The NRC also regularly conducts generic reviews of technical and other issues, a number of which may affect the nuclear plants in which System companies have interests. The cost of complying with any new requirements that may result from these reviews cannot be estimated at this time, but such costs could be substantial. For more information regarding recent actions taken by the NRC with respect to the System's nuclear units, see "Electric Operations- Nuclear Generation-Nuclear Plant Performance." NUCLEAR PLANT PERFORMANCE Capacity factor is a ratio that compares a unit's actual generating output for a period with the unit's maximum potential output. The average capacity factor for operating nuclear units in the United States was 77.6 percent in 1995 and 69.9 percent for the five nuclear units operated by the System in 1995, compared with 67.5 percent for 1994. The System anticipates total expenditures in 1996 of approximately $425 million for operations and maintenance (O&M) and $55.5 million in capital improvements for the five nuclear plants that it operates. When the nuclear units in which they have interests are out of service, CL&P, PSNH and WMECO need to generate and/or purchase replacement power. Recovery of replacement power costs is permitted, subject to prudence reviews, through the GUAC for CL&P, through FPPAC for PSNH and through a retail fuel adjustment clause for WMECO. For the status of regulatory and legal proceedings related to recovery of replacement power costs for the 1991-1995 period, see "Rates." MILLSTONE UNITS For the 12 months ended December 31, 1995, the three Millstone units' composite capacity factor was 64.5 percent, compared with a composite capacity factor of 66.4 percent for the 12 months ended December 31, 1994 and 79.3 percent for the same period in 1993. On January 31, 1996, the NRC announced that the three Millstone nuclear units had been placed on its "watch list" because of long standing performance concerns that warranted "increased NRC attention until the licensee demonstrates a period of improved performance." The NRC listed a number of problems which have arisen since 1990 at Millstone Station, including licensed reactor operator requalification failures, repetitive improper maintenance causing an unisolable valve failure, problems with a supplemental leak collection release system, inadequate erosion-corrosion monitoring, untimely corrective action involving a heater drain tank recirculation line rupture, poor testing control causing an inadvertent drain-down of a reactor vessel, a high number of safety system failures, safety relief valve setpoint drift problems, untimely corrective actions for identified design deficiencies, failures to implement procedures which precipitated significant plant events and in some cases endangered plant staff and failure to comply with safety-related aspects of Millstone's Final Safety Analysis Report and portions of other requirements. Also mentioned were two instances of escalated enforcement actions by the NRC for harassment, intimidation and discrimination against employees raising safety concerns and a continuing high volume of employee allegations of safety concerns not being resolved appropriately by the System. The NRC recognized that at present there are significant current variations in the performance of the three units, but the foregoing events, combined with a failure to sustain performance improvements across all three units and to resolve employee concerns, required continued close NRC monitoring of programs and performance at Millstone Station to assure development and implementation of effective corrective action programs. While the NRC did not specifically restrict operations of the Millstone units, management expects that the increased NRC attention will inevitably have effects and costs that cannot be accurately estimated at this time. Management also plans to continue its extensive efforts already underway to address the NRC's concerns that employees at the Millstone Station are unable to raise nuclear safety issues to company supervisors and managers without fear of retaliation. Among the NRC's recent actions has been the establishment of a senior-level group to conduct an evaluation of the handling of Millstone employee concerns. In February 1996, the NRC also requested information regarding the process followed by the System in connection with its recent nuclear workforce reduction. Management shares the NRC's concerns in this area and is continuing to take steps to ensure that the environment at Millstone Station is one in which workers feel free to raise issues without fear of retaliation. For more information regarding the workforce reduction, see "Employees." On March 7, 1996, NUSCO received two letters from the NRC: the first relates to Millstone 2 and the second concerns Millstone 3 and CY. The correspondence regarding Millstone 2 notes "a number of operability and design concerns" at the unit and requires NU to submit information to the NRC on what NU has done to ensure future operations at Millstone 2 will conform to NRC regulations and to the unit's operating license and Updated Final Safety Analysis Report (UFSAR). That information must be submitted at least seven days before Millstone 2 restarts subsequent to the outage described below. The second NRC letter requests reports by April 6, 1996 on actions taken to date and the System's plans and schedule to ensure that future operation of Millstone 3 and CY will conform to NRC regulations and the units' operating licenses and UFSARs. Management does not know at this time whether the NRC will request similar information and assurances regarding Seabrook. Millstone 1, a 660-MW boiling-water reactor, has a license expiration date of October 6, 2010. In 1995, Millstone 1 operated at a 77.2 percent capacity factor. The unit began a planned refueling and maintenance outage on November 4, 1995. The original outage duration of 49 days has been extended to the middle to late part of the second quarter to complete overlay repairs on the reactor recirculation system and to respond to a December 1995 letter from the NRC requesting information regarding actions to be taken to ensure that future operations of Millstone 1 will be conducted in accordance with the terms and conditions of its operating license and NRC regulations. Total replacement- power costs for CL&P and WMECO are expected to be approximately $6.5 million per month. It is also estimated that CL&P and WMECO will incur an additional $20 million of O&M costs as a result of the extended outage. The recovery of the replacement power and O&M costs could be subject to refund as a result of prudence reviews in Connecticut or Massachusetts. Petitions were filed with the NRC in August 1995 seeking enforcement and other sanctions against the System for its historic practice of off-loading the full reactor core at Millstone 1 during refueling outages, as well as certain refueling practices at the other Millstone units and Seabrook 1. The NRC initiated several investigations in response to the petitions. One of the investigations was completed by the NRC's Office of the Inspector General in December 1995, which issued four findings: two critical of the System and two critical of the NRC technical staff's oversight of the System. In addition, several New England-based public interest groups have requested a hearing on a license amendment issued by the NRC for Millstone 1 which would explicitly authorize the full-core offload practice. The request for a hearing is pending before the NRC's Atomic Safety and Licensing Board, and hearings are expected to take place in 1996. Millstone 2, a 870-MW pressurized-water reactor, has a license expiration date of July 31, 2015. In 1995, Millstone 2 operated at a 35.9 percent capacity factor. In October 1994, Millstone 2 was shut down for a planned two month refueling and maintenance outage, which was extended by eight months. The outage encountered several unexpected difficulties that lengthened the duration of the outage. The outage extension was primarily caused by a significant scope increase in service water system repairs and an extremely deliberate approach to the conduct of work during the early portion of the outage. The unit returned to service on August 4, 1995. Replacement-power costs and O&M costs attributable to the extension of the outage for CL&P and WMECO were approximately $85 million and $24 million, respectively. The replacement power costs were recovered as incurred for WMECO and are currently being recovered by CL&P through the GUAC. O&M costs were deferred and are being amortized through rates by both CL&P and WMECO. The recovery of the replacement power and O&M costs could be subject to refund as a result of prudence reviews in Connecticut. Millstone 2 was shut down on February 21, 1996 as a result of an engineering evaluation that determined that some valves could be inoperable in certain emergency scenarios. With the unit already off-line, management has decided to move up a mid-cycle inspection outage that had previously been scheduled to begin in mid-April. Management does not know at this time whether the NRC's March 7, 1996 request for information discussed above will have a material impact on the restart schedule for Millstone 2 but does believe there will be an extension beyond the previously scheduled April 1995 restart date. For each month the unit is not in service, the System will incur approximately $8.5 million to $9 million for replacement power costs. Millstone 3, a 1154-MW pressurized-water reactor, has a license expiration date of November 25, 2025. In 1995, Millstone 3 operated at a 80.5 percent capacity factor. The unit began a planned refueling outage on April 14, 1995, which ended on June 7, 1995. SEABROOK Seabrook 1, a 1148-MW pressurized-water reactor, has a license expiration date of October 17, 2026. The Seabrook operating license expires 40 years from the date of issuance of authorization to load fuel, which was about three and one-half years before Seabrook's full-power operating license was issued. The System will determine at the appropriate time whether to seek recapture of some or all of this period from the NRC and thus add up to an additional three and one-half years to the operating term for Seabrook. In 1995, Seabrook operated at a capacity factor of 83.2 percent. The unit began a planned refueling and maintenance outage on November 3, 1995, which ended on December 11, 1995, the shortest planned outage in the unit's operating history. YANKEE UNITS CONNECTICUT YANKEE CY, a 582-MW pressurized-water reactor, has a license expiration date of June 29, 2007. In 1995, CY operated at a capacity factor of 72.6 percent. CY began a planned refueling and maintenance outage on January 28, 1995, which ended on April 19, 1995. The outage was extended by 31 days to inspect and replace service water piping and fan motor cables for the containment air recirculation fan cooler units. MAINE YANKEE MY, a 870-MW pressurized-water reactor, has a license expiration date of October 21, 2008. MY's operating license expires 40 years from the date of issuance of the construction permit, which was about four years before MY's full-power operating license was issued. At the appropriate time, MYAPC will determine whether to seek recapture of this construction period from the NRC and add it to the term of the MY operating license. In 1995, MY operated at a capacity factor of 2.6 percent. MY was out of service from early February 1995 through January 16, 1996 for a routine refueling outage combined with the sleeving of MY's three steam generators, at a cost of approximately $30 million. By order issued on January 3, 1996, the NRC suspended MY's authority to operate at full power and limited MY to operating at 90 percent power pending the NRC's review and approval of a computer code application used at MY. CL&P, WMECO and PSNH incurred additional costs for replacement power (estimated at $1 million, $200,000 and $400,000, respectively, per month) as result of the extended outage. VERMONT YANKEE VY, a 514-MW boiling water reactor, has a license expiration date of March 21, 2012. In 1995, VY operated at a capacity factor of 83.4 percent. VY had a 40-day planned refueling outage during 1995, which ended on May 3, 1995. YANKEE ROWE In February 1992, YAEC's owners voted to shut down Yankee Rowe permanently based on an economic evaluation of the cost of a proposed safety review, the reduced demand for electricity in New England, the price of alternative energy sources and uncertainty about certain regulatory requirements. The power contracts between CL&P, PSNH, WMECO and YAEC permit YAEC to recover from each its proportional share of the Yankee Rowe shutdown and decommissioning costs. For more information regarding the decommissioning of Yankee Rowe, see "Electric Operations-Nuclear Generation-Decommissioning." NUCLEAR INSURANCE The NRC requires nuclear plant licensees to maintain a minimum of $1.06 billion in nuclear property and decontamination insurance coverage. The NRC requires that proceeds from the policy following an accident that exceed $100 million will first be applied to pay expenses. The insurance carried by the licensees of the Millstone units, Seabrook 1, CY, MY and VY meets the NRC's requirements. YAEC has obtained an exemption for the Yankee Rowe plant from the $1.06 billion requirement and currently carries $25 million of insurance that otherwise meets the requirements of the rule. For more information regarding nuclear insurance, see "Nuclear Insurance Contingencies" in the notes to NU's, CL&P's, PSNH's, WMECO's and NAEC's financial statements. NUCLEAR FUEL The supply of nuclear fuel for the System's existing units requires the procurement of uranium concentrates, followed by the conversion, enrichment and fabrication of the uranium into fuel assemblies suitable for use in the System's units. The majority of the System companies' uranium enrichment services requirements is provided under a long-term contract with the United States Enrichment Corporation (USEC), a wholly owned United States government corporation. The majority of Seabrook's uranium enrichment services requirements is furnished through a Russian trading company. The System expects that uranium concentrates and related services for the units operated by the System and for the other units in which the System companies are participating, that are not covered by existing contracts, will be available for the foreseeable future on reasonable terms and prices. On August 10, 1995, NAESCO filed a complaint in the United States Court of Federal Claims challenging the propriety of the prices charged by the USEC for uranium enrichment services procured for Seabrook Station in 1993. The complaint is an appeal of the final decision rendered by the USEC contracting officer denying NAESCO's claims, which range from $2.5 to $5.8 million, and will likely be considered along with similar complaints that are pending before the court on behalf of 13 other utilities. As a result of the Energy Policy Act, the United States commercial nuclear power industry is required to pay to the United States Department of Energy (DOE), through a special assessment for the costs of the decontamination and decommissioning of uranium enrichment plants owned by the United States government, no more than $150 million for 15 years beginning in 1993. Each domestic nuclear utility's payment is based on its pro rata share of all enrichment services received by the United States commercial nuclear power industry from the United States government through October 1992. Each year, the DOE will adjust the annual assessment using the Consumer Price Index. The Energy Policy Act provides that the assessments are to be treated as reasonable and necessary current costs of fuel, which costs shall be fully recoverable in rates in all jurisdictions. The System's total share of the estimated assessment was approximately $62.4 million. Management believes that the DOE assessments against CL&P, WMECO, PSNH and NAEC will be recoverable in future rates. Accordingly, each of these companies has recognized these costs as a regulatory asset, with a corresponding obligation on its balance sheet. On June 22, 1995, the United States Court of Federal Claims held that, as applied to YAEC, the Uranium Enrichment Decontamination and Decommissioning Fund is an unlawful add-on to the bargained-for contract price for enriched uranium. As a result, the federal government must refund the approximately $3.0 million that YAEC has paid into the fund since its inception. NU is evaluating the applicability of this decision to the $21 million that the System companies have already paid into the fund, and whether this alters the System companies' obligation to pay such special assessments in the future. The decision as to YAEC has been appealed by the federal government. Nuclear fuel costs associated with nuclear plant operations include amounts for disposal of nuclear waste. The System companies include in their nuclear fuel expense spent fuel disposal costs accepted by the DPUC, NHPUC and DPU in rate case or fuel adjustment decisions. Spent fuel disposal costs are also reflected in FERC-approved wholesale charges. Such provisions include amortization and recovery in rates of previously unrecovered disposal costs of accumulated spent nuclear fuel. HIGH-LEVEL RADIOACTIVE WASTE The Nuclear Waste Policy Act of 1982 (NWPA) provides that the federal government is responsible for the permanent disposal of spent nuclear reactor fuel and high-level waste. As required by the NWPA, electric utilities generating spent nuclear fuel and high-level waste are obligated to pay fees into a fund which would be used to cover the cost of siting, constructing, developing and operating a permanent disposal facility for this waste. The System companies have been paying for such services for fuel burned starting in April 1983 on a quarterly basis since July 1983. The DPUC, NHPUC and DPU permit the fee to be recovered through rates. In return for payment of the fees prescribed by the NWPA, the federal government is to take title to and dispose of the utilities' high-level wastes and spent nuclear fuel. The NWPA provides that a disposal facility be operational and for the DOE to accept nuclear waste for permanent disposal in 1998. On April 28, 1995, DOE issued an interpretative release stating that it does not have an unconditional statutory or contractual obligation to accept spent fuel beginning January 1, 1998. On June 23, 1995, the DPUC and the New Hampshire Office of Consumer Advocate joined the Connecticut, New Hampshire and Massachusetts Attorneys General and a number of states in a lawsuit filed in federal court against the DOE, seeking a declaratory judgment that the DOE has a statutory obligation to take high-level nuclear waste from utilities in 1998 and to establish judicially administered milestones to enforce that obligation. On October 4, 1995, NUSCO, NAESCO and CYAPC joined a companion lawsuit filed by a number of utilities seeking similar relief. The cases were consolidated by the federal court of appeals. Oral argument was held on January 17, 1996, and the matter is still pending. Nuclear utilities and state regulators are presently considering additional steps that they might take to ensure that the DOE is able to meet its obligations with regard to nuclear waste disposal as soon as possible. Until the federal government begins accepting nuclear waste for disposal, operating nuclear generating plants will need to retain high-level waste and spent fuel on-site or make some other provisions for their storage. With the addition of new storage racks, storage facilities for Millstone 3 and CY are expected to be adequate for the projected life of the units. The storage facilities for Millstone 1 and 2 are expected to be adequate (maintaining the capacity to accommodate a full-core discharge from the reactor) until 2001. Fuel consolidation, which has been licensed for Millstone 2, could provide adequate storage capability for the projected lives of Millstone 1 and 2. In addition, other licensed technologies, such as dry storage casks or on-site transfers, are being considered to accommodate spent fuel storage requirements. With the current installation of new racks in its existing spent fuel pool, Seabrook is expected to have spent fuel storage capacity until at least 2010. In 1995, MYAPC began replacing the fuel racks in the spent fuel pool at MY to provide for additional storage capacity. MYAPC believes that the replacement of the fuel racks will provide adequate storage capacity through MY's current licensed operating life. The storage capacity of the spent fuel pool at VY is expected to be reached in 2005, and the available capacity of the pool is expected to be able to accommodate full-core removal until 2001. Because the Yankee Rowe plant was permanently shut down in February 1992, YAEC is considering the construction of a temporary facility to store the spent nuclear fuel produced by the Yankee Rowe plant over its operating lifetime until that fuel is removed by the DOE. See "Electric Operations-Nuclear Generation-Decommissioning" for further information on the closing and decommissioning of Yankee Rowe, including a recent order issued by the NRC halting decommissioning activities at Yankee Rowe. LOW-LEVEL RADIOACTIVE WASTE In April 1995, the Northwest interstate compact passed a resolution and order broadening the types of low-level radioactive waste (LLRW) acceptable for disposal at the privately operated Envirocare facility in Utah. This policy change made a significant portion of utility LLRW acceptable for disposal at Envirocare. In July 1995, the state of South Carolina reopened the Barnwell LLRW disposal site to the nation (except for North Carolina). These events enabled Seabrook to begin shipping its first LLRW ever and, for the first time since 1992, gave Millstone Station and CY a choice of disposal sites for certain categories of LLRW. By the end of November 1995, the System had contracts with both Barnwell and Envirocare for operational LLRW disposal. The vast majority of LLRW in storage from July 1994 through June 1995 at Millstone station and CY, and in storage since startup at the Seabrook plant, was shipped to either Barnwell or Envirocare by the end of 1995. The System incurred approximately $8 million in off-site LLRW disposal costs in 1995 for the five nuclear units it operates. Because access to LLRW disposal may be lost at any time, the System has plans that will allow for on-site storage of LLRW for at least five years in the event that disposal is interrupted. Both Connecticut and New Hampshire are also pursuing other options for out-of-state disposal of LLRW. MY had stored all its LLRW on-site since January 1, 1993, when it lost access to off-site disposal facilities. Most of this stored waste has been shipped to Barnwell since Maine regained access to the site in mid-1995. The plant has the capability to store a volume of LLRW equivalent to at least five years generation, in the event that off-site disposal access is lost. VY has stored all its LLRW on-site since July 1994. The plant also has the capacity to store a volume of LLRW equivalent to at least five years generation, in the event that off-site disposal access is lost. With access to Barnwell in mid-1995, VY has elected to continue storing most of its LLRW on-site in anticipation of lower future disposal costs at the yet-to-be constructed Texas LLRW disposal site. Both Maine and Vermont are in the process of implementing an agreement with Texas to provide access to a LLRW disposal facility that is to be developed in that state. All three states plan to form a LLRW compact that is currently awaiting approval by Congress. DECOMMISSIONING Based upon the System's most recent comprehensive site-specific updates of the decommissioning costs for each of the three Millstone units and for Seabrook, the recommended decommissioning method continues to be immediate and complete dismantlement of those units at their retirement. The table below sets forth the estimated Millstone and Seabrook decommissioning costs for the System companies. The estimates are based on the latest site studies, escalated to December 31, 1995 dollars. CL&P PSNH WMECO NAEC System (Millions) Millstone 1 $300.3 $ - $ 70.4 $ - $ 370.7 Millstone 2 265.8 - 62.3 - 328.1 Millstone 3 232.0 12.5 53.7 - 298.2 Seabrook 1 17.2 - - 152.5 169.7 ----- ----- ------ ------ ------- Total $815.3 $12.5 $186.4 $152.5 $1166.7 ====== ===== ====== ====== ======= As of December 31, 1995, the balances (at market) in certain external decommissioning trust funds, as discussed more fully below, were as follows: CL&P PSNH WMECO NAEC System (Millions) Millstone 1 $113.2 $ - $ 33.8 $ - $147.0 Millstone 2 73.2 - 22.8 - 96.0 Millstone 3 49.9 2.4 13.3 - 65.6 Seabrook 1 1.7 - - 15.3 17.0 ------ ------ ------ ----- ------ Total $238.0 $ 2.4 $ 69.9 $15.3 $325.6 ====== ====== ====== ===== ====== Pursuant to Connecticut law, CL&P has periodically filed plans with the DPUC for financing the decommissioning of the three Millstone units. In 1986, the DPUC approved the establishment of separate external trusts for the currently tax-deductible portions of decommissioning expense accruals for Millstone 1 and 2 and for all expense accruals for Millstone 3. In its 1993 CL&P multiyear rate case decision, the DPUC allowed CL&P's full decommissioning estimate for the three Millstone units to be collected from customers. This estimate includes an approximate 16 percent contingency factor for the decommissioning cost of each unit. The estimated aggregate cost of decommissioning the System's ownership share in the Millstone units is approximately $997 million in December 1995 dollars. WMECO has established independent trusts to hold all decommissioning expense collections from customers. In its 1990 WMECO multiyear rate case decision, the DPU allowed WMECO's decommissioning estimate for the three Millstone units ($840 million in December 1990 dollars) to be collected from customers. Due to the settlement in the 1992 WMECO rate case, the aggregate decommissioning estimate for the three Millstone units remains unchanged. New Hampshire enacted a law in 1981 requiring the creation of a state- managed fund to finance decommissioning of any units in that state. The New Hampshire Decommissioning Fund Commission (NHDFC) approved a revised decommissioning estimate in June 1995. On the basis of this revised estimate, the total decommissioning cost for the System's ownership share of Seabrook is $169.7 million in December 1995 dollars. NAEC's costs for decommissioning are billed by it to PSNH and recovered by PSNH under the Rate Agreement. Under the Rate Agreement, PSNH is entitled to a base rate increase to recover increased decommissioning costs. See "Rates-New Hampshire Retail Rates-General" for further information on the Rate Agreement. The decommissioning cost estimates for the System nuclear units are reviewed and updated regularly to reflect inflation and changes in decommissioning requirements and technology. Changes in requirements or technology, or adoption of a decommissioning method other than immediate dismantlement, could change these estimates. CL&P, PSNH and WMECO attempt to recover sufficient amounts through their allowed rates to cover their expected decommissioning costs. Only the portion of currently estimated total decommissioning costs that has been accepted by regulatory agencies is reflected in rates of the System companies. Based on present estimates, and assuming its nuclear units operate to the end of their respective license periods, the System expects that the decommissioning trusts funds will be substantially funded when those expenditures have to be made. CYAPC, YAEC, VYNPC and MYAPC are all collecting revenues for decommissioning from their power purchasers. The table below sets forth the estimated decommissioning costs of the Yankee units for the System companies. The estimates are based on the latest site studies, escalated to December 31, 1995 dollars. For information on the equity ownership of the System companies in each of the Yankee units, see "Electric Operations-Nuclear Generation- General." CL&P PSNH WMECO System (Millions) VY $ 33.0 $ 13.9 $ 8.7 $ 55.6 Yankee Rowe* 65.9 18.8 18.8 103.5 CY 133.0 19.3 36.6 188.9 MY 42.4 17.7 10.6 70.7 ------ ------ ------ ------ Total $274.3 $ 69.7 $ 74.7 $418.7 ====== ====== ====== ====== - --------------- * The costs shown include all remaining decommissioning costs and other closing costs associated with the early retirement of Yankee Rowe as of December 31, 1995. As of December 31, 1995, the balances (at market) in the external decommissioning trust funds for the Yankee units were as follows: CL&P PSNH WMECO System (Millions) VY $ 13.4 $ 5.7 $ 3.5 $ 22.6 Yankee Rowe 29.0 8.3 8.3 45.6 CY 61.6 8.9 17.0 87.5 MY 17.1 7.1 4.2 28.4 ---- ---- ---- ---- Total $121.1 $30.0 $33.0 $184.1 ====== ===== ===== ====== YAEC has begun decommissioning its nuclear facility. However, on October 12, 1995, the NRC issued an order halting major dismantlement or decommissioning activities at Yankee Rowe until after completion of an adjudicatory hearing process. The NRC's action was taken in response to a recent federal appeals court decision finding that the NRC should have offered a hearing opportunity prior to authorizing Yankee Rowe's component removal program in 1993. On January 16, 1996, the NRC issued a decision requiring that the proceeding, including hearings if necessary, be completed by mid-July 1996. Based on a pre-hearing conference held on February 21, 1996, YAEC expects that the NRC will reapprove the Yankee Rowe decommissioning plan. On December 29, 1995, FERC approved a revised decommissioning estimate for Yankee Rowe, which assumed prompt resumption of major decommissioning activities. Based on the revised decommissioning estimate, the total remaining decommissioning cost for the System's ownership share of Yankee Rowe is approximately $103.5 million in December 1995 dollars. CYAPC accrues decommissioning costs on the basis of immediate dismantlement at retirement. In May 1993, FERC approved a settlement agreement in a CYAPC rate proceeding allowing a revised decommissioning estimate of $294.2 million (in July 1992 dollars) to be recovered in rates beginning on June 1, 1993. This amount will increase by a stated amount each year for inflation. The most current estimated decommissioning cost of the System's ownership share is approximately $188.9 million in year-end 1995 dollars. MYAPC estimates the cost of the System's ownership share of decommissioning MY at $70.7 million in December 31, 1995 dollars based on a study completed in July 1993. VYNPC estimates the cost of the System's ownership share of decommissioning VY at $55.6 million in December 31, 1995 dollars based on a study completed in March 1994. NONUTILITY BUSINESSES PRIVATE POWER DEVELOPMENT The System participates as a developer and investor in domestic and international private power projects through its subsidiary, Charter Oak. Management currently does not permit Charter Oak to invest in facilities which are located within the System service territory or sell electric output to any of the System electric utility companies. Charter Oak is investing primarily in projects outside of the United States. Charter Oak owns, through wholly owned special-purpose subsidiaries, a 10 percent equity interest in a 220-MW natural gas-fired combined-cycle cogeneration QF in Texas, a 56 MW interest in a 1,875-MW natural gas-fired cogeneration facility in the United Kingdom and a 33 percent equity interest in a 114-MW natural gas-fired project in Argentina. Charter Oak is currently participating in the development of projects in Latin America and the Pacific Rim. Specifically, Charter Oak is engaged in constructing a 168-MW natural gas-fired project located in Argentina and a 20-MW wind-power project in Costa Rica. Although Charter Oak has no full-time employees, 14 NUSCO employees are dedicated to Charter Oak activities on a full-time basis. Other NUSCO employees provide services as required. NU's Board of Trustees has authorized investments up to $200 million in Charter Oak. NU's total investment in Charter Oak was approximately $64 million as of December 31, 1995. NU currently is committed to invest or guarantee up to an additional $75 million in Charter Oak to fund completion of the natural gas-fired project in Argentina and the wind-power project in Costa Rica. To date, Charter Oak's consolidated revenues and net income (loss) have not been material to the System. ENERGY MANAGEMENT SERVICES In 1990, NU organized a subsidiary corporation, HEC, to acquire substantially all of the assets and personnel of a nonaffiliated energy management services company. In general, HEC contracts to reduce its customers' energy costs and/or conserve energy and other resources. HEC also provides DSM consulting services to utilities and others. HEC's energy management and consulting services previously had been directed primarily to the commercial, industrial and institutional markets and utilities in New England and New York, but, on July 19, 1995, HEC received expanded authority from the SEC to perform energy management services without geographical limitation. NU's aggregate equity investment in HEC was approximately $4 million through December 31, 1995. REGULATORY AND ENVIRONMENTAL MATTERS ENVIRONMENTAL REGULATION GENERAL The System and its subsidiaries are subject to federal, state and local regulations with respect to water quality, air quality, toxic substances, hazardous waste and other environmental matters. Similarly, the System's major generation and transmission facilities may not be constructed or significantly modified without a review by the applicable state agency of the environmental impact of the proposed construction or modification. Compliance with environmental laws and regulations, particularly air and water pollution control requirements, may limit operations or require substantial investments in new equipment at existing facilities. See "Resource Plans" for a discussion of the System's construction plans. SURFACE WATER QUALITY REQUIREMENTS The federal Clean Water Act (CWA) requires every "point source" discharger of pollutants into navigable waters to obtain a National Pollutant Discharge Elimination System (NPDES) permit from the United States Environmental Protection Agency (EPA) or state environmental agency specifying the allowable quantity and characteristics of its effluent. System facilities have all required NPDES permits in effect. Compliance with NPDES and state water discharge permits has necessitated substantial expenditures and may require further expenditures because of additional requirements that could be imposed in the future. On October 13, 1995, the Connecticut Department of Environmental Protection (CDEP) issued a consent order to CL&P and the Long Island Lighting Company (LILCO) requiring those companies to address leaks from the Long Island cable, which is jointly owned by CL&P and LILCO. The order requires CL&P and LILCO to study and propose alternatives for prevention, detection and mitigation of oil leaks and to evaluate the ecological effects of leaks on the environment. Alternatives to be studied include replacement of the cable and the dielectric fluid currently used in the cable. The System will incur additional costs to meet the requirements of the order and to meet any subsequent CDEP requirements resulting from the studies under the consent order, which costs cannot be estimated at this time. Management also cannot determine at this time whether long-term future operation of the cable will remain cost effective subsequent to any additional CDEP requirements. In early February 1996, the CDEP notified CL&P and LILCO that it desired to amend the consent order to cover transformer oil that was inadvertently introduced into the cable by LILCO at its pumping station on Long Island. LILCO is in the process of removing the transformer oil from the cable and has instituted safeguards to prevent it from happening again. The System does not believe that any of the transformer oil reached the part of the cable in Connecticut. The United States Attorney's Office in New Haven, Connecticut has commenced an investigation and has issued subpoenas to CL&P, NU, NUSCO, CONVEX and LILCO seeking documents relating to operation and maintenance of and recent leaks from the Long Island cable. Since the investigation is in its preliminary stages and the government has not revealed the scope of its investigation, management cannot evaluate the likelihood of a criminal proceeding being initiated at this time. However, management is aware of nothing that would suggest that any System company, officer or employee has engaged in conduct that would warrant such a proceeding. The CWA requires EPA and state permitting authorities to approve the cooling water intake structure design and thermal discharge of steam-electric generating plants. All System steam-electric plants have received these approvals. In the renewed NPDES discharge permit for the three Millstone nuclear units, issued in 1992, CDEP included a condition requiring a feasibility study of various structural or operational modifications of the cooling water intake system to reduce the entrainment of winter flounder larvae. The report, submitted in 1993, concluded that the mitigation alternatives examined were not technically feasible or cost effective. The CDEP found that the current cooling water intake represents the "best available technology" for minimizing adverse impacts, but required NNECO to schedule refueling outages, when possible, to coincide with high larval winter flounder abundance at the intakes and to report the results of such efforts. The NPDES permit further states that additional evidence may result in the agency imposing more stringent requirements. Merrimack Station's NPDES permit requires site work to isolate adjacent wetlands from the station's waste water system. Plans have been approved by the New Hampshire Department of Environmental Services (NHDES), and PSNH is now preparing a permit application to begin construction. The Merrimack permit also requires PSNH to perform further biological studies because significant numbers of migratory fish are being restored to lower reaches of the Merrimack River. These studies are in progress and initial results will be reported in 1996. Preliminary findings from these studies indicate that Merrimack Station's once-through cooling system does not interfere with the establishment of a balanced aquatic community. However, if NHDES determines there is interference, PSNH could be required to construct a partially enclosed cooling water system for Merrimack Station. The amount of capital expenditures relating to the foregoing cannot be determined at this time. However, if such expenditures were required, they would likely be substantial and a reduction of Merrimack Station's net generation capability could result. The ultimate cost impact of the CWA and state water quality regulations on the System cannot be estimated because of uncertainties such as the impact of changes to the effluent guidelines or water quality standards. Additional modifications, in some cases extensive and involving substantial cost, may ultimately be required for some or all of the System's generating facilities. In response to several major oil spills in recent years, Congress passed the Oil Pollution Act of 1990 (OPA 90). OPA 90 sets out the requirements for facility response plans and periodic inspections of spill response equipment at facilities that can cause substantial harm to the environment by discharging oil or hazardous substances into the navigable waters of the United States and onto adjoining shorelines. Pursuant to OPA 90, EPA has authority to regulate nontransportation-related fixed onshore facilities and the United States Coast Guard (Coast Guard) has the authority to regulate transportation-related onshore facilities. Response plans were filed for all System facilities believed to be subject to this requirement. The Coast Guard has completed its final review process and issued its approval of these plans. The EPA has issued its approval of all facility plans except PSNH's Schiller Station, where the EPA has authorized continued operation pending its final plan approval. OPA 90 includes limits on the liability that may be imposed on persons deemed responsible for release of oil. The limits do not apply to oil spills caused by negligence or violation of laws or regulations. OPA 90 also does not preempt state laws regarding liability for oil spills. In general, the laws of the states in which the System owns facilities and through which the System transports oil could be interpreted to impose strict liability for the cost of remediating releases of oil and for damages caused by releases. The System and its principal oil transporter currently carry a total of $900 million in insurance coverage for oil spills. AIR QUALITY REQUIREMENTS The Clean Air Act Amendments of 1990 (CAAA) made extensive revisions and additions to the federal Clean Air Act and imposed many stringent new requirements on air emissions sources. The CAAA contains provisions that further regulate emissions of sulfur dioxide (SO2) and nitrogen oxide (NOX) for the purpose of controlling acid rain and ground level ozone. In addition, the CAAA addresses the control of toxic air pollutants. Installation of continuous emissions monitors (CEMs) and expanded permitting provisions are also included. Existing and future federal and state air quality regulations could hinder or possibly preclude the construction of new, or the modification of existing, fossil units in the System's service area and could raise the capital and operating cost of existing units. The ultimate cost impact of these requirements on the System cannot be estimated because of uncertainties about how EPA and the states will implement various requirements of the CAAA. Nitrogen Oxide. Title I of the CAAA identifies NOX emissions as a precursor of ambient ozone. The Northeastern region of the United States, including Connecticut, Massachusetts and New Hampshire, currently exceeds the ambient air quality standard for ozone. Pursuant to the CAAA, states exceeding the ozone standard must implement plans to address ozone nonattainment. All three states have issued final regulations to implement Phase I reduction requirements, and the System has met these requirements. Compliance with Phase I requirements has cost the System a total of approximately $41 million: $10 million for CL&P, $27 million for PSNH, $1 million for WMECO and $3 million for HWP. Compliance has been achieved using a combination of currently available technology, combustion efficiency improvements and emissions trading. Compliance costs for Phase II, effective in 1999, are expected to result in an additional cost of $10 to $15 million. In December 1993, PSNH reached a revised agreement regarding NOX emissions with various environmental groups and the New Hampshire Business and Industrial Association (NHBIA). The agreement provides for aggressive unit-specific NOX emission rate limits for PSNH's generating facilities, effective May 31, 1995. The agreement relieves PSNH of a prior commitment to retire or repower Merrimack Unit 2 by May 15, 1999. More stringent emission rate limits equivalent to the range of 0.1 to 0.4 pounds of NOX per million Btu, however, are required for the unit by that date. In May 1994, NHDES promulgated the New Hampshire NOX reduction rule in accordance with the terms of the NHBIA Agreement. PSNH has complied with the requirements of this rule by installing controls on the units. The additional requirements for Merrimack Unit 2 for 1999 may be attained through increased catalytic reduction of NOX at an additional estimated cost of $5 to $7 million. Sulfur Dioxide. The CAAA mandates reductions in SO2 emissions to control acid rain. These reductions are to occur in two phases. First, certain high SO2 emitting plants were required to reduce their emissions beginning January 1, 1995. All Phase I units will be allocated SO2 allowances for the period 1995- 1999. These allowances are freely tradable. One allowance entitles a source to emit one ton of SO2 in a year. No unit may emit more SO2 in a particular year than the amount for which it has allowances. The only System units subject to the Phase I reduction requirements are PSNH's Merrimack Units 1 and 2. Additionally, Newington Station in New Hampshire and Mt. Tom Station in Massachusetts are conditional Phase I units. This means that the System can decide to include these plants as Phase I units during any year and obtain allowances for that year. The System has included these plants as Phase I units for 1995. On January 1, 2000, the start of Phase II, a nationwide cap of 8.9 million tons per year of utility SO2 emissions will be imposed and existing units will be granted allowances to emit SO2. Most of the System companies' allocated allowances will substantially exceed its expected SO2 emissions for 2000 and subsequent years, except for PSNH, which expects to purchase additional SO2 allowances from either affiliated or nonaffilated companies. New Hampshire and Massachusetts have each instituted acid rain control laws that limit SO2 emissions. The System is meeting the new SO2 limitations by using natural gas and lower sulfur coal in its plants. Under the existing fuel adjustment clauses in Connecticut, New Hampshire and Massachusetts, the System should be able to recover the additional fuel costs of compliance with the CAAA and state laws from its customers. For more information regarding a prudence hearing in New Hampshire on costs associated with PSNH's capital expenditures to comply with Phase I reduction requirements, see "Rates-New Hampshire Retail Rates-FPPAC." Management does not believe that the acid rain provisions of the CAAA will have a significant impact on the System's overall costs or rates due to the very strict limits on SO2 emissions already imposed by Connecticut, New Hampshire and Massachusetts. In addition, management believes that Title IV of the CAAA (acid rain) requirements for NOX limitations will not have a significant impact on System costs due to the more stringent NOX limitations resulting from Title I of the CAAA discussed above. EPA, Connecticut, New Hampshire and Massachusetts regulations also include other air quality standards, emission standards and monitoring and testing and reporting requirements that apply to the System's generating stations. They require that new or modified fossil fuel-fired electric generating units operate within stringent emission limits. The System could incur additional costs to meet these requirements, which costs cannot be estimated at this time. Air Toxics. Title III of the CAAA directed EPA to study air toxics and mercury emissions from fossil fired steam electric generation units to determine if they should be regulated. EPA exempted these plants from the hazardous air pollutant program pending completion of the studies, expected this year. Should EPA determine that such generating plants' emissions must be controlled to the same extent as emissions from other sources under Title III, the System could be required to make substantial capital expenditures to upgrade or replace pollution control equipment, but the amount of these expenditures cannot be readily estimated. TOXIC SUBSTANCES AND HAZARDOUS WASTE REGULATIONS PCBs. Under the federal Toxic Substances Control Act of 1976 (TSCA), EPA has issued regulations that control the use and disposal of polychlorinated biphenyls (PCBs). PCBs had been widely used as insulating fluids in many electric utility transformers and capacitors before TSCA prohibited any further manufacture of such PCB equipment. System companies have taken numerous steps to comply with these regulations and have incurred increased costs for disposal of used fluids and equipment that are subject to the regulations. In general, the System sends fluids with concentrations of PCBs equal to or higher than 500 ppm but lower than 8,500 ppm to an unaffiliated company to dispose of using a chemical treatment process. Electrical capacitors that contain PCB fluid are sent off-site to dispose of through burning in high temperature incinerators approved by EPA. The System disposes of solid wastes containing PCBs in secure chemical waste landfills. Asbestos. Federal, Connecticut, New Hampshire and Massachusetts asbestos regulations have required the System to expend significant sums on removal of asbestos, including measures to protect the health of workers and the general public and to properly dispose of asbestos wastes. Asbestos costs for the System are expected to be approximately $2 million in 1996. These costs are generally included in capital budgets. RCRA. Under the federal Resource Conservation and Recovery Act of 1976, as amended (RCRA), the generation, transportation, treatment, storage and disposal of hazardous wastes are subject to EPA regulations. Connecticut, New Hampshire and Massachusetts have adopted state regulations that parallel RCRA regulations but in some cases are more stringent. The procedures by which System companies handle, store, treat and dispose of hazardous wastes are regularly revised, where necessary, to comply with these regulations. CL&P is expecting that EPA and CDEP will approve clean closure for CL&P's Montville and Middletown Stations' former surface impoundments. For the Norwalk Harbor and Devon sites, CL&P has applied for post-closure permits and is awaiting approval from EPA and CDEP. The System estimates that it will incur approximately $2.1 million in total costs for 30-year maintenance monitoring, and closure of the container storage areas and surface impoundments for these sites in the future, but the ultimate amount will depend on EPA's final disposition. Hazardous Waste Liability. As many other industrial companies have done in the past, System companies have disposed of residues from operations by depositing or burying such materials on-site or disposing of them at off-site landfills or facilities. Typical materials disposed of include coal gasification waste, fuel oils, gasoline and other hazardous materials that might contain PCBs. It has since been determined that deposited or buried wastes, under certain circumstances, could cause groundwater contamination or create other environmental risks. The System has recorded a liability for what it believes is, based upon currently available information, its estimated environmental remediation costs for waste disposal sites for which the System companies expect to bear legal liability, and continues to evaluate the environmental impact of its former disposal practices. Under federal and state law, government agencies and private parties can attempt to impose liability on System companies for such past disposal. As of December 31, 1995, the liability recorded by the System for its estimated environmental remediation costs for known sites needing remediation including those sites described below, exclusive of recoveries from insurance or third parties, was approximately $15 million. This amount represents the minimum reserve required by the Financial Accounting Standards Board. These costs could be significantly higher if alternative remedies become necessary. Under the federal Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended, commonly known as Superfund, EPA has the authority to clean up or order cleanup of hazardous waste sites and to impose the cleanup costs on parties deemed responsible for the hazardous waste activities on the sites. Responsible parties include the current owner of a site, past owners of a site at the time of waste disposal, waste transporters and waste generators. It is EPA's position that all responsible parties are jointly and severally liable, so that any single responsible party can be required to pay the entire costs of cleaning up the site. As a practical matter, however, the costs of cleanup are usually allocated by agreement of the parties, or by the courts on an equitable basis among the parties deemed responsible, and several federal appellate court decisions have rejected EPA's position on strict joint and several liability. Superfund also contains provisions that require System companies to report releases of specified quantities of hazardous materials and require notification of known hazardous waste disposal sites. System companies are in compliance with these reporting and notification requirements. The System currently is involved in two Superfund sites in Connecticut, one in Kentucky and two in New Hampshire. The level of study of each site and the information about the waste contributed to the site by the System and other parties differs from site to site. Where reliable information is available that permits the System to make a reasonable estimate of the expected total costs of remedial action and/or the System's likely share of remediation costs for a particular site, those cost estimates are provided below. All cost estimates were made in accordance with Financial Accounting Standards Board standards where remediation costs were probable and reasonably estimable. Any estimated costs disclosed for cleaning up the sites discussed below were determined without consideration of possible recoveries from third parties, including insurance recoveries. Where the System has not accrued a liability, the costs either were not material or there was insufficient information to accurately assess the System's exposure. A coalition of major parties had previously joined "Northeast Utilities (Connecticut Light and Power)" (NU (CL&P))as defendants in connection with the Beacon Heights and Laurel Park Superfund sites in Connecticut. In 1993, the United States District Court for the District of Connecticut dismissed the coalitions' claims against NU (CL&P) and a number of other defendants. The coalitions, however, have appealed the district court's decision, which is currently pending. EPA has issued a notice of potential liability to NNECO and CYAPC as potentially responsible parties (PRPs) at the Maxey Flats nuclear waste disposal site in Fleming County, Kentucky. The System had sent a substantial volume of LLRW from Millstone 1, Millstone 2 and CY to this site. PRPs that are members of the Maxey Flats PRP Steering Committee, including System companies, and several federal government agencies, including DOE and the Department of Defense as well as the Commonwealth of Kentucky have reached a tentative settlement with EPA embodied in a consent decree. On February 8, 1996, this consent decree was filed by the United States Department of Justice in a federal district court in Kentucky for approval. NUSCO, on behalf of NNECO and CYAPC, signed the consent decree in March 1995. The System has recorded a liability for future remediation costs for this site based on its best estimate of its share of ultimate remediation costs under the tentative agreement. The System's future liability at the site has been assessed at slightly over $1 million. PSNH has committed approximately $280,000 as its share to clean up one municipal landfill Superfund site in Dover, New Hampshire and has been assessed a de minimus share at another such site in North Hampton, New Hampshire. Some additional costs may be incurred at these sites, but they are not expected to be significant. As discussed below, in addition to the remediation efforts for the above- mentioned Superfund sites, the System has been named as a PRP and is monitoring developments in connection with several state environmental actions. In 1987, CDEP published a list of 567 hazardous waste disposal sites in Connecticut. The System owns two sites on this list, which are also listed on the EPA's list of hazardous waste sites. The System has spent approximately $700,000, as of December 31, 1995, completing investigations at these sites. Both sites were formerly used by CL&P predecessor companies for the manufacture of coal gas (also known as town gas sites) from the late 1800s to the 1950s. This process resulted in the production of coal tar and creosote residues and other byproducts, which, when not sold for other industrial or commercial uses, were frequently deposited on or near the production facilities. Site investigations are being carried out to gain an understanding of the environmental and health risks of these sites. Assessments of the need for site remediation is ongoing. The level of future cleanup will be established in cooperation with CDEP, which has recently issued cleanup standards for soil and groundwater. One of the sites is a 25.8-acre site located in the south end of Stamford, Connecticut. Site investigations have located coal tar deposits covering approximately 5.5 acres and having a volume of approximately 45,000 cubic yards. A final risk assessment report for the site was completed in January 1994. Several remedial options have been evaluated to clean up the site, if necessary. The estimated costs of remediation and institutional controls range from $5 to $13 million. The second site is a 3.5-acre former coal gasification facility that currently serves as an active substation in Rockville, Connecticut. Site investigations have located creosote and other polyaromatic hydrocarbon contaminants which may require remediation. Several options are being evaluated to remediate the site if necessary. To further evaluate the health risks at the site, additional studies are being planned in coordination with the CDEP during 1996. As part of the 1989 divestiture of CL&P's gas business, site investigations were performed for properties that were transferred to Yankee Gas Services Company (Yankee Gas). CL&P agreed to accept liability for any required cleanup for the three sites it retained. These three sites include Stamford and Rockville (discussed above) and Torrington, Connecticut. At the Torrington site, investigations have been completed and the cost of any remediation, if necessary, is not expected to be material. CL&P and Yankee Gas also share a site in Winsted, Connecticut and any liability for required cleanup there. CL&P and Yankee Gas will share the costs of cleanup of sites formerly used in CL&P's gas business but not currently owned by either of them. PSNH contacted NHDES in December 1993 concerning possible coal tar contamination in Laconia, New Hampshire in Lake Opechee and the Winnipesaukee River near an area where PSNH and a second PRP formerly owned and operated a coal gasification plant from the late 1800's to the 1950's. PSNH completed a preliminary site investigation in December 1994. Results indicate that off-site coal tar/creosote contamination is present in the adjacent water body. A comprehensive site investigation is planned for 1996. The cost of remediation, if necessary, at this site is estimated at $5 to 8 million. PSNH has entered into an interim cost sharing agreement with the other PRP wherein the other PRP will bear 25 percent of this cost. A second coal gasification facility formerly owned and operated by a predecessor company to PSNH is located in Keene, New Hampshire. The NHDES has been notified of the presence of coal tar contamination and further site investigations are planned in 1996. Additional New Hampshire sites include several former manufactured gasification facilities, an inactive ash landfill located at Dover Point and a municipal landfill in Peterborough. Historic reviews of these sites are ongoing. PSNH's liability at these sites cannot be estimated at this time. In Massachusetts, System companies have been designated by the Massachusetts Department of Environmental Protection (MDEP) as PRPs for twelve sites under MDEP's hazardous waste and spill remediation program. At two sites, the System may incur remediation costs that may be material to HWP depending on the remediation requirements. At one site, HWP has been identified by MDEP as one of three PRPs in a coal tar site in Holyoke, Massachusetts. HWP owned and operated the Holyoke Gas Works from 1859 to 1902. The site is located on the east side of Holyoke, adjacent to the Connecticut River and immediately downstream of HWP's Hadley Falls Station. MDEP has designated both the land and river deposit areas as priority waste disposal sites. Due to the presence of tar patches in the vicinity of the spawning habitat of the shortnose sturgeon (SNS)-an endangered species-the National Oceanographic and Atmospheric Administration (NOAA) and National Marine Fisheries Service have taken an active role in overseeing site activities. Both MDEP and NOAA have indicated they may require the removal of tar deposits from the vicinity of the SNS spawning habitat. To date, HWP has spent approximately $405,000 for river studies and construction costs for an oil containment boom to prevent leaching hydrocarbons from entering the Hadley Falls tailrace and the Connecticut River. The total estimated costs for remediation of this site range from $2 to $3 million. The second site is a former manufactured gas plant facility in Easthampton, Massachusetts, owned by WMECO. The site is currently undergoing investigations both on-site and off-site to identify the extent of coal tar deposits. In the past, the System has received other claims from government agencies and third parties for the cost of remediating sites not currently owned by the System but affected by past System disposal activities and may receive more such claims in the future. The System expects that the costs of resolving claims for remediating sites about which it has been notified will not be material, but cannot estimate the costs with respect to sites about which it has not been notified. If the System, regulatory agencies or courts determine that remedial actions must be taken in relation to past disposal practices on property owned or used for disposal by the System in the past, the System could incur substantial costs. ELECTRIC AND MAGNETIC FIELDS In recent years, published reports have discussed the possibility of adverse health effects from electric and magnetic fields (EMF) associated with electric transmission and distribution facilities and appliances and wiring in buildings and homes. Most researchers, as well as scientific review panels considering all significant EMF epidemiological and laboratory research to date, agree that current information remains inconclusive, inconsistent and insufficient for risk assessment of EMF exposures. Based on this information management does not believe that a causal relationship has been established or that significant capital expenditures are appropriate to minimize unsubstantiated risks. NU is closely monitoring research and government policy developments. The System supports further research into the subject and is participating in the funding of the National EMF Research and Public Information Dissemination Program and other industry-sponsored studies. If further investigation were to demonstrate that the present electricity delivery system is contributing to increased risk of cancer or other health problems, the industry could be faced with the difficult problem of delivering reliable electric service in a cost- effective manner while managing EMF exposures. In addition, if the courts were to conclude that individuals have been harmed and that utilities are liable for damages, the potential monetary exposure for all utilities, including the System companies, could be enormous. Without definitive scientific evidence of a causal relationship between EMF and health effects, and without reliable information about the kinds of changes in utilities' transmission and distribution systems that might be needed to address the problem, if one is found, no estimates of the cost impacts of remedial actions and liability awards are available. The Connecticut Interagency EMF Task Force (Task Force) provided a report to the state legislature in January 1995. The Task Force advocates a policy of "voluntary exposure control," which involves providing people with information to enable them to make individual decisions about EMF exposure. Neither the Task Force, nor any Connecticut state agency, has recommended changes to the existing electrical supply system. The Connecticut Siting Council (Siting Council) previously adopted a set of EMF "best management practices," which are now considered in the justification, siting and design of new transmission lines and substations. The Siting Council also opened a generic docket in 1994 to conduct a comparative life-cycle cost analysis of overhead and underground transmission lines, which was mandated by Connecticut PA-176. This act was adopted by the General Assembly in part due to public EMF concerns. The Siting Council hired consultants in 1995 to assist with this analysis. A decision is expected in 1996. EMF has become increasingly important as a factor in facility siting decisions in many states. Several bills involving EMF were introduced in Massachusetts in 1995, with no action taken. These bills were similar to ones introduced in previous years, on which no action was taken. WMECO supported one of the bills, which would have authorized a special commission to investigate health effects, if any, of EMF, and conduct EMF measurements in schools and daycare centers near transmission lines. The Connecticut General Assembly likewise took no action on a bill introduced in 1995 concerning electromagnetic sources near schools. CL&P has been the focus of media reports charging that EMF associated with a CL&P substation and related distribution lines in Guilford, Connecticut, are linked with various cancers and other illnesses in several nearby residents. See "Item 3. Legal Proceedings," for information about two suits brought by plaintiffs who now live or formerly lived near that substation. FERC HYDRO PROJECT LICENSING Federal Power Act licenses may be issued for hydroelectric projects for terms of up to 50 years as determined by FERC. Upon the expiration of a license, any hydroelectric project so licensed is subject to reissuance by FERC to the existing licensee or to others upon payment to the licensee of the lesser of fair value or the net investment in the project plus severance damages less certain amounts earned by the licensee in excess of a reasonable rate of return. The System companies hold FERC licenses for 19 hydroelectric projects aggregating approximately 1,142 MW of capacity, located in Connecticut, Massachusetts and New Hampshire. Four of the System licenses expired on December 31, 1993 (WMECO's Gardners Falls project and PSNH's Ayers Island, Smith and Gorham projects). On August 1, 1994, FERC issued new 30-year licenses to PSNH for the continued operation of the Smith and Gorham projects. Although rehearing requests on these new licenses are pending with FERC, it is anticipated that it will be economic for PSNH to continue operation of these projects. FERC has issued annual licenses allowing the Gardners Falls and Ayers Island projects to continue operations pending completion of the relicensing process. It is not known whether FERC will require any substantial changes in the operation or design of these two projects if and when it issues new licenses. The license for HWP's Holyoke Project expires in late 1999. The relicensing process for this project began in 1994. On November 29, 1995, the Holyoke Gas and Electric Department initiated the process of applying to FERC for the license on the Holyoke Project. Absent significant differences in competing license applications, the Federal Power Act gives a preference to an existing licensee for the new license. Applications must be filed with FERC by August 1997. CL&P's FERC licenses for operation of the Falls Village and Housatonic Hydro Projects expire in 2001. The relicensing process for these projects will begin later in 1996. FERC has issued a notice indicating that it has authority to order project licensees to decommission projects that are no longer economic to operate. FERC has not required any such project decommissioning to date; the potential costs of decommissioning a project, however, could be substantial. It is likely that this FERC decision will be appealed at an appropriate time. EMPLOYEES As of December 31, 1995, the System companies had 9,051 full and part-time employees on their payrolls, of which 2,285 were employed by CL&P, 1,339 by PSNH, 533 by WMECO, 101 by HWP, 1,333 by NNECO, 2,589 by NUSCO and 871 by NAESCO. NU, NAEC and Charter Oak have no employees. In 1995 and early 1996, the System implemented a program to reduce the nuclear organization's total workforce by approximately 220 employees, which included both early retirements and involuntary terminations. The pretax cost of the program was approximately $8.7 million. Approximately 2,275 employees of CL&P, PSNH, WMECO, NAESCO and HWP are covered by nine union agreements, which expire between May 31, 1996 and October 1, 1998. Approximately 370 union employees of WMECO and HWP returned to work on September 1, 1995, ending a strike that began on May 25, 1995. ITEM 2. Properties The physical properties of the System are owned or leased by subsidiaries of NU. CL&P's principal plants and other properties are located either on land which is owned in fee or on land, as to which CL&P owns perpetual occupancy rights adequate to exclude all parties except possibly state and federal governments, which has been reclaimed and filled pursuant to permits issued by the United States Army Corps of Engineers. The principal properties of PSNH are held by it in fee. In addition, PSNH leases space in an office building under a 30-year lease expiring in 2002. WMECO's principal plants and a major portion of its other properties are owned in fee, although one hydroelectric plant is leased. NAEC owns a 35.98 percent interest in Seabrook 1 and approximately 719 acres of exclusion area land located around the unit. In addition, CL&P, PSNH, and WMECO have certain substation equipment, data processing equipment, nuclear fuel, nuclear control room simulators, vehicles, and office space that are leased. With few exceptions, the System companies' lines are located on or under streets or highways, or on properties either owned or leased, or in which the company has appropriate rights, easements, or permits from the owners. CL&P's properties are subject to the lien of its first mortgage indenture. PSNH's properties are subject to the lien of its first mortgage indenture. In addition, any PSNH outstanding revolving credit agreement borrowings are secured by a second lien, junior to the lien of the first mortgage indenture, on PSNH's property located in New Hampshire. WMECO's properties are subject to the lien of its first mortgage indenture. NAEC's First Mortgage Bonds are secured by a lien on the Seabrook 1 interest described above, and all rights of NAEC under the Seabrook Power Contract. In addition, CL&P's and WMECO's interests in Millstone 1 are subject to second liens for the benefit of lenders under agreements related to pollution control revenue bonds. Various of these properties are also subject to minor encumbrances which do not substantially impair the usefulness of the properties to the owning company. The System companies' and NAEC's properties are well maintained and are in good operating condition. Transmission and Distribution System At December 31, 1995, the System companies owned 103 transmission and 427 distribution substations that had an aggregate transformer capacity of 25,000,646 kilovoltamperes (kVa) and 9,134,229 kVa, respectively; 3,057 circuit miles of overhead transmission lines ranging from 69 kilovolt (kV) to 345 kV, and 192 cable miles of underground transmission lines ranging from 69 kV to 138 kV; 32,593 pole miles of overhead and 1,912 conduit bank miles of underground distribution lines; and 391,562 line transformers in service with an aggregate capacity of 16,422,713 kVa. Electric Generating Plants As of December 31, 1995, the electric generating plants of the System companies and NAEC, and the System companies' entitlements in the generating plants of the three operating Yankee regional nuclear generating companies were as follows (See "Item 1. Business - Electric Operations, Nuclear Generation" for information on ownership and operating results for the year.): Claimed Year Capability* Owner Plant Name (Location) Type Installed (kilowatts) - ----- --------------------- ---- --------- ----------- CL&P Millstone (Waterford, CT) Unit 1 Nuclear 1970 524,637 Unit 2 Nuclear 1975 708,345 Unit 3 Nuclear 1986 606,453 Seabrook (Seabrook, NH) Nuclear 1990 47,013 CT Yankee (Haddam, CT) Nuclear 1968 201,204 ME Yankee (Wiscasset, ME) Nuclear 1972 94,832 VT Yankee (Vernon, VT) Nuclear 1972 45,353 --------- Total Nuclear-Steam Plants (7 units) 2,227,837 Total Fossil-Steam Plants (9 units) 1954-73 1,776,400 Total Hydro-Conventional (25 units) 1903-55 98,930 Total Hydro-Pumped Storage (7 units) 1928-73 905,150 Total Internal Combustion (15 units) 1966-86 390,450 --------- Total CL&P Generating Plant (63 units) 5,398,767 ========= PSNH Millstone (Waterford, CT) Unit 3 Nuclear 1986 32,624 CT Yankee (Haddam, CT) Nuclear 1968 29,160 ME Yankee (Wiscasset, ME) Nuclear 1972 39,514 VT Yankee (Vernon, VT) Nuclear 1972 19,068 --------- Total Nuclear-Steam Plants (4 units) 120,366 Total Fossil-Steam Plants (7 units) 1952-78 1,004,065 Total Hydro-Conventional (20 units) 1917-83 67,510 Total Internal Combustion (5 units) 1968-70 108,450 --------- Total PSNH Generating Plant (36 units) 1,300,391 ========= WMECO Millstone (Waterford, CT) Unit 1 Nuclear 1970 123,063 Unit 2 Nuclear 1975 166,155 Unit 3 Nuclear 1986 140,216 CT Yankee (Haddam, CT) Nuclear 1968 55,404 ME Yankee (Wiscasset, ME) Nuclear 1972 23,708 VT Yankee (Vernon, VT) Nuclear 1972 11,948 --------- Total Nuclear-Steam Plants (6 units) 520,494 Total Fossil-Steam Plants (1 unit) 1957 107,000 Total Hydro-Conventional (27 units) 1904-34 110,910** Total Hydro-Pumped Storage (4 units) 1972-73 205,200 Total Internal Combustion (3 units) 1968-69 63,500 --------- Total WMECO Generating Plant(41 units) 1,007,104 ========= Claimed Year Capability* Owner Plant Name (Location) Type Installed (kilowatts) - ----- --------------------- ---- --------- ----------- NAEC Seabrook (Seabrook, NH) Nuclear 1990 416,672 ========= HWP Mt. Tom (Holyoke, MA) Fossil-Steam 1960 147,000 Total Hydro-Conventional (15 units) 1905-83 43,560 --------- Total HWP Generating Plant (16 units) 190,560 ========= NU System Millstone (Waterford, CT) Unit 1 Nuclear 1970 647,700 Unit 2 Nuclear 1975 874,500 Unit 3 Nuclear 1986 779,293 Seabrook (Seabrook, NH) Nuclear 1990 463,685 CT Yankee (Haddam, CT) Nuclear 1968 285,768 ME Yankee (Wiscasset, ME) Nuclear 1972 158,054 VT Yankee (Vernon, CT) Nuclear 1972 76,369 --------- Total Nuclear-Steam Plants (7 units) 3,285,369 Total Fossil-Steam Plants (18 units) 1952-78 3,034,465 Total Hydro-Conventional (87 units) 1903-83 320,910** Total Hydro-Pumped Storage (7 units) 1928-73 1,110,350 Total Internal Combustion (23 units) 1966-86 562,400 --------- Total NU System Generating Plant Including Regional Yankees (142 units) 8,313,494 ========= Excluding Regional Yankees (139 units) 7,793,303 ========= *Claimed capability represents winter ratings as of December 31, 1995. **Total Hydro-Conventional capability includes the Cobble Mtn. plant's 33,960 kW which is leased from the City of Springfield, MA. Franchises NU's operating subsidiaries hold numerous franchises in the territories served by them. For more information regarding recent judicial, regulatory and legislative decisions and initiatives that may affect the terms under which the System companies provide electric service in their franchised territories, see "Connecticut Retail Rates - Electric Industry Restructuring in Connecticut;" "New Hampshire Retail Rates - Electric Industry Restructuring in New Hampshire;" and "Massachusetts Retail Rates - Electric Industry Restructuring in Massachusetts," and "Item 3. Legal Proceedings." CL&P. Subject to the power of alteration, amendment or repeal by the General Assembly of Connecticut and subject to certain approvals, permits and consents of public authority and others prescribed by statute, CL&P has, subject to certain exceptions not deemed material, valid franchises free from burdensome restrictions to sell electricity in the respective areas in which it is now supplying such service. In addition to the right to sell electricity as set forth above, the franchises of CL&P include, among others, rights and powers to manufacture, generate, purchase, transmit and distribute electricity, to sell electricity at wholesale to other utility companies and municipalities and to erect and maintain certain facilities on public highways and grounds, all subject to such consents and approvals of public authority and others as may be required by law. The franchises of CL&P include the power of eminent domain. PSNH. Subject to the power of alteration, amendment or repeal by the General Court (legislature) of the State of New Hampshire and subject to certain approvals, permits and consents of public authority and others prescribed by statute, PSNH has, subject to certain exceptions not deemed material, valid franchises free from burdensome restrictions to sell electricity in the respective areas in which it is now supplying such service. In addition to the right to sell electricity as set forth above, the franchises of PSNH include, among others, rights and powers to manufacture, generate, purchase, transmit and distribute electricity, to sell electricity at wholesale to other utility companies and municipalities and to erect and maintain certain facilities on certain public highways and grounds, all subject to such consents and approvals of public authority and others as may be required by law. The franchises of PSNH include the power of eminent domain. NNECO. Subject to the power of alteration, amendment or repeal by the General Assembly of Connecticut and subject to certain approvals, permits and consents of public authority and others prescribed by statute, NNECO has a valid franchise free from burdensome restrictions to sell electricity to utility companies doing an electric business in Connecticut and other states. In addition to the right to sell electricity as set forth above, the franchise of NNECO includes, among others, rights and powers to manufacture, generate and transmit electricity, and to erect and maintain facilities on certain public highways and grounds, all subject to such consents and approvals of public authority and others as may be required by law. WMECO. WMECO is authorized by its charter to conduct its electric business in the territories served by it, and has locations in the public highways for transmission and distribution lines. Such locations are granted pursuant to the laws of Massachusetts by the Department of Public Works of Massachusetts or local municipal authorities and are of unlimited duration, but the rights thereby granted are not vested. Such locations are for specific lines only, and, for extensions of lines in public highways, further similar locations must be obtained from the Department of Public Works of Massachusetts or the local municipal authorities. In addition, WMECO has been granted easements for its lines in the Massachusetts Turnpike by the Massachusetts Turnpike Authority. HWP and Holyoke Power and Electric Company (HP&E). HWP, and its wholly owned subsidiary HP&E, are authorized by their charters to conduct their businesses in the territories served by them. HWP's electric business is subject to the restriction that sales be made by written contract in amounts of not less than 100 horsepower, except for municipal customers in the counties of Hampden or Hampshire, Massachusetts and except for customers who occupy property in which HWP has a financial interest, by ownership or purchase money mortgage. HWP also has certain dam and canal and related rights, all subject to such consents and approvals of public authorities and others as may be required by law. The two companies have locations in the public highways for their transmission and distribution lines. Such locations are granted pursuant to the laws of Massachusetts by the Department of Public Works of Massachusetts or local municipal authorities and are of unlimited duration, but the rights thereby granted are not vested. Such locations are for specific lines only and, for extensions of lines in public highways, further similar locations must be obtained from the Department of Public Works of Massachusetts or the local municipal authorities. The two companies have no other utility franchises. NAEC. NAEC is authorized by the NHPUC to own and operate its interest in Seabrook 1. ITEM 3. LEGAL PROCEEDINGS 1. Litigation Relating to Electric and Magnetic Fields In December 1991, NU and CL&P were sued in Connecticut Superior Court by Melissa Bullock, a nineteen-year old woman, and her mother, Suzanne Bullock, both residents of 28 Meadow Street in Guilford, Connecticut. The plaintiffs allege that they have lived in close proximity to CL&P's Meadow Street substation and distribution lines since 1979. The suit claims that Melissa Bullock suffers from a form of brain cancer and related physical and psychological injuries, which were "brought on as a result of exposure in her home to electromagnetic radiation generated by the defendants." Suzanne Bullock claims various physical and psychological injuries, and a diminution in the value of her property. The various counts against NU and CL&P include allegations of negligence, product liability, nuisance, unfair trade practices and strict liability. The suit seeks monetary damages, both compensatory and punitive, in as-yet unspecified amounts, as well as an injunction to cease emission of "dangerous levels" of electric and magnetic fields (EMF) into the plaintiffs' home. The plaintiffs are represented in part by counsel with a nationwide emphasis on similar litigation, and management considers this lawsuit to be a test case. The case is presently in the pre-trial discovery process. Trial is not anticipated until 1997. In January 1992, a related lawsuit by two other plaintiffs also alleging cancer from EMF emanating from CL&P's Meadow Street substation and distribution lines was served on CL&P and NU. The plaintiffs are represented by the same counsel as the Bullocks, and the claims are nearly identical to the Bullocks' suit. This case is also in the pretrial discovery process; a trial date is not yet known. Management believes that the allegations that EMF caused or contributed to the plaintiffs' illnesses are not supported by current scientific studies. NU and CL&P intend to defend the lawsuits vigorously. For information on EMF studies and state and federal initiatives, see "Item 1. Business - Regulatory and Environmental Matters - Electric and Magnetic Fields." 2. Southeastern Connecticut Regional Resources Recovery Authority (SCRRRA) - Application of the Municipal Rate This matter involves three separate disputes over the rates that apply to CL&P's purchases of the generation of the SCRRRA project in Preston, Connecticut. Municipal Rate Litigation: In 1990, CL&P initiated a challenge in federal district court to the DPUC's approval of an electricity purchase contract for the SCRRRA project under Connecticut's so-called "municipal rate law." Under this law, CL&P would be required to purchase a portion of the electricity from the resource recovery facility at a rate equal to the retail rate that CL&P charges municipalities for electricity ("municipal rate"), which is significantly higher than CL&P's avoided costs. The district court subsequently ordered the parties to seek FERC's resolution of this matter. On January 11, 1995, FERC ruled that a state cannot require an electric utility to enter into a contract paying a qualifying facility more than the utility's avoided costs. On April 12, 1995, FERC denied several petitions for rehearing and reaffirmed its ruling. SCRRRA and other participants in the FERC proceeding have appealed FERC's ruling to the United States Court of Appeals. FERC moved to dismiss the appeal on jurisdictional grounds, which motion is still pending. Should CL&P ultimately prevail, the benefits to CL&P customers would be approximately $14.5 million. Non-Participant Towns: CL&P also contested SCRRRA's claim that CL&P must pay the municipal rate for the portion of the project's electricity that is derived from the trash of towns that are not long-term participants in the project. On April 20, 1994, the DPUC granted SCRRRA's request that the municipal rate be made applicable to the non-participant's portion of electricity. On June 9, 1994, CL&P filed an appeal of the DPUC's ruling in the Hartford Superior Court. A total of approximately $3.5 million is in dispute for the years 1992 through 1994. The rate CL&P would be required to pay would also be substantially higher in later years if the DPUC's ruling is upheld. On February 6, 1995, the Superior Court granted the SCRRRA's motion to stay this proceeding until FERC issues a final decision on the municipal rate law. This case could be moot once the FERC decision is final. Excess Capacity: CL&P also contested SCRRRA's claim that CL&P must purchase, at the applicable contract rates (each of which is higher than CL&P's current avoided costs), any excess of the project's generation above 13.85 MW per hour. On May 3, 1994, the Connecticut Appellate Court affirmed a Superior Court ruling that the DPUC should decide this issue. On September 20, 1995, the DPUC ruled that the project's electricity sales under the contract are limited to no more than an average of 13.85 MW in any month. If the current level of plant operations continues, CL&P's total savings would be in the range of $11.4 million (present worth basis) over the contract's entire term. In November 1995, CL&P and SCRRRA each filed appeals of the DPUC decision in Hartford Superior Court. CL&P maintains that its purchase obligation is limited to 13.85 MW applied on an hourly basis (instead of on a monthly basis), while SCRRRA maintains that CL&P's purchase obligation is not limited to 13.85 MW. These appeals are now in the briefing stage, after which the case will wait assignment to a judge for oral argument. 3. CL&P's 1992-1993 Retail Rate Case In June 1993, the DPUC issued a decision approving a multi-year rate plan for CL&P. Two appeals have been filed from the 1993 Decision, one by CL&P and the other by the Connecticut Office of Consumer Counsel (OCC) and the City of Hartford (City). The two appeals were consolidated, and in May 1994, the City's appeal was dismissed by the Hartford Superior Court on jurisdictional grounds. The City appealed that dismissal to the Connecticut Appellate Court. The Supreme Court of Connecticut transferred the jurisdictional issue to itself and, in August 1995, affirmed the lower court's dismissal of the City. The City filed several post-decision motions, which the Supreme Court subsequently denied on September 13, 1995. The OCC's appeal is now proceeding in Hartford Superior Court. The other appeal, CL&P's challenge to certain aspects of the rate decision, is also proceeding in Hartford Superior Court. 4. Connecticut DPUC - CL&P's Petition for Declaratory Ruling Regarding Proposed Retail Sales of Electricity by Texas-Ohio Power, Inc. (TOP) On August 3, 1995, CL&P filed a petition for declaratory rulings with the DPUC to determine whether TOP, which built a small congeneration plant in Manchester, Connecticut, can sell electricity from the facility to two CL&P retail customers in Manchester. The plant is located on property leased from one of the two customers. TOP expected to sell electricity to the other customer, a manufacturing facility located on adjacent property, via a 500 foot distribution line. TOP is a unit of Texas-Ohio Gas, a Houston-based gas pipeline operator and marketer. CL&P's petition pointed to the fact that CL&P has a franchised right to sell electricity in Manchester and TOP has not been authorized to compete by engaging in retail electricity sales within that territory. The petition also requested that the DPUC rule that, under Connecticut statutes, as well as judicial and DPUC decisions interpreting Connecticut law, TOP is prohibited from selling electricity at retail in Connecticut. On December 4, 1995, CL&P informed the DPUC that it had entered into a flex rate contract with one of the two retail customers thereby retaining them as a customer and mooting the need for the DPUC to decide the issue of sales by a private power producer to an off-site customer. However, on December 6, 1995, the DPUC acted on CL&P's original petition and issued a final decision denying all of the specific declaratory rulings requested by CL&P. The DPUC concluded that, because TOP's project would not use the public streets, it did not require specific legislative authorization to make retail sales of electricity. Further, the DPUC found that specific statutory prohibitions against selling electricity at retail did not apply to TOP. On January 17, 1996, CL&P appealed the DPUC's decision to the Hartford Superior Court. CL&P's appeal asks the Court to reverse the DPUC decision, insofar as it concludes that TOP is not prohibited from making retail electric sales in Connecticut, and to vacate the portions of the decision that deal with electricity sales to off-site customers. NU cannot predict the outcome of this proceeding or its ultimate effect on the System. 5. FERC - PSNH Acquisition Case In 1992, FERC's approval of NU's acquisition of PSNH was appealed to the United States Court of Appeals for the First Circuit (Court). The Court affirmed the decision approving the merger but ordered FERC to address whether, if FERC had applied a more stringent "public interest standard" to the Seabrook power contract, any modifications would have been necessary. Purporting to apply this standard, FERC reaffirmed certain modifications to the contract, interpreting the standard liberally to allow it to intervene in contracts on behalf of non-parties to the contract. NU requested rehearing, arguing that FERC had not applied the appropriate standard, which request was denied by FERC in July 1994. In September 1994, NU filed a Petition for Review with the First Circuit Court of Appeals concerning FERC's application of a "public interest standard" to the Seabrook Power Contract. On May 23, 1995, the Court affirmed FERC's order. The Court held that FERC had correctly applied the "public interest standard" to modify terms of the contract. The order affects only future changes to the Seabrook Power Contract, including changes to decommissioning charges and rate of return. 6. New Hampshire Office of Consumer Advocate and the Campaign for Ratepayers Rights Case On November 1, 1995, the New Hampshire Office of Consumer Advocate (OCA) and the Campaign for Ratepayers Rights filed suit in Superior Court against the NHPUC seeking a declaratory ruling that special contracts entered into by and between PSNH and certain retail customers are prohibited by the 1989 rate agreement between PSNH and the State of New Hampshire (Rate Agreement). The petition is based on an alleged inconsistency between the New Hampshire statute that allows special contracts agreed to by a utility and a customer when deemed appropriate by the NHPUC and the legislation accepting the Rate Agreement wherein PSNH received protection against NHPUC actions fixing rates other than in the manner agreed upon in the Rate Agreement. The petition alleges that the special contracts constitute a breach of the Rate Agreement by PSNH, thereby estopping PSNH from claiming benefits under the Rate Agreement. On December 11, 1995, the Superior Court denied a request for an emergency injunction which would have prevented the NHPUC from authorizing any further special contracts between PSNH and large industrial customers. The New Hampshire Attorney General is representing the NHPUC in this action. However, OCA disputes the New Hampshire Attorney General's authority to provide such representation. While NU believes this proceeding should be dismissed on procedural grounds, it cannot predict the outcome of this proceeding or its ultimate effect on the System. 7. Tax Litigation In 1991, per Connecticut statute, the Town of Haddam performed a town-wide revaluation of the Connecticut Yankee (CY) property in that town. Based on the report of the engineering firm hired by the town to perform the revaluation, Haddam determined that the full fair-market value of the property, as of October 1, 1991, was $840 million. At that time, CY's net-book value was $245 million. In March 1992, CY appealed this excessive valuation to Haddam's Board of Tax Review, which subsequently rejected CY's appeal. CY then, in July 1992, appealed to the Middletown Superior Court. At issue is the fair market value of utility property. NU believes that the assessments should be based on a fair market value that approximates net book cost. This is the assessment level that taxing authorities are predominantly using throughout Connecticut. However, Haddam advocates a method that approximates reproduction costs. Two expert appraisals of the property were prepared for CY's use in the appeal - 1) Stone & Webster's determination that the full fair-market value of CY's property, as of October 1, 1991, was $230 million and 2) AUS Consulting of Milwaukee's finding of a value of $219.4 million. Trial began in Middletown Superior Court in early December 1995, and a decision is expected during the first half of 1996. NU cannot predict the outcome of this proceeding or its ultimate effect on the System. 8. Other Legal Proceedings The following sections of Item 1 "Business" discuss additional legal proceedings: See "Competition and Marketing" for information regarding a DPUC proceeding on guidelines for CL&P's flexible rate agreements; "Wholesale Marketing" for information on a PSNH complaint filed against NHEC at the FERC; "Rates" for information about CL&P's rate and fuel clause adjustment clause proceedings, NHPUC proceedings involving Freedom Energy Company, New Hampshire's LEEPA statute and PSNH's franchise rights, and the Seabrook Power Contract; "Electric Operations -- Generation and Transmission" for information about proceedings relating to power and transmission issues; "Electric Operations -- Nuclear Generation" for information related to nuclear plant performance, nuclear fuel enrichment pricing, high-level and low-level radioactive waste disposal, decommissioning matters and NRC regulation; "Regulatory and Environmental Matters" for information about proceedings involving surface water and air quality, toxic substances and hazardous waste, electric and magnetic fields, licensing of hydroelectric projects, and other matters. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS No Event that would be described in response to this item occurred with respect to NU, CL&P, WMECO, PSNH or NAEC. PART II Item 5. Market for the Registrants' Common Equity and Related Shareholder Matters NU. The common shares of NU are listed on the New York Stock Exchange. The ticket symbol is "NU," although it is frequently presented as "Noeast Util" and/or "NE Util" in various financial publications. The high and low sales prices for the past two years, by quarters, are shown below. Year Quarter High Low ---- ------- ---- --- 1995 First $24 1/4 21 Second 23 7/8 21 3/8 Third 24 1/2 22 Fourth 25 3/8 23 1/2 1994 First $25 3/4 23 Second 24 7/8 21 1/4 Third 24 5/8 20 3/8 Fourth 23 3/8 21 1/4 As of January 31, 1996, there were 129,943 common shareholders of record of NU. As of the same date, there were a total of 135,985,056 common shares issued, including approximately 8.5 million unallocated ESOP shares held in the ESOP trust. NU declared and paid quarterly dividends of $0.44 in 1995 and $0.44 in 1994. On January 23, 1996, the Board of Trustees declared a dividend of $0.44 per share, payable on March 31, 1996 to holders of record on March 1, 1996. The declaration of future dividends may vary depending on capital requirements and income as well as financial and other conditions existing at the time. Information with respect to dividend restrictions for NU and its subsidiaries is contained in Item 1. Business under the caption "Financing Program - Financing Limitations" and in Note (b) to the "Consolidated Statements of Common Shareholders' Equity" on page 30 of NU's 1996 Annual Report to Shareholders, which information is incorporated herein by reference. CL&P, PSNH, WMECO, and NAEC. The information required by this item is not applicable because the common stock of CL&P, PSNH, WMECO, and NAEC is held solely by NU. Item 6. Selected Financial Data NU. Reference is made to information under the heading "Selected Consolidated Financial Data" contained on page 45 of NU's 1995 Annual Report to Shareholders, which information is incorporated herein by reference. CL&P. Reference is made to information under the heading "Selected Financial Data" contained on page 35 of CL&P's 1995 Annual Report, which information is Incorporated herein by reference. PSNH. Reference is made to information under the heading "Selected Financial Data" contained on pages 32 and 33 of PSNH's 1995 Annual Report, which information is incorporated herein by reference. WMECO. Reference is made to information under the heading "Selected Financial Data" contained on page 33 of WMECO's 1995 Annual Report, which information is incorporated herein by reference. NAEC. Reference is made to information under the heading "Selected Financial Data" contained on page 21 of NAEC's 1995 Annual Report, which information is incorporated herein by reference. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations NU. Reference is made to information under the heading "Management's Discussion and Analysis" contained on pages 15 through 21 in NU's 1995 Annual Report to Shareholders, which information is incorporated herein by reference. CL&P. Reference is made to information under the heading "Management's Discussion and Analysis of Financial Condition and Results of Operations" contained on pages 29 through 34 in CL&P's 1995 Annual Report, which information is incorporated herein by reference. PSNH. Reference is made to information under the heading "Management's Discussion and Analysis of Financial Condition and Results of Operations" contained on pages 26 through 31 in PSNH's 1995 Annual Report, which information is incorporated herein by reference. WMECO. Reference is made to information under the heading "Management's Discussion and Analysis of Financial Condition and Results of Operations" contained on pages 27 through 32 in WMECO's 1995 Annual Report, which information is incorporated herein by reference. NAEC. Reference is made to information under the heading "Management's Discussion and Analysis of Financial Condition and Results of Operations" contained on pages 17 through 20 in NAEC's 1995 Annual Report, which information is incorporated herein by reference. Item 8. Financial Statements and Supplementary Data NU. Reference is made to information under the headings "Company Report," "Report of Independent Public Accountants," "Consolidated Statements of Income," "Consolidated Statements of Cash Flows," "Consolidated Statements of Income Taxes," "Consolidated Balance Sheets," "Consolidated Statements of Capitalization," "Consolidated Statements of Common Shareholders' Equity," "Notes to Consolidated Financial Statements," and "Consolidated Statements of Quarterly Financial Data" contained on pages 22 through 44 in NU's 1995. Annual Report to Shareholders, which information, which information is incorporated herein by reference. CL&P. Reference is made to information under the headings "Consolidated Balance Sheets," "Consolidated Statements of Income," "Consolidated Statements of Cash Flows," "Consolidated Statements of Common Stockholder's Equity," "Notes to Consolidated Financial Statements," "Report of Independent Public Accountants," and "Statements of Quarterly Financial Data" contained on pages 2 through 28 and page 35 in CL&P's 1995 Annual Report, which information is incorporated herein by reference. PSNH. Reference is made to information under the headings "Balance Sheets," "Statements of Income," "Statements of Cash Flows," "Statements of Common Equity," "Notes to Financial Statements," "Report of Independent Public Accountants," "Independent Auditors' Report," and "Statements of Quarterly Financial Data" contained on pages 2 through 25 and page 34 in PSNH's 1995 Annual Report, which information is incorporated herein by reference. WMECO. Reference is made to information under the headings "Balance Sheets," "Statements of Income," "Statements of Cash Flows," "Statements of Common Stockholder's Equity," "Notes to Financial Statements," "Report of Independent Public Accountants," and "Statements of Quarterly Financial Data" contained on pages 2 through 26 and page 33 in WMECO's 1995 Annual Report, which information is incorporated herein by reference. NAEC. Reference is made to information under the headings "Balance Sheet," "Statement of Income," "Statement of Cash Flows," "Statement of Common Stockholder's Equity," "Notes to Financial Statements," "Report of Independent Public Accountants," and "Statement of Quarterly Financial Data" contained on pages 2 through 16 and page 21 in NAEC's 1995 Annual Report which information is incorporated herein by reference. Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure No event that would be described in response to this item has occurred with respect to NU, CL&P, PSNH, WMECO, or NAEC. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS NU. In addition to the information provided below concerning the executive officers of NU, incorporated herein by reference is the information contained in the sections "Proxy Statement," "Committee Composition and Responsibility," "Common Stock Ownership of Certain Beneficial Owners," "Common Stock Ownership of Management," "Compensation of Trustees," "Summary Compensation Table," "Pension Benefits," and "Report on Executive Compensation" of the definitive proxy statement for solicitation of proxies by NU's Board of Trustees, dated April 1, 1996 and filed with the Commission pursuant to Rule 14a-6 under the Securities Exchange Act of 1934 (the Act). First First Positions Elected Elected Name Held an Officer a Trustee - ----------------------- --------- ---------- --------- Bernard M. Fox CHB, P, CEO, T 05/01/83 05/20/86 CL&P. First First Positions Elected Elected Name Held an Officer a Director - ----------------------- --------- ---------- ---------- Robert G. Abair D - 01/01/89 Robert E. Busch P, D 06/01/87 06/01/87 John H. Forsgren EVP, CFO 02/01/96 - Bernard M. Fox CH, D 05/15/81 05/01/83 William T. Frain, Jr. D - 02/01/94 Cheryl W. Grise SVP, CAO, D 06/01/91 01/01/94 Barry Ilberman VP 02/01/89 - John B. Keane VP, TR, D 08/01/92 08/01/92 Francis L. Kinney SVP 04/24/74 - Hugh C. MacKenzie P, D 07/01/88 06/06/90 John J. Roman VP, CONT 04/01/92 - Robert P. Wax VP, SEC, GC 08/01/92 - PSNH. First First Positions Elected Elected Name Held an Officer a Director - ----------------------- --------- ---------- ---------- Robert E. Busch P 06/05/92 John C. Collins D - 10/19/92 John H. Forsgren EVP, CFO 02/01/96 - Bernard M. Fox CH, CEO, D 06/05/92 06/05/92 William T. Frain, Jr. P, COO, D 03/18/71 02/01/94 Cheryl W. Grise D 02/06/95 Barry Ilberman VP 07/01/94 - Gerald Letendre D - 10/19/92 Hugh C. MacKenzie D - 02/01/94 Jane E. Newman D - 10/19/92 John J. Roman VP, CONT 04/01/92 - Robert P. Wax VP,SEC,GC,D 08/01/92 02/01/93 WMECO. First First Positions Elected Elected Name Held an Officer a Director - ----------------------- --------- ---------- ---------- Robert G. Abair VP, CAO, D 09/06/88 01/01/89 Robert E. Busch P, D 06/01/87 06/01/87 John H. Forsgren EVP, CFO 02/01/96 - Bernard M. Fox C, D 05/15/81 05/01/83 William T. Frain, Jr. D - 02/01/94 Cheryl W. Grise SVP, D 06/01/91 01/01/94 Barry Ilberman VP 02/01/89 - John B. Keane VP, TR, D 08/01/92 08/01/92 Francis L. Kinney SVP 04/24/74 - Hugh C. MacKenzie P, D 07/01/88 06/06/90 John J. Roman VP, CONT 04/01/92 - Robert P. Wax VP, SEC, AC, GC 08/01/92 - NAEC. First First Positions Elected Elected Name Held an Officer a Director - ----------------------- --------- ---------- ---------- Robert E. Busch P, D 10/21/91 10/16/91 Ted C. Feigenbaum EVP, CNO, D 10/21/91 10/16/91 John H. Forsgren EVP, CFO 02/01/96 - Bernard M. Fox C, CEO, D 10/21/91 10/16/91 William T. Frain, Jr. D - 02/01/94 Cheryl W. Grise SVP, CAO, D 10/21/91 01/01/94 Barry Ilberman VP 01/29/92 - Francis L. Kinney SVP 10/21/91 - John B. Keane VP, TR, D 08/01/92 08/01/92 Hugh C. MacKenzie D - 01/01/94 John J. Roman VP, CONT 04/01/92 - Robert P. Wax VP, SEC, GC 08/01/92 - Key: AC - Assistant Clerk CAO - Chief Administrative Office EVP - Executive Vice President CEO - Chief Executive Officer GC - General Counsel CFO - Chief Financial Officer P - President CH - Chairman SEC - Secretary CHB - Chairman of the Board SVP - Senior Vice President CNO - Chief Nuclear Officer T - Trustee COO - Chief Operating Officer TR - Treasurer CONT - Controller VP - Vice President D - Director Name Age Business Experience During Past 5 Years - ------------------------ --- --------------------------------------- Robert G. Abair (1) 57 Elected Vice President and Chief Administrative Officer of WMECO in 1988. Robert E. Busch (2) 49 Elected President-Energy Resources Group of NU, CL&P, PSNH and WMECO February, 1996 and President of NAEC in 1994; previously Executive Vice President and Chief Financial Officer of NU, CL&P, PSNH, and WMECO since 1992; Executive Vice President and Chief Financial Officer of NAEC since 1992; Senior Vice President and Chief Financial Officer of NU, CL&P and WMECO since 1990. John C. Collins (3) 51 Executive Vice President, Lahey Clinic, since 1995. Previously Chief Executive Officer, The Hitchcock Clinic, Dartmouth - Hitchcock Medical Center from 1977 to 1995. Ted C. Feigenbaum (4) 45 Elected Executive Vice President and Chief Nuclear Officer of NAEC February, 1996; previously Senior Vice President of NAEC since 1991; Senior Vice President and Chief Nuclear Officer of PSNH June, 1992 to August, 1992; President and Chief Executive Officer - New Hampshire Yankee Division of PSNH October, 1990 to June, 1992 and Chief Nuclear Production Officer of PSNH January, 1990 to June, 1992. John H. Forsgren 49 Elected Executive Vice President and Chief Financial Officer of NU, CL&P, PSNH, WMECO and NAEC February, 1996; previously Managing Director of Chase Manhattan Bank since 1995; Executive Vice President of Sun International Investments, LTD since 1994; and Senior Vice President-Chief Financial Officer of Euro Disney, The Walt Disney Company. Bernard M. Fox (5) 53 Elected Chairman of the Board, President and Chief Executive Officer of NU, Chairman of CL&P, PSNH, WMECO and NAEC, and Chief Executive Officer of PSNH and NAEC in 1995; previously Vice Chairman of CL&P and WMECO, and Vice Chairman and Chief Executive Officer of NAEC since 1994; Chief Executive Officer of NU, CL&P, PSNH, WMECO and NAEC in 1993; President and Chief Operating Officer of NU, CL&P and WMECO in 1990 and NAEC since 1991; Vice Chairman of PSNH since 1992. William T. Frain, Jr. (6)54 Elected President and Chief Operating Officer of PSNH in 1994; previously Senior Vice President of PSNH since 1992; previously Vice President and Treasurer of PSNH since 1991. Cheryl W. Grise 43 Elected Senior Vice President and Chief Administrative Officer of CL&P, PSNH and NAEC, and Senior Vice President of WMECO in 1995; previously Senior Vice President-Human Resources and Administrative Services of CL&P, WMECO and NAEC since 1994; Vice President-Human Resources of NAEC since 1992 and of CL&P and WMECO since 1991. Barry Ilberman 46 Elected Vice President-Corporate and Environmental Affairs of CL&P, PSNH, WMECO and NAEC, in 1994; previously Vice President-Corporate Planning of CL&P, WMECO since 1992; Vice President-Corporate Business Practices of CL&P, WMECO since 1991; and Vice President-Human Resources of CLP, WMECO since 1989. John B. Keane (7) 49 Elected Vice President and Treasurer of NU, CL&P, PSNH, WMECO and NAEC in 1993; previously Vice President, Secretary and General Counsel-Corporate of NU, CL&P and WMECO since 1993; Vice President, Assistant Secretary and General Counsel-Corporate of PSNH and NAEC, Vice President, Secretary and General Counsel-Corporate of NU and CL&P, and Vice President, Secretary, Assistant Clerk and General Counsel-Corporate of WMECO since 1992; previously Associate General Counsel of NUSCO since 1985. Francis L. Kinney (8) 63 Elected Senior Vice President-Governmental Affairs of CL&P, WMECO and NAEC in 1994; previously Vice President-Public Affairs of NAEC since 1992 and of CL&P and WMECO since 1978. Gerald Letendre 54 President, Diamond Casting & Machine Co., Inc. since 1972. Hugh C. MacKenzie (9) 53 Elected President-Retail Business Group of NU Feburary, 1996 and President of CL&P and WMECO in 1994; previously Senior Vice President-Customer Service Operations of CL&P and WMECO since 1990. Jane E. Newman (10) 50 Executive Vice President, Exeter Trust Company since 1995. Previously President, Coastal Broadcasting Corporation since 1992; previously Assistant to the President of the United State for Management and Administration from 1989 to 1991. John J. Roman 42 Elected Vice President and Controller of NU, CL&P, PSNH, WMECO and NAEC in 1995; previously Assistant Controller of CL&P, PSNH, WMECO and NAEC since 1992. Robert P. Wax 47 Elected Vice President, Secretary and General Counsel of PSNH and NAEC in 1994; elected Vice President, Secretary and General Counsel of NU and CL&P and Vice President, Secretary, Assistant Clerk and General Counsel of WMECO in 1993; previously Vice President, Assistant Secretary and General Counsel of PSNH and NAEC since 1993; previously Vice President and General Counsel- Regulatory of NU, CL&P, PSNH, WMECO, and NAEC since 1992; previously Associate General Counsel of NUSCO since 1985. (1) Trustee of Easthampton Savings Bank. (2) Director of Connecticut Yankee Atomic Power Company. (3) Director of Fleet Bank - New Hampshire and Hamden Assurance Company Limited. (4) Director of Connecticut Yankee Atomic Power Company and Maine Yankee Atomic Power Company. (5) Director of The Institute of Living, The Institute of Nuclear Power Operations, The Connecticut Business and Industry Association, Mount Holyoke College, Fleet Financial Group, CIGNA Corporation, Connecticut Yankee Atomic Power Company and The Dexter Corporation. (6) Director of Connecticut Yankee Atomic Power Company, the Business and Industry Association of New Hampshire, the Greater Manchester Chamber of Commerce; Trustee of Optima Health, Inc., and Saint Anselm's College. (7) Director of Maine Yankee Atomic Power Company, Vermont Yankee Nuclear Power Corporation, Yankee Atomic Electric Company and Connecticut Yankee Atomic Power Company (8) Director of Mid-Conn Bank. (9) Director of Connecticut Yankee Atomic Power Company. (10) Director of Exeter Trust Company, Perini Corporation, NYNEX Telecommunications and Consumers Water Company. There are no family relationships between any director or executive officer and any other director or executive officer of NU, CL&P, PSNH, WMECO or NAEC. ITEM 11. EXECUTIVE COMPENSATION NU. Incorporated herein by reference is the information contained in the sections "Summary Compensation Table," "Pension Benefits," and "Report on Executive Compensation" of the definitive proxy statement for solicitation of proxies by NU's Board of Trustees, dated April 1, 1996 and filed with the Commission pursuant to Rule 14a-6 under the Act. SUMMARY COMPENSATION TABLE The following table presents the cash and non-cash compensation received by the CEO and the next four highest paid executive officers of the System, and by two retired executive officers who would have been among the five highest paid executive officers but for their retirement, in accordance with rules of the Securities and Exchange Commission (SEC):
Annual Compensation Long Term Compensation Awards Payouts Options/ Long Re- Stock Term All Other stricted Appreci- Incentive Other Annual Stock ation Program Compen- Name and Salary Bonus($) Compensa- Awards Rights Payouts sation(&) Principal Position Year ($) (1) tion($) ($) (#) ($) (2) Bernard M. Fox(4) 1995 551,300 (3) None None None 130,165 7,350 Chairman of the Board, 1994 544,459 308,896 None None None 115,771 4,500 President and Chief 1993 478,775 180,780 None None None 61,155 7,033 Executive Officer Robert E. Busch(5) 1995 350,000 (3) None None None 63,100 7,350 President - Energy 1994 346,122 173,366 None None None 44,073 4,500 Resources Group 1993 255,915 78,673 None None None 32,337 7,072 Hugh C. MacKenzie(6) 1995 247,665 (3) None None None 46,789 7,350 President - Retail 1994 245,832 113,416 None None None 40,449 4,500 Business Group 1993 192,502 51,765 None None None 28,000 5,775 Francis L. Kinney(7) 1995 190,100 (3) None None None 29,808 5,584 Senior Vice 1994 191,303 57,425 None None None 24,549 4,500 President - Govern- 1993 188,090 28,620 None None None 27,020 5,423 mental Affairs (principal subsidiaries) Cheryl W. Grise(8) 1995 178,885 (3) None None None 24,834 5,361 Senior Vice President -1994 169,354 64,412 None None None 17,616 4,491 Chief Administrative 1993 136,475 25,728 None None None 0 4,094 Officer (principal subsidiaries) William B. Ellis(9) 1995 249,420 (3) None None None 158,393 7,350 Retired 1994 457,769 129,742 None None None 185,003 4,500 1993 521,250 160,693 None None None 87,363 None John F. Opeka(10) 1995 275,449 (3) None None None 56,779 7,350 Retired 1994 283,069 65,775 None None None 54,556 4,500 1993 277,304 58,259 None None None 40,014 6,875
Notes: (1) Awards under the 1993 and 1994 short-term programs of the Northeast Utilities Executive Incentive Plan (EIP) were paid the next year in the form of cash. In accordance with the requirements of the SEC, these awards are included as "bonus" in the years earned. (2) "All Other Compensation" consists of employer matching contributions under the Northeast Utilities Service Company Supplemental Retirement and Savings Plan, generally available to all eligible employees. (3) Awards under the short-term program of the EIP have typically been made by the Committee on Organization, Compensation and Board Affairs in April each year. (4) Mr. Fox is a Director and Executive Officer of CL&P, PSNH, WMECO and NAEC. (5) Mr. Busch is a Director of CL&P, WMECO and NAEC and an Executive Officer of CL&P, PSNH, WMECO and NAEC. (6) Mr. MacKenzie is a Director of CL&P, PSNH, WMECO and NAEC and an Executive Officer of CL&P and WMECO. (7) Mr. Kinney is an Executive Officer of CL&P, WMECO and NAEC. (8) Mrs. Grise is a Director of CL&P, PSNH, WMECO and NAEC and an Executive Officer of CL&P, WMECO and NAEC. (9) Mr. Ellis retired as Chairman of the Board and a Trustee of Northeast Utilities, and as Chairman and a Director of CL&P, PSNH, WMECO, and NAEC on August 1, 1995. (10) Mr. Opeka retired as Executive Vice President - Nuclear of NAEC and as a Director of NAEC, CL&P and WMECO on November 1, 1995. PENSION BENEFITS The following table shows the estimated annual retirement benefits payable to an executive officer of Northeast Utilities upon retirement, assuming that retirement occurs at age 65 and that the officer is at that time not only eligible for a pension benefit under the Northeast Utilities Service Company Retirement Plan (the Retirement Plan) but also eligible for the "make-whole benefit" and the "target benefit" under the Supplemental Executive Retirement Plan for Officers of Northeast Utilities System Companies (the Supplemental Plan). The Supplemental Plan is a non-qualified pension plan providing supplemental retirement income to system officers. The "make-whole benefit" under the Supplemental Plan, available to all officers, makes up for benefits lost through application of certain tax code limitations on the benefits that may be provided under the Retirement Plan and includes as "compensation" awards under the Executive Incentive Compensation Program and Executive Incentive Plan and deferred compensation (as earned). The "target benefit" further supplements these benefits and is available to officers at the Senior Vice President level and higher who are selected by the Board of Trustees to participate in the target benefit and who remain in the employ of Northeast Utilities companies until at least age 60 (unless the Board of Trustees sets an earlier age). Each of the executive officers of Northeast Utilities named in the "Summary Compensation Table" is currently eligible for a target benefit. The benefits presented are based on a straight life annuity beginning at age 65 and do not take into account any reduction for joint and survivorship annuity payments. ANNUAL TARGET BENEFIT FINAL AVERAGE COMPENSATION YEARS OF CREDITED SERVICE 15 20 25 30 35 $200,000 $72,000 $96,000 $120,000 $120,000 $120,000 250,000 90,000 120,000 150,000 150,000 150,000 300,000 108,000 144,000 180,000 180,000 180,000 350,000 126,000 168,000 210,000 210,000 210,000 400,000 144,000 192,000 240,000 240,000 240,000 450,000 162,000 216,000 270,000 270,000 270,000 500,000 180,000 240,000 300,000 300,000 300,000 600,000 216,000 288,000 360,000 360,000 360,000 700,000 252,000 336,000 420,000 420,000 420,000 800,000 288,000 384,000 480,000 480,000 480,000 900,000 324,000 432,000 540,000 540,000 540,000 1,000,000 360,000 480,000 600,000 600,000 600,000 1,100,000 396,000 528,000 660,000 660,000 660,000 1,200,000 432,000 576,000 720,000 720,000 720,000 Final average compensation for purposes of calculating the "target benefit" is the highest average annual compensation of the participant during any 36 consecutive months compensation was earned. Compensation taken into account under the "target benefit" described above includes salary, bonus, restricted stock awards, and long-term incentive payouts shown in the Summary Compensation Table, but does not include employer matching contributions under the 401(k) Plan. In the event that an officer's employment terminates because of disability, the retirement benefits shown above would be offset by the amount of any disability benefits payable to the recipient that are attributable to contributions made by Northeast Utilities and its subsidiaries under long term disability plans and policies. As of December 31, 1995, the five executive officers named in the Summary Compensation Table above had the following years of credited service for retirement compensation purposes: Mr. Fox - 31, Mr. Busch - 22, Mr. MacKenzie - - 30, Mr. Kinney - 34, and Mrs. Grise - 15. Assuming that retirement were to occur at age 65 for these officers, retirement would occur with 43, 38, 41, 36 and 36 years of credited service, respectively. In 1992, Northeast Utilities entered into an agreement with Mr. Fox to provide for an orderly Chief Executive Officer succession. The agreement states that if Mr. Fox is terminated as Chief Executive Officer without cause, he will be entitled to specified severance pay and benefits. Those benefits consist primarily of (i) two years' base pay, medical, dental and life insurance benefits; (ii) a supplemental retirement benefit equal to the difference between the target benefit he would be entitled to receive if he had reached the age of 55 on the termination date and the actual target benefit to which he is entitled as of the termination date; and (iii) a target benefit under the Supplemental Plan, notwithstanding that he might not have reached age 60 on the termination date and notwithstanding other forfeiture provisions of that plan. The agreement also provides specified death and disability benefits. The agreement does not address Mr. Fox's normal compensation and benefits, which are to be determined by the Committee on Organization, Compensation and Board Affairs and the Board in accordance with their customary practices. The agreement terminates two years after Northeast Utilities gives Mr. Fox a notice of termination, but no earlier than the date he becomes 55. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT NU. Incorporated herein by reference is the information contained in the sections "Common Stock Ownership of Certain Beneficial Owners," "Common Stock Ownership of Management," "Compensation of Trustees," "Summary Compensation Table," "Pension Benefits," and "Report on Executive Compensation" of the definitive proxy statement for solicitation of proxies by NU's Board of Trustees, dated April 1, 1996 and filed with the Commission pursuant to Rule 14a-6 under the Act. CL&P, PSNH, WMECO AND NAEC. NU owns 100% of the outstanding common stock of registrants CL&P, PSNH, WMECO and NAEC. As of February 27, 1996, the Directors of CL&P, PSNH, WMECO and NAEC, beneficially owned the number of shares of each class of equity securities of NU listed below. No equity securities of CL&P, PSNH, WMECO or NAEC are owned by the Directors and Executive Officers of their respective companies. CL&P, PSNH, WMECO, and NAEC DIRECTORS AND NAMED EXECUTIVE OFFICERS ------------------------------------------------------------------ Amount and Nature of Title Of Name of Beneficial Percent of Class Beneficial Owner Ownership (1) Class (2) - ------- ---------------------- ----------- ---------- NU Common Robert G. Abair(3) 6,489 (3,023) NU Common Robert E. Busch(4) 10,074 (5,492) NU Common John C. Collins(5) 25 NU Common Ted C. Feigenbaum(6) 474 (474) NU Common John H. Forsgren(7) 0 NU Common Bernard M. Fox(8) 25,092 (3,597) NU Common William T. Frain, Jr.(9) 1,793 (536) NU Common Cheryl W. Grise(10) 3,407 (1,116) NU Common Barry Ilberman(11) 6,822 (3,156) NU Common John B. Keane(12) 2,122 (1,475) NU Common Francis L. Kinney(13) 3,697 (2,189) NU Common Gerald Letendre(5) 0 NU Common Hugh C. MacKenzie(14) 8,047 (2,724) NU Common Jane E. Newman(5) 0 NU Common John J. Roman(15) 1,624 (1,624) NU Common Robert P. Wax(16) 2,791 (2,260) Amount beneficially owned by Directors and Executive Officers as a group - CL&P 71,958 (27,192) shares - PSNH 59,675 (20,505) shares - WMECO 71,958 (27,192) shares - NAEC 65,943 (24,642) shares (1) Unless otherwise noted, each Director and Executive Officer of CL&P, PSNH, WMECO and NAEC has sole voting and investment power with respect to the listed shares. The numbers in parentheses reflect the number of shares owned by each Director and Executive Officer under the Northeast Utilities Service Company Supplemental Retirement and Savings Plan (401(k) Plan), as to which the Officer has no investment power. (2) As of February 27, 1996 there were 136,023,358 common shares of NU outstanding. The percentage of such shares beneficially owned by any Director or Executive Officer, or by all Directors and Executive Officers of CL&P, PSNH, WMECO and NAEC as a group, does not exceed one percent. (3) Mr. Abair is a Director of CL&P and WMECO. (4) Mr. Busch is a Director of CL&P, WMECO and NAEC and an Executive Officer of CL&P, PSNH, WMECO and NAEC. (5) Messrs. Collins, Letendre and Ms. Newman are Directors of PSNH. Mr. Collins shares voting and investment power with his wife for 25 shares. (6) Mr. Feigenbaum is a Director and an Executive Officer of NAEC. (7) Mr. Forsgren is an Executive Officer of CL&P, PSNH, WMECO and NAEC. (8) Mr. Fox is a Director and Executive Officer of CL&P, PSNH, WMECO and NAEC. Mr. Fox shares voting and investment power with his wife for 3,031 of these shares. In addition, Mr. Fox's wife has sole voting and investment power for 140 shares as to which Mr. Fox disclaims beneficial ownership. (9) Mr Frain is a Director of CL&P, PSNH, WMECO and NAEC and an Executive Officer of PSNH. (10) Mrs. Grise is a Director of CL&P, PSNH, WMECO and NAEC and an Executive Officer of CL&P, WMECO and NAEC. (11) Mr. Ilberman is an Executive Officer of CL&P, PSNH, WMECO and NAEC. Mr. Ilberman shares voting and investment power with his wife for 290 of these shares and voting and investment power with his mother for 1,161 of these shares. (12) Mr. Keane is a Director of CL&P, WMECO and NAEC. (13) Mr. Kinney is an Executive Officer of CL&P, WMECO and NAEC. Mr. Kinney shares voting and investment power with his wife for 1,508 of these shares. (14) Mr. MacKenzie is a Director of CL&P, PSNH, WMECO and NAEC and an Executive Officer of CL&P and WMECO. Mr. MacKenzie shares voting and investment power with his wife for 1,467 shares. (15) Mr. Roman is an Executive Officer of CL&P, PSNH, WMECO and NAEC. (16) Mr. Wax is a Director of PSNH and an Executive Officer of CL&P, PSNH, WMECO and NAEC. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS NU. Incorporated herein by reference is the information contained in the section "Certain Relationships and Related Transactions" of the definitive proxy statement for solicitation of proxies by NU's Board of Trustees, dated April 1, 1996 and filed with the Commission pursuant to Rule 14a-6 under the Act. CL&P, PSNH, WMECO, AND NAEC. No relationships or transactions that would be described in response to this item exist now or existed during 1995 with respect to CL&P, PSNH, WMECO, and NAEC. ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K. (a) 1. Financial Statements: The Report of Independent Public Accountants and financial statements of NU, CL&P, PSNH, WMECO, and NAEC are hereby incorporated by reference and made a part of this report (see "Item 8. Financial Statements and Supplementary Data"). Report of Independent Public Accountants on Schedules S-1 Consent of Independent Public Accountants S-2 2. Schedules: Financial Statement Schedules for NU (Parent), NU and Subsidiaries, CL&P and Subsidiaries, PSNH and WMECO are listed in the Index to Financial Statement Schedules S-3 3. Exhibits Index E-1 (b) Reports on Form 8-K: NU, CL&P, PSNH, WMECO, and NAEC filed Form 8-Ks dated January 31, 1996 on January 31, 1996. This 8-K filing disclosed that the NRC had announced that the Millstone Nuclear Power Station had been placed on its "watch list." NORTHEAST UTILITIES 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. NORTHEAST UTILITIES ------------------- (Registrant) Date: March 13, 1996 By /s/Bernard M. Fox -------------- ----------------- Bernard M. Fox Chairman of the Board, President and Chief Executive 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. Date Title Signature - ---- ----- --------- March 13, 1996 A Trustee, Chairman /s/Bernard M. Fox - -------------- of the Board, ----------------- President and Bernard M. Fox Chief Executive Officer March 13, 1996 Executive Vice /s/ John H. Forsgren - -------------- President and Chief -------------------- Financial Officer John H. Forsgren March 13, 1996 Vice President and /s/John J. Roman - -------------- Controller ---------------- John J. Roman NORTHEAST UTILITIES SIGNATURES (CONT'D) Date Title Signature - ---- ----- --------- March 13, 1996 Trustee /s/Alfred F. Boschulte - -------------- ---------------------- Alfred F. Boschulte March 13, 1996 Trustee /s/Cotton Mather Cleveland - -------------- -------------------------- Cotton Mather Cleveland March 13, 1996 Trustee /s/George David - -------------- --------------- George David March 13, 1996 Trustee /s/E. Gail de Planque - -------------- --------------------- E. Gail de Planque March 13, 1996 Trustee /s/Gaynor N. Kelley - -------------- ------------------- Gaynor N. Kelley March 13, 1996 Trustee /s/Elizabeth T. Kennan - -------------- ---------------------- Elizabeth T. Kennan March 13, 1996 Trustee /s/Denham C. Lunt, Jr. - -------------- ---------------------- Denham C. Lunt, Jr. NORTHEAST UTILITIES SIGNATURES (CONT'D) Date Title Signature - ---- ----- --------- March 13, 1996 Trustee /s/William J. Pape II - -------------- --------------------- William J. Pape II March 13, 1996 Trustee /s/Robert E. Patricelli - -------------- ----------------------- Robert E. Patricelli March 13, 1996 Trustee /s/Norman C. Rasmussen - -------------- ---------------------- Norman C. Rasmussen March 13, 1996 Trustee /s/John F. Swope - -------------- ---------------- John F. Swope March 13, 1996 Trustee /s/John F. Turner - -------------- ----------------- John F. Turner THE CONNECTICUT LIGHT AND POWER COMPANY 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. THE CONNECTICUT LIGHT AND POWER COMPANY --------------------------------------- (Registrant) Date: March 13, 1996 By /s/Bernard M. Fox -------------- ----------------- Bernard M. Fox Chairman 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. Date Title Signature - ---- ----- --------- March 13, 1996 Chairman and /s/Bernard M. Fox - -------------- a Director ----------------- Bernard M. Fox March 13, 1996 President and /s/Hugh C. MacKenzie - -------------- a Director -------------------- Hugh C. MacKenzie March 13, 1996 Executive Vice /s/ John H. Forsgren - -------------- President and Chief -------------------- Financial Officer John H. Forsgren March 13, 1996 Vice President and /s/John J. Roman - -------------- Controller ---------------- John J. Roman THE CONNECTICUT LIGHT AND POWER COMPANY SIGNATURES (CONT'D) Date Title Signature - ---- ----- --------- March 13, 1996 Director /s/Robert G. Abair - -------------- ------------------ Robert G. Abair March 13, 1996 Director /s/Robert E. Busch - -------------- ------------------ Robert E. Busch March 13, 1996 Director /s/William T. Frain, Jr. - -------------- ------------------------ William T. Frain, Jr. March 13, 1996 Director /s/Cheryl W. Grise - -------------- ------------------ Cheryl W. Grise March 13, 1996 Director /s/John B. Keane - -------------- ---------------- John B. Keane PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE 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. PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE --------------------------------------- (Registrant) Date: March 13, 1996 By /s/Bernard M. Fox -------------- ----------------- Bernard M. Fox Chairman and Chief Executive 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. Date Title Signature - ---- ----- --------- March 13, 1996 Chairman, Chief /s/Bernard M. Fox - -------------- Executive Officer ----------------- and a Director Bernard M. Fox March 13, 1996 President, Chief /s/William T. Frain, Jr. - -------------- Operating Officer ------------------------ and a Director William T. Frain, Jr. March 13, 1996 Executive Vice /s/ John H. Forsgren - -------------- President and Chief -------------------- Financial Officer John H. Forsgren March 13, 1996 Vice President and /s/John J. Roman - -------------- Controller ---------------- John J. Roman PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE SIGNATURES (CONT'D) Date Title Signature - ---- ----- --------- Director - -------------- ------------------ John C. Collins March 13, 1996 Director /s/Cheryl W. Grise - -------------- ------------------ Cheryl W. Grise Director - -------------- ------------------ Gerald Letendre March 13, 1996 Director /s/Hugh C. MacKenzie - -------------- -------------------- Hugh C. MacKenzie March 13, 1996 Director /s/Jane E. Newman - -------------- ----------------- Jane E. Newman March 13, 1996 Director /s/Robert P. Wax - -------------- ---------------- Robert P. Wax WESTERN MASSACHUSETTS ELECTRIC COMPANY 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. WESTERN MASSACHUSETTS ELECTRIC COMPANY -------------------------------------- (Registrant) Date: March 13, 1996 By /s/Bernard M. Fox -------------- ----------------- Bernard M. Fox Chairman 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. Date Title Signature - ---- ----- --------- March 13, 1996 Chairman and /s/Bernard M. Fox - -------------- a Director ----------------- Bernard M. Fox March 13, 1996 President and /s/Hugh C. MacKenzie - -------------- a Director -------------------- Hugh C. MacKenzie March 13, 1996 Executive Vice /s/ John H. Forsgren - -------------- President and Chief -------------------- Financial Officer John H. Forsgren March 13, 1996 Vice President and /s/John J. Roman - -------------- Controller ---------------- John J. Roman WESTERN MASSACHUSETTS ELECTRIC COMPANY SIGNATURES (CONT'D) Date Title Signature - ---- ----- --------- March 13, 1996 Director /s/Robert G. Abair - -------------- ------------------ Robert G. Abair March 13, 1996 Director /s/Robert E. Busch - -------------- ------------------ Robert E. Busch March 13, 1996 Director /s/William T. Frain, Jr. - -------------- ------------------------ William T. Frain, Jr. March 13, 1996 Director /s/Cheryl W. Grise - -------------- ------------------ Cheryl W. Grise March 13, 1996 Director /s/John B. Keane - -------------- ---------------- John B. Keane NORTH ATLANTIC ENERGY CORPORATION 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. NORTH ATLANTIC ENERGY CORPORATION --------------------------------- (Registrant) Date: March 13, 1996 By /s/Bernard M. Fox -------------- ----------------- Bernard M. Fox Chairman and Chief Executive 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. Date Title Signature - ---- ----- --------- March 13, 1996 Chairman, Chief /s/Bernard M. Fox - -------------- Executive Officer ----------------- and a Director Bernard M. Fox March 13, 1996 President and /s/Robert E. Busch - -------------- a Director ------------------ Robert E. Busch March 13, 1996 Executive Vice /s/ John H. Forsgren - -------------- President and Chief -------------------- Financial Officer John H. Forsgren NORTH ATLANTIC ENERGY CORPORATION SIGNATURES (CONT'D) Date Title Signature - ---- ----- --------- March 13, 1996 Vice President and /s/John J. Roman - -------------- Controller ---------------- John J. Roman March 13, 1996 Director /s/Ted C. Feigenbaum - -------------- -------------------- Ted C. Feigenbaum March 13, 1996 Director /s/William T. Frain, Jr. - -------------- ------------------------ William T. Frain, Jr. March 13, 1996 Director /s/Cheryl W. Grise - -------------- ------------------ Cheryl W. Grise March 13, 1996 Director /s/John B. Keane - -------------- ---------------- John B. Keane March 13, 1996 Director /s/Hugh C. MacKenzie - -------------- -------------------- Hugh C. MacKenzie REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS ON SCHEDULES We have audited in accordance with generally accepted auditing standards, the financial statements included in Northeast Utilities' annual report to shareholders and The Connecticut Light and Power Company's, Western Massachusetts Electric Company's, North Atlantic Energy Corporation's, and Public Service Company of New Hampshire's annual reports, incorporated by reference in this Form 10-K, and have issued our reports thereon dated February 16, 1996. Our reports on the financial statements include an explanatory paragraph with respect to the change in method of accounting for property taxes, if applicable to each company, as described in notes to the related company's financial statements. Our audits were made for the purpose of forming an opinion on each company's statements taken as a whole. The schedules listed in the accompanying index are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of each company's basic financial statements. These schedules have been subjected to the auditing procedures applied in the audits of each company's basic financial statements and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to each company's basic financial statements taken as a whole. /s/ ARTHUR ANDERSEN LLP ARTHUR ANDERSEN LLP Hartford, Connecticut February 16, 1996 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation by reference of our reports included or incorporated by reference in this Form 10-K, into previously filed Registration Statement No. 33-55279 of The Connecticut Light and Power Company, No. 33-56537 of CL&P Capital, LP, No. 33- 51185 of Western Massachusetts Electric Company, and No. 33-34622, No. 33-44814, and No. 33-40156 of Northeast Utilities. /s/ ARTHUR ANDERSEN LLP ARTHUR ANDERSEN LLP Hartford, Connecticut March 13, 1996 SCHEDULE I NORTHEAST UTILITIES (PARENT) FINANCIAL INFORMATION OF REGISTRANT BALANCE SHEETS AT DECEMBER 31, 1995 AND 1994 (Thousands of Dollars)
1995 1994 ---------- ---------- ASSETS - ------ Other Property and Investments: Investments in subsidiary companies, at equity............................................... $2,701,866 $2,625,228 Investments in transmission companies, at equity...... 23,557 26,106 Other, at cost........................................ 250 636 ----------- ----------- 2,725,673 2,651,970 ----------- ----------- Current Assets: Cash.................................................. 18 42 Notes receivable from affiliated companies............ 9,675 1,975 Receivables from affiliated companies................. 607 2,598 Prepayments........................................... 138 228 ----------- ----------- 10,438 4,843 ----------- ----------- Deferred Charges: Accumulated deferred income taxes..................... 6,984 7,749 Unamortized debt expense.............................. 11 31 Other................................................. 122 26 ----------- ----------- 7,117 7,806 ----------- ----------- Total Assets..................................... $2,743,228 $2,664,619 =========== =========== CAPITALIZATION AND LIABILITIES - ------------------------------ Capitalization: Common Shareholders' Equity: Common shares, $5 par value--Authorized 225,000,000 shares; 135,611,166 shares issued and 127,050,647 shares outstanding in 1995 and 134,210,226 shares issued and 124,994,322 outstanding in 1994..................... $ 678,056 $ 671,051 Capital surplus, paid in.............................. 936,308 904,371 Deferred benefit plan--employee stock ownership plan.. (198,152) (213,324) Retained earnings..................................... 1,007,340 946,988 ----------- ----------- Total common shareholders' equity................... 2,423,552 2,309,086 Long-term debt........................................ 210,000 224,000 ----------- ----------- Total capitalization................................ 2,633,552 2,533,086 ----------- ----------- Current Liabilities: Notes payable to banks................................ 57,500 104,000 Long-term debt and preferred stock--current portion... 14,000 12,000 Accounts payable...................................... 18,213 962 Accounts payable to affiliated companies.............. 1,074 2,944 Accrued taxes......................................... 6,539 7,454 Accrued interest...................................... 2,864 3,623 Dividend reinvestment plan............................ 8,995 - Other................................................. 2 17 ----------- ----------- 109,187 131,000 ----------- ----------- Other Deferred Credits.................................. 489 533 ----------- ----------- Total Capitalization and Liabilities $2,743,228 $2,664,619 =========== ===========
SCHEDULE I NORTHEAST UTILITIES (PARENT) FINANCIAL INFORMATION OF REGISTRANT STATEMENTS OF INCOME YEARS ENDED DECEMBER 31, 1995, 1994, AND 1993 (Thousands of Dollars Except Share Information)
1995 1994 1993 ------------- ------------- ------------- Operating Revenues............... $ - $ - $ - ------------- ------------- ------------- Operating Expenses: Other.......................... 14,267 13,114 2,677 Federal income taxes........... (8,585) (10,736) (7,564) ------------- ------------- ------------- Total operating expenses...... 5,682 2,378 (4,887) ------------- ------------- ------------- Operating Income (Loss).......... (5,682) (2,378) 4,887 ------------- ------------- ------------- Other Income: Equity in earnings of subsidiaries.................. 310,025 309,769 263,725 Equity in earnings of transmission companies........ 3,561 3,418 3,736 Other, net..................... 329 679 1,302 ------------- ------------- ------------- Other income, net............ 313,915 313,866 268,763 ------------- ------------- ------------- Income before interest charges..................... 308,233 311,488 273,650 ------------- ------------- ------------- Interest Charges 25,799 24,614 23,697 ------------- ------------- ------------- Earnings for Common Shares $ 282,434 $ 286,874 $ 249,953 ============= ============= ============= Earnings Per Common Share........ $ 2.24 $ 2.30 $ 2.02 ============= ============= ============= Common Shares Outstanding (average)....................... 126,083,645 124,678,192 123,947,631 ============= ============= =============
SCHEDULE I NORTHEAST UTILITIES (PARENT) FINANCIAL INFORMATION OF REGISTRANT STATEMENT OF CASH FLOWS YEARS ENDED DECEMBER 31, 1995, 1994, 1993 (Thousands of Dollars)
1995 1994 1993 -------------- -------------- -------------- Operating Activities: Net income $ 282,434 $ 286,874 $ 249,953 Adjustments to reconcile to net cash from operating activities: Equity in earnings of subsidiary companies (310,025) (309,769) (263,725) Cash dividends received from subsidiary companies 272,350 201,403 191,297 Deferred income taxes 772 (1,890) (3,199) Other sources of cash 6,916 3,007 197 Other uses of cash (528) (169) (3,915) Changes in working capital: Receivables 1,991 30,525 (25,012) Accounts payable 15,381 (43,601) 27,066 Other working capital (excludes cash) 7,396 7,615 (3,010) -------------- -------------- -------------- Net cash flows from operating activities 276,687 173,995 169,652 -------------- -------------- -------------- Financing Activities: Issuance of common shares 47,218 14,551 22,252 Net (decrease) increase in short-term debt (46,500) 31,500 2,000 Reacquisitions and retirements of long-term debt (12,000) (9,000) (5,000) Cash dividends on common shares (221,701) (219,317) (218,179) -------------- -------------- -------------- Net cash flows used for financing activities (232,983) (182,266) (198,927) -------------- -------------- -------------- Investment Activities: NU System Money Pool (7,700) 17,650 32,975 Investment in subsidiaries (38,963) (10,912) (4,853) Other investment activities, net 2,935 1,503 1,152 -------------- -------------- -------------- Net cash flows (used for) from investments (43,728) 8,241 29,274 -------------- -------------- -------------- Net decrease in cash for the period (24) (30) (1) Cash - beginning of period 42 72 73 -------------- -------------- -------------- Cash - end of period $ 18 $ 42 $ 72 ============== ============== ============== Supplemental Cash Flow Information Cash paid during the year for: Interest, net of amounts capitalized $ 26,430 $ 24,235 $ 23,808 ============== ============== ============== Income taxes (refund) $ (8,418) $ (16,786) $ - ============== ============== ==============
NORTHEAST UTILITIES AND SUBSIDIARIES SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES YEAR ENDED DECEMBER 31, 1995 (Thousands of Dollars)
- ------------------------------------------------------------------------------------------------------- Column A Column B Column C Column D Column E Additions -------------------- (1) (2) Charged to Balance at Charged to other Balance beginning costs and accounts- Deductions- at end Description of period expenses describe describe of period - ------------------------------------------------------------------------------------------------------- RESERVES DEDUCTED FROM ASSETS TO WHICH THEY APPLY: Reserves for uncollectible accounts $ 16,826 $ 18,010 $ - $ 20,458 (a)$ 14,378 ========= ========= ========= ========= ========= Asset valuation reserves $ 21,585 $ 31,481 $ - $ - $ 53,066 ========= ========= ========= ========= ========= RESERVES NOT APPLIED AGAINST ASSETS: Operating reserves $ 34,721 $ 11,475 $ - $ 7,787 (b)$ 38,409 ========= ========= ========= ========= ========= (a) Amounts written off, net of recoveries. (b) Principally payments for environmental remediation, various injuries and damages, employee medical expenses, and expenses in connection therewith.
NORTHEAST UTILITIES AND SUBSIDIARIES SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES YEAR ENDED DECEMBER 31, 1994 (Thousands of Dollars)
- ------------------------------------------------------------------------------------------------------ Column A Column B Column C Column D Column E Additions -------------------- (1) (2) Charged to Balance at Charged to other Balance beginning costs and accounts- Deductions- at end Description of period expenses describe describe of period - ------------------------------------------------------------------------------------------------------ RESERVES DEDUCTED FROM ASSETS TO WHICH THEY APPLY: Reserves for uncollectible accounts $ 14,629 $ 23,194 $ - $ 20,997 (a) $ 16,826 ========= ========= ========= ========= ========= Asset valuation reserves $ 797 $ 29,688 $ - $ 8,900 (b) $ 21,585 ========= ========= ========= ========= ========= RESERVES NOT APPLIED AGAINST ASSETS: Operating reserves $ 28,286 $ 13,150 $ - $ 6,715 (c) $ 34,721 ========= ========= ========= ========= ========= (a) Amounts written off, net of recoveries. (b) Principally the reduction in the carrying amounts of assets. (c) Principally payments for environmental remediation, various injuries and damages, employee medical expenses, and expenses in connection therewith.
NORTHEAST UTILITIES AND SUBSIDIARIES SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES YEAR ENDED DECEMBER 31, 1993 (Thousands of Dollars)
- ---------------------------------------------------------------------------------------------------- Column A Column B Column C Column D Column E Additions -------------------- (1) (2) Charged to Balance at Charged to other Balance beginning costs and accounts- Deductions- at end Description of period expenses describe describe of period - ---------------------------------------------------------------------------------------------------- RESERVES DEDUCTED FROM ASSETS TO WHICH THEY APPLY: Reserves for uncollectible accounts $ 13,255 $ 21,118 $ - $ 19,744 (a) $ 14,629 ========= ========= ========= ========= ========= Asset valuation reserves $ 17,628 $ 23,169 $ - $ 40,000 (b) $ 797 ========= ========= ========= ========= ========= RESERVES NOT APPLIED AGAINST ASSETS: Operating reserves $ 24,489 $ 54,583 $ - $ 50,786 (c) $ 28,286 ========= ========= ========= ========= ========= (a) Amounts written off, net of recoveries. (b) Principally the reduction in the carrying amounts of assets. (c) Principally payments for environmental remediation, various injuries and damages, employee medical expenses, and expenses in connection therewith.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES YEAR ENDED DECEMBER 31, 1995 (Thousands of Dollars)
- ------------------------------------------------------------------------------------------------------- Column A Column B Column C Column D Column E Additions -------------------- (1) (2) Charged to Balance at Charged to other Balance beginning costs and accounts- Deductions- at end Description of period expenses describe describe of period - ------------------------------------------------------------------------------------------------------- RESERVES DEDUCTED FROM ASSETS TO WHICH THEY APPLY: Reserves for uncollectible accounts $ 12,778 $ 12,722 $ - $ 14,933 (a)$ 10,567 ========= ========= ========= ========= ========= Asset valuation reserves $ 21,585 $ 25,481 $ - $ - $ 47,066 ========= ========= ========= ========= ========= RESERVES NOT APPLIED AGAINST ASSETS: Operating reserves $ 19,529 $ 5,633 $ - $ 5,288 (b)$ 19,874 ========= ========= ========= ========= ========= (a) Amounts written off, net of recoveries. (b) Principally payments for environmental remediation, various injuries and damages, employee medical expenses, and expenses in connection therewith.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES YEAR ENDED DECEMBER 31, 1994 (Thousands of Dollars)
- ------------------------------------------------------------------------------------------------------ Column A Column B Column C Column D Column E Additions -------------------- (1) (2) Charged to Balance at Charged to other Balance beginning costs and accounts- Deductions- at end Description of period expenses describe describe of period - ------------------------------------------------------------------------------------------------------ RESERVES DEDUCTED FROM ASSETS TO WHICH THEY APPLY: Reserves for uncollectible accounts $ 10,816 $ 17,177 $ - $ 15,215 (a) $ 12,778 ========= ========= ========= ========= ========= Asset valuation reserves $ 797 $ 29,688 $ - $ 8,900 (b) $ 21,585 ========= ========= ========= ========= ========= RESERVES NOT APPLIED AGAINST ASSETS: Operating reserves $ 14,905 $ 9,924 $ - $ 5,300 (c) $ 19,529 ========= ========= ========= ========= ========= (a) Amounts written off, net of recoveries. (b) Principally the reduction in the carrying amounts of assets. (c) Principally payments for environmental remediation, various injuries and damages, employee medical expenses, and expenses in connection therewith.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES YEAR ENDED DECEMBER 31, 1993 (Thousands of Dollars)
- ---------------------------------------------------------------------------------------------------- Column A Column B Column C Column D Column E Additions -------------------- (1) (2) Charged to Balance at Charged to other Balance beginning costs and accounts- Deductions- at end Description of period expenses describe describe of period - ---------------------------------------------------------------------------------------------------- RESERVES DEDUCTED FROM ASSETS TO WHICH THEY APPLY: Reserves for uncollectible accounts $ 8,358 $ 16,366 $ - $ 13,908 (a) $ 10,816 ========= ========= ========= ========= ========= Asset valuation reserves $ 17,628 $ 23,169 $ - $ 40,000 (b) $ 797 ========= ========= ========= ========= ========= RESERVES NOT APPLIED AGAINST ASSETS: Operating reserves $ 12,665 $ 29,036 $ - $ 26,796 (c) $ 14,905 ========= ========= ========= ========= ========= (a) Amounts written off, net of recoveries. (b) Principally the reduction in the carrying amounts of assets. (c) Principally payments for environmental remediation, various injuries and damages, employee medical expenses, and expenses in connection therewith.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES YEAR ENDED DECEMBER 31, 1995 (Thousands of Dollars)
- ------------------------------------------------------------------------------------------------------- Column A Column B Column C Column D Column E Additions -------------------- (1) (2) Charged to Balance at Charged to other Balance beginning costs and accounts- Deductions- at end Description of period(a)expenses describe describe of period - ------------------------------------------------------------------------------------------------------- RESERVES DEDUCTED FROM ASSETS TO WHICH THEY APPLY: Reserves for uncollectible accounts $ 2,015 $ 2,454 $ - $ 2,887 (a)$ 1,582 ========= ========= ========= ========= ========= RESERVES NOT APPLIED AGAINST ASSETS: Operating reserves $ 5,113 $ 3,668 $ - $ 639 (b)$ 8,142 ========= ========= ========= ========= ========= (a) Amounts written off, net of recoveries. (b) Principally payments for environmental remediation, various injuries and damages, employee medical expenses, and expenses in connection therewith.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES YEAR ENDED DECEMBER 31, 1994 (Thousands of Dollars)
- ------------------------------------------------------------------------------------------------------ Column A Column B Column C Column D Column E Additions -------------------- (1) (2) Charged to Balance at Charged to other Balance beginning costs and accounts- Deductions- at end Description of period expenses describe describe of period - ------------------------------------------------------------------------------------------------------ RESERVES DEDUCTED FROM ASSETS TO WHICH THEY APPLY: Reserves for uncollectible accounts $ 1,816 $ 2,999 $ - $ 2,800 (a) $ 2,015 ========= ========= ========= ========= ========= RESERVES NOT APPLIED AGAINST ASSETS: Operating reserves $ 3,960 $ 1,525 $ - $ 372 (b) $ 5,113 ========= ========= ========= ========= ========= (a) Amounts written off, net of recoveries. (b) Principally payments for environmental remediation, various injuries and damages, employee medical expenses, and expenses in connection therewith.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES YEAR ENDED DECEMBER 31, 1993 (Thousands of Dollars)
- ---------------------------------------------------------------------------------------------------- Column A Column B Column C Column D Column E Additions -------------------- (1) (2) Charged to Balance at Charged to other Balance beginning costs and accounts- Deductions- at end Description of period expenses describe describe of period - ---------------------------------------------------------------------------------------------------- RESERVES DEDUCTED FROM ASSETS TO WHICH THEY APPLY: Reserves for uncollectible accounts $ 2,780 $ 1,771 $ - $ 2,735 (a) $ 1,816 ========= ========= ========= ========= ========= RESERVES NOT APPLIED AGAINST ASSETS: Operating reserves $ 4,420 $ 457 $ - $ 917 (b) $ 3,960 ========= ========= ========= ========= ========= (a) Amounts written off, net of recoveries. (b) Principally payments for environmental remediation, various injuries and damages, employee medical expenses, and expenses in connection therewith.
WESTERN MASSACHUSETTS ELECTRIC COMPANY SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES YEAR ENDED DECEMBER 31, 1995 (Thousands of Dollars)
- ------------------------------------------------------------------------------------------------------- Column A Column B Column C Column D Column E Additions -------------------- (1) (2) Charged to Balance at Charged to other Balance beginning costs and accounts- Deductions- at end Description of period expenses describe describe of period - ------------------------------------------------------------------------------------------------------- RESERVES DEDUCTED FROM ASSETS TO WHICH THEY APPLY: Reserves for uncollectible accounts $ 2,032 $ 2,836 $ - $ 2,638 (a)$ 2,230 ========= ========= ========= ========= ========= Asset valuation reserves $ - $ 6,000 $ - $ - $ 6,000 ========= ========= ========= ========= ========= RESERVES NOT APPLIED AGAINST ASSETS: Operating reserves $ 4,674 $ 1,340 $ - $ 870 (b)$ 5,144 ========= ========= ========= ========= ========= (a) Amounts written off, net of recoveries. (b) Principally payments for environmental remediation, various injuries and damages, employee medical expenses, and expenses in connection therewith.
WESTERN MASSACHUSETTS ELECTRIC COMPANY SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES YEAR ENDED DECEMBER 31, 1994 (Thousands of Dollars)
- ------------------------------------------------------------------------------------------------------ Column A Column B Column C Column D Column E Additions -------------------- (1) (2) Charged to Balance at Charged to other Balance beginning costs and accounts- Deductions- at end Description of period expenses describe describe of period - ------------------------------------------------------------------------------------------------------ RESERVES DEDUCTED FROM ASSETS TO WHICH THEY APPLY: Reserves for uncollectible accounts $ 1,997 $ 3,017 $ - $ 2,982 (a) $ 2,032 ========= ========= ========= ========= ========= RESERVES NOT APPLIED AGAINST ASSETS: Operating reserves $ 3,842 $ 1,473 $ - $ 641 (b) $ 4,674 ========= ========= ========= ========= ========= (a) Amounts written off, net of recoveries. (b) Principally payments for environmental remediation, various injuries and damages, employee medical expenses, and expenses in connection therewith.
WESTERN MASSACHUSETTS ELECTRIC COMPANY SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES YEAR ENDED DECEMBER 31, 1993 (Thousands of Dollars)
- ---------------------------------------------------------------------------------------------------- Column A Column B Column C Column D Column E Additions -------------------- (1) (2) Charged to Balance at Charged to other Balance beginning costs and accounts- Deductions- at end Description of period expenses describe describe of period - ---------------------------------------------------------------------------------------------------- RESERVES DEDUCTED FROM ASSETS TO WHICH THEY APPLY: Reserves for uncollectible accounts $ 2,117 $ 2,812 $ - $ 2,932 (a) $ 1,997 ========= ========= ========= ========= ========= RESERVES NOT APPLIED AGAINST ASSETS: Operating reserves $ 2,543 $ 6,192 $ - $ 4,893 (b) $ 3,842 ========= ========= ========= ========= ========= (a) Amounts written off, net of recoveries. (b) Principally payments for environmental remediation, various injuries and damages, employee medical expenses, and expenses in connection therewith.
EXHIBIT INDEX Each document described below is incorporated by reference to the files of the Securities and Exchange Commission, unless the reference to the document is marked as follows: * - Filed with the 1995 Annual Report on Form 10-K for NU and herein incorporated by reference from the 1995 NU Form 10-K, File No. 1-5324 into the 1995 Annual Reports on Form 10-K for CL&P, PSNH, WMECO and NAEC. # - Filed with the 1995 Annual Report on Form 10-K for NU and herein incorporated by reference from the 1995 NU Form 10-K, File No. 1-5324 into the 1995 Annual Report on Form 10-K for CL&P. @ - Filed with the 1995 Annual Report on Form 10-K for NU and herein incorporated by reference from the 1995 NU Form 10-K, File No. 1-5324 into the 1995 Annual Report on Form 10-K for PSNH. ** - Filed with the 1995 Annual Report on Form 10-K for NU and herein incorporated by reference from the 1995 NU Form 10-K, File No. 1-5324 into the 1995 Annual Report on Form 10-K for WMECO. ## - Filed with the 1995 Annual Report on Form 10-K for NU and herein incorporated by reference from the 1995 Form 10-K, File No. 1-5324 into the 1995 Annual Report on Form 10-K for NAEC. Exhibit Number Description 3 Articles of Incorporation and By-Laws 3.1 Northeast Utilities 3.1.1 Declaration of Trust of NU, as amended through May 24, 1988. (Exhibit 3.1.1, 1988 NU Form 10-K, File No. 1-5324) 3.2 The Connecticut Light and Power Company 3.2.1 Certificate of Incorporation of CL&P,restated to March 2, 1994. (Exhibit 3.2.1, 1993 NU Form 10-K, File No. 1-5324) 3.2.2 By-laws of CL&P, as amended to March 1, 1982. (Exhibit 3.2.2, 1993 NU Form 10-K, File No. 1-5324) 3.3 Public Service Company of New Hampshire 3.3.1 Articles of Incorporation, as amended to May 16, 1991. (Exhibit 3.3.1, 1993 NU Form 10-K, File No. 1-5324) 3.3.2 By-laws of PSNH, as amended to November 1, 1993. (Exhibit 3.3.2, 1993 NU Form 10-K, File No. 1-5324) 3.4 Western Massachusetts Electric Company 3.4.1 Articles of Organization of WMECO, restated to February 23, 1995. (Exhibit 3.4.1, 1994 NU Form 10-K, File No. 1-5324) 3.4.2 By-laws of WMECO, as amended to February 13, 1995. (Exhibit 3.4.2, 1994 NU Form 10-K, File No. 1-5324) 3.5 North Atlantic Energy Corporation 3.5.1 Articles of Incorporation of NAEC dated September 20, 1991. (Exhibit 3.5.1, 1993 NU Form 10-K, File No. 1-5324) 3.5.2 Articles of Amendment dated October 16, 1991 and June 2, 1992 to Articles of Incorporation of NAEC. (Exhibit 3.5.2, 1993 NU Form 10-K, File No. 1-5324) 3.5.3 By-laws of NAEC, as amended to November 8, 1993. (Exhibit 3.5.3, 1993 NU Form 10-K, File No. 1-5324) 4 Instruments defining the rights of security holders, including indentures 4.1 Northeast Utilities 4.1.1 Indenture dated as of December 1, 1991 between Northeast Utilities and IBJ Schroder Bank & Trust Company, with respect to the issuance of Debt Securities. (Exhibit 4.1.1, 1991 NU Form 10-K, File No. 1-5324) 4.1.2 First Supplemental Indenture dated as of December 1, 1991 between Northeast Utilities and IBJ Schroder Bank & Trust Company, with respect to the issuance of Series A Notes. (Exhibit 4.1.2, 1991 NU Form 10-K, File No. 1-5324) 4.1.3 Second Supplemental Indenture dated as of March 1, 1992 between Northeast Utilities and IBJ Schroder Bank & Trust Company with respect to the issuance of 8.38% Amortizing Notes. (Exhibit 4.1.3, 1992 NU Form 10-K, File No. 1-5324) 4.1.4 Warrant Agreement dated as of June 5, 1992 between Northeast Utilities and the Service Company. (Exhibit 4.1.4, 1992 NU Form 10-K, File No. 1-5324) 4.1.4.1 Additional Warrant Agent Agreement dated as of June 5, 1992 between Northeast Utilities and State Street Bank and Trust Company. (Exhibit 4.1.4.1, 1992 NU Form 10-K, File No. 1-5324) 4.1.4.2 Exchange and Disbursing Agent Agreement dated as of June 5, 1992 among Northeast Utilities, Public Service Company of New Hampshire and State Street Bank and Trust Company. Exhibit 4.1.4.2, 1992 NU Form 10-K, File No. 1-5324) 4.1.5 Credit Agreements among CL&P, NU, WMECO, NUSCO (as Agent) and 15 Commercial Banks dated December 3, 1992 (364 Day and Three-Year Facilities). (Exhibit C.2.38, 1992 NU Form U5S, File No. 30-246) 4.1.6 Credit Agreements among CL&P, WMECO, NU, Holyoke Water Power Company, RRR, NNECO and NUSCO (as Agent) and 2 commercial banks dated December 3, 1992 (364 Day and Three-Year Facilities). (Exhibit C.2.39, 1992 NU Form U5S, File No. 30-246) 4.2 The Connecticut Light and Power Company 4.2.1 Indenture of Mortgage and Deed of Trust between CL&P and Bankers Trust Company, Trustee, dated as of May 1, 1921. (Composite including all twenty-four amendments to May 1, 1967.) (Exhibit 4.1.1, 1989 NU Form 10-K, File No. 1-5324) Supplemental Indentures to the Composite May 1, 1921 Indenture of Mortgage and Deed of Trust between CL&P and Bankers Trust Company, dated as of: 4.2.2 April 1, 1967. (Exhibit 4.16, File No. 2-60806) 4.2.3 January 1, 1968. (Exhibit 4.18, File No. 2-60806) 4.2.4 December 1, 1969. (Exhibit 4.20, File No. 2-60806) 4.2.5 June 30, 1982. (Exhibit 4.33, File No. 2-79235) 4.2.6 December 1, 1989. (Exhibit 4.1.26, 1989 NU Form 10-K, File No. 1-5324) 4.2.7 April 1, 1992. (Exhibit 4.30, File No. 33-59430) 4.2.8 July 1, 1992. (Exhibit 4.31, File No. 33-59430) 4.2.9 July 1, 1993. (Exhibit A.10(b), File No. 70-8249) 4.2.10 July 1, 1993. (Exhibit A.10(b), File No. 70-8249) 4.2.11 December 1, 1993. (Exhibit 4.2.14, 1993 NU Form 10-K, File No. 1-5324) 4.2.12 February 1, 1994. (Exhibit 4.2.15, 1993 NU Form 10-K, File No. 1-5324) 4.2.13 February 1, 1994. (Exhibit 4.2.16, 1993 NU Form 10-K, File No. 1-5324) 4.2.14 June 1, 1994. (Exhibit 4.2.15, 1994 NU Form 10-K, File No. 1-5324) 4.2.15 October 1, 1994. (Exhibit 4.2.16, 1994 NU Form 10-K, File No. 1-5324) 4.2.16 Financing Agreement between Industrial Development Authority of the State of New Hampshire and CL&P (Pollution Control Bonds, 1986 Series) dated as of December 1, 1986. (Exhibit C.1.47, 1986 NU Form U5S, File No. 30-246) 4.2.16.1 Letter of Credit and Reimbursement Agreement (Pollution Control Bonds, 1986 Series) dated as of August 1, 1994. (Exhibit 1 (Execution Copy), File No. 70-7320) 4.2.17 Financing Agreement between Industrial Development Authority of the State of New Hampshire and CL&P (Pollution Control Bonds, 1988 Series) dated as of October 1, 1988. (Exhibit C.1.55, 1988 NU Form U5S, File No. 30-246) # 4.2.17.1 Letter of Credit (Pollution Control Bonds, 1988 Series) dated October 27, 1988. # 4.2.17.2 Reimbursement and Security Agreement (Pollution Control Bonds, 1988 Series) dated as of October 1, 1988. 4.2.18 Financing Agreement between Industrial Development Authority of the State of New Hampshire and CL&P (Pollution Control Bonds) dated as of December 1, 1989. (Exhibit C.1.39, 1989 NU Form U5S, File No. 30-246) 4.2.19 Loan and Trust Agreement among Business Finance Authority of the State of New Hampshire, CL&P and the Trustee (Pollution Control Bonds, 1992 Series A) dated as of December 1, 1992.(Exhibit C.2.33, 1992 NU Form U5S, File No. 30-246) # 4.2.19.1 Letter of Credit and Reimbursement Agreement (Pollution Control Bonds, 1992 Series A) dated as of December 1, 1992. 4.2.20 Loan Agreement between Connecticut Development Authority and CL&P (Pollution Control Bonds - Series A, Tax Exempt Refunding) dated as of September 1, 1993. (Exhibit 4.2.21, 1993 NU Form 10-K, File No. 1-5324) 4.2.20.1 Letter of Credit and Reimbursement Agreement (Pollution Control Bonds - Series A, Tax Exempt Refunding) dated as of September 1, 1993. (Exhibit 4.2.23, 1993 NU Form 10-K, File No. 1- 5324) 4.2.21 Loan Agreement between Connecticut Development Authority and CL&P (Pollution Control Bonds - Series B, Tax Exempt Refunding) dated as of September 1, 1993. (Exhibit 4.2.22, 1993 NU Form 10-K, File No. 1-5324) 4.2.21.1 Letter of Credit and Reimbursement Agreement (Pollution Control Bonds - Series B, Tax Exempt Refunding) dated as of September 1, 1993. (Exhibit 4.2.24, 1993 NU Form 10-K, File No. 1- 5324) 4.2.22 Amended and Restated Limited Partnership Agreement (CL&P Capital, L.P.) among CL&P, NUSCO, and the persons who became limited partners of CL&P Capital, L.P. in accordance with the provisions thereof dated as of January 23, 1995 (MIPS). (Exhibit A.1 (Execution Copy), File No. 70-8451) 4.2.23 Indenture between CL&P and Bankers Trust Company, Trustee (Series A Subordinated Debentures), dated as of January 1, 1995 (MIPS). (Exhibit B.1 (Execution Copy), File No. 70- 8451) 4.2.24 Payment and Guaranty Agreement of CL&P dated as of January 23, 1995 (MIPS). (Exhibit B.3 (Execution Copy), File No. 70-8451) 4.3 Public Service Company of New Hampshire 4.3.1 First Mortgage Indenture dated as of August 15, 1978 between PSNH and First Fidelity Bank, National Association,New Jersey, Trustee, (Composite including all amendments to May 16, 1991). (Exhibit 4.4.1, 1992 NU Form 10-K, File No. 1-5324) 4.3.1.1 Tenth Supplemental Indenture dated as of May 1, 1991 between PSNH and First Fidelity Bank, National Association. (Exhibit 4.1, PSNH Current Report on Form 8-K dated February 10, 1992, File No. 1-6392). 4.3.2 Revolving Credit Agreement dated as of May 1, 1991. (Exhibit 4.12, PSNH Current Report on Form 8-K dated February 10, 1992, File No. 1-6392) 4.3.3 Series A (Tax Exempt New Issue) PCRB Loan and Trust Agreement dated as of May 1, 1991. (Exhibit 4.2, PSNH Current Report on Form 8-K dated February 10, 1992, File No. 1-6392) 4.3.4 Series B (Tax Exempt Refunding) PCRB Loan and Trust Agreement dated as of May 1, 1991. (Exhibit 4.3, PSNH Current Report on Form 8-K dated February 10, 1992, File No. 1-6392) 4.3.5 Series C (Tax Exempt Refunding) PCRB Loan and Trust Agreement dated as of May 1, 1991. (Exhibit 4.4, PSNH Current Report on Form 8-K dated February 10, 1992, File No. 1-6392) 4.3.6 Series D (Taxable New Issue) PCRB Loan and Trust Agreement dated as of May 1, 1991. (Exhibit 4.5, PSNH Current Report on Form 8-K dated February 10, 1992, File No. 1-6392) 4.3.6.1 First Supplement to Series D (Tax Exempt Refunding Issue) PCRB Loan and Trust Agreement dated as of December 1, 1992. (Exhibit 4.4.5.1, 1992 NU Form 10-K, File No. 1-5324) 4.3.6.2 Second Series D (May 1, 1991 Taxable New Issue and December 1, 1992 Tax Exempt Refunding Issue) PCRB Letter of Credit and Reimbursement Agreement dated as of May 1, 1995 (Exhibit B.4, Execution Copy, File No. 70-8036) 4.3.7 Series E (Taxable New Issue) PCRB Loan and Trust Agreement dated as of May 1, 1991. (Exhibit 4.6, PSNH Current Report on Form 8-K dated February 10, 1992, File No. 1-6392) 4.3.7.1 First Supplement to Series E (Tax Exempt Refunding Issue) PCRB Loan and Trust Agreement dated as of December 1, 1993. (Exhibit 4.3.8.1, 1993 NU Form 10-K, File No. 1-5324) 4.3.7.2 Second Series E (May 1, 1991 Taxable New Issue and December 1, 1993 Tax Exempt Refunding Issue) PCRB Letter of Credit and Reimbursement Agreement dated as of May 1, 1995. (Exhibit B.5, Execution Copy, File No. 70-8036) 4.4 Western Massachusetts Electric Company 4.4.1 First Mortgage Indenture and Deed of Trust between WMECO and Old Colony Trust Company, Trustee, dated as of August 1, 1954. (Exhibit 4.4.1, 1993 NU Form 10-K, File No. 1-5324) Supplemental Indentures thereto dated as of: 4.4.2 March 1, 1967. (Exhibit 2.5, File No. 2-68808) 4.4.3 September 1, 1990. (Exhibit 4.3.15, 1990 NU Form 10-K, File No. 1-5324.) 4.4.4 December 1, 1992. (Exhibit 4.15, File No. 33-55772) 4.4.5 January 1, 1993. (Exhibit 4.5.13, 1992 NU Form 10-K, File No. 1-5324) 4.4.6 March 1, 1994. (Exhibit 4.4.11, 1993 NU Form 10-K, File No. 1-5324) 4.4.7 March 1, 1994. (Exhibit 4.4.12, 1993 NU Form 10-K, File No. 1-5324) 4.4.8 Loan Agreement between Connecticut Development Authority and WMECO, (Pollution Control Bonds - Series A, Tax Exempt Refunding) dated as of September 1, 1993. (Exhibit 4.4.13, 1993 NU Form 10-K, File No. 1-5324) 4.4.8.1 Letter of Credit and Reimbursement Agreement (Pollution Control Bonds - Series A, Tax Exempt Refunding) dated as of September 1, 1993. (Exhibit 4.4.14, 1993 NU Form 10-K, File No. 1- 5324) 4.5 North Atlantic Energy Corporation 4.5.1 First Mortgage Indenture and Deed of Trust between NAEC and United States Trust Company of New York, Trustee, dated as of June 1, 1992. (Exhibit 4.6.1, 1992 NU Form 10-K, File No. 1-5324) ## 4.5.2 Term Credit Agreement dated as of November 9, 1995. 10 Material Contracts 10.1 Stockholder Agreement dated as of July 1, 1964 among the stockholders of Connecticut Yankee Atomic Power Company (CYAPC). (Exhibit 10.1, 1994 NU Form 10-K, File No. 1-5324) 10.2 Form of Power Contract dated as of July 1, 1964 between CYAPC and each of CL&P, HELCO, PSNH and WMECO. (Exhibit 10.2, 1994 NU Form 10-K, File No. 1-5324) 10.2.1 Form of Additional Power Contract dated as of April 30, 1984, between CYAPC and each of CL&P, PSNH and WMECO. (Exhibit 10.2.1, 1994 NU Form 10-K, File No. 1-5324) 10.2.2 Form of 1987 Supplementary Power Contract dated as of April 1, 1987, between CYAPC and each of CL&P, PSNH and WMECO. (Exhibit 10.2.6, 1987 NU Form 10-K, File No. 1-5324) 10.3 Capital Funds Agreement dated as of September 1, 1964 between CYAPC and CL&P, HELCO, PSNH and WMECO. (Exhibit 10.3, 1994 NU Form 10-K, File No. 1-5324) 10.4 Stockholder Agreement dated December 10, 1958 between Yankee Atomic Electric Company (YAEC) and CL&P, HELCO, PSNH and WMECO. (Exhibit 10.4, 1993 NU Form 10-K, File No. 1-5324) 10.5 Form of Amendment No. 3, dated as of April 1, 1985, to Power Contract between YAEC and each of CL&P, PSNH and WMECO, including a composite restatement of original Power Contract dated June 30, 1959 and Amendment No. 1 dated April 1, 1975 and Amendment No. 2 dated October 1, 1980. (Exhibit 10.5, 1988 NU Form 10-K, File No. 1-5324.) 10.5.1 Form of Amendment No. 4 to Power Contract, dated May 6, 1988, between YAEC and each of CL&P, PSNH and WMECO. (Exhibit 10.5.1, 1989 NU Form 10-K, File No. 1-5324) 10.5.2 Form of Amendment No. 5 to Power Contract, dated June 26, 1989, between YAEC and each of CL&P, PSNH and WMECO. (Exhibit 10.5.2, 1989 NU Form 10-K, File No. 1-5324) 10.5.3 Form of Amendment No. 6 to Power Contract, dated July 1,1989, between YAEC and each of CL&P, PSNH and WMECO. (Exhibit 10.5.3, 1989 NU Form 10-K, File No. 1-5324) 10.5.4 Form of Amendment No. 7 to Power Contract, dated February 1, 1992, between YAEC and each of CL&P, PSNH and WMECO. (Exhibit 10.5.4, 1993 NU Form 10-K, File No. 1-5324) 10.6 Stockholder Agreement dated as of May 20, 1968 among stockholders of MYAPC. (Exhibit 4.15, File No. 2-30018) 10.7 Form of Power Contract dated as of May 20, 1968 between MYAPC and each of CL&P, HELCO, PSNH and WMECO. (Exhibit 4.14, File No. 2-30018) 10.7.1 Form of Amendment No. 1 to Power Contract dated as of March 1, 1983 between MYAPC and each of CL&P, PSNH and WMECO. (Exhibit 10.7.1, 1993 NU Form 10-K, File No. 1-5324) 10.7.2 Form of Amendment No. 2 to Power Contract dated as of January 1, 1984 between MYAPC and each of CL&P, PSNH and WMECO. (Exhibit 10.7.2, 1993 NU Form 10-K, File No. 1- 5324) 10.7.3 Form of Amendment No. 3 to Power Contract dated as of October 1, 1984 between MYAPC and each of CL&P, PSNH and WMECO. (Exhibit No. 10.7.3, 1994 NU Form 10-K, File No. 1- 5324) 10.7.4 Form of Additional Power Contract dated as of February 1, 1984 between MYAPC and each of CL&P, PSNH and WMECO. (Exhibit 10.7.4, 1993 NU Form 10-K, File No. 1-5324) 10.8 Capital Funds Agreement dated as of May 20, 1968 between Maine Yankee Atomic Power Company (MYAPC) and CL&P, PSNH, HELCO and WMECO. (Exhibit 4.13, File No. 2-30018) 10.8.1 Amendment No. 1 to Capital Funds Agreement, dated as of August 1, 1985, between MYAPC, CL&P, PSNH and WMECO. (Exhibit No. 10.8.1, 1994 NU Form 10-K, File No. 1-5324) 10.9 Sponsor Agreement dated as of August 1, 1968 among the sponsors of VYNPC. (Exhibit 4.16, File No. 2-30285) 10.10 Form of Power Contract dated as of February 1, 1968 between VYNPC and each of CL&P, HELCO, PSNH and WMECO. (Exhibit 4.18, File No. 2- 30018) 10.10.1 Form of Amendment to Power Contract dated as of June 1, 1972 between VYNPC and each of CL&P, HELCO, PSNH and WMECO. (Exhibit 5.22, File No. 2-47038) 10.10.2 Form of Second Amendment to Power Contract dated as of April 15, 1983 between VYNPC and each of CL&P, PSNH and WMECO. (Exhibit 10.10.2, 1993 NU Form 10-K, File No. 1- 5324) 10.10.3 Form of Third Amendment to Power Contract dated as of April 24, 1985 between VYNPC and each of CL&P, PSNH and WMECO. (Exhibit No. 10.10.3, 1994 NU Form 10-K, File No. 1-5324) 10.10.4 Form of Fourth Amendment to Power Contract dated as of June 1, 1985 between VYNPC and each of CL&P, PSNH and WMECO. (Exhibit 10.10.4, 1986 NU Form 10-K, File No. 5324) 10.10.5 Form of Fifth Amendment to Power Contract dated as of May 6, 1988 between VYNPC and each of CL&P, PSNH and WMECO. (Exhibit 10.10.5, 1990 NU Form 10-K, File No. 1-5324) 10.10.6 Form of Sixth Amendment to Power Contract dated as of May 6, 1988 between VYNPC and each of CL&P, PSNH and WMECO. (Exhibit 10.10.6, 1990 NU Form 10-K, File No. 1-5324) 10.10.7 Form of Seventh Amendment to Power Contract dated as of June 15, 1989 between VYNPC and each of CL&P, PSNH and WMECO. (Exhibit 10.10.7, 1990 NU Form 10-K, File No. 1-5324) 10.10.8 Form of Eighth Amendment to Power Contract dated as of December 1, 1989 between VYNPC and each of CL&P, PSNH and WMECO. (Exhibit 10.10.8, 1990 NU Form 10-K, File No. 1- 5324) 10.10.9 Form of Additional Power Contract dated as of February 1, 1984 between VYNPC and each of CL&P, PSNH and WMECO. (Exhibit 10.10.9, 1993 NU Form 10-K, File No. 1-5324) 10.11 Capital Funds Agreement dated as of February 1, 1968 between Vermont Yankee Nuclear Power Corporation (VYNPC) and CL&P, HELCO, PSNH and WMECO. (Exhibit 4.16, File No. 2-30018) 10.11.1 Form of First Amendment to Capital Funds Agreement dated as of March 12, 1968 between VYNPC and CL&P, HELCO, PSNH and WMECO. (Exhibit 4.17, File No. 2-30018) 10.11.2 Form of Second Amendment to Capital Funds Agreement dated as of September 1, 1993 between VYNPC and CL&P, HELCO, PSNH and WMECO. (Exhibit 10.11.2, 1993 NU Form 10-K, File No. 1- 5324) 10.12 Amended and Restated Millstone Plant Agreement dated as of December 1, 1984 by and among CL&P, WMECO and Northeast Nuclear Energy Company (NNECO). (Exhibit 10.12, 1994 NU Form 10-K, File No. 1-5324) 10.13 Sharing Agreement dated as of September 1, 1973 with respect to 1979 Connecticut nuclear generating unit (Millstone 3). (Exhibit 6.43, File No. 2-50142) 10.13.1 Amendment dated August 1, 1974 to Sharing Agreement - 1979 Connecticut Nuclear Unit. (Exhibit 5.45, File No. 2-52392) 10.13.2 Amendment dated December 15, 1975 to Sharing Agreement - 1979 Connecticut Nuclear Unit. (Exhibit 7.47, File No. 2- 60806) 10.13.3 Amendment dated April 1, 1986 to Sharing Agreement - 1979 Connecticut Nuclear Unit. (Exhibit 10.17.3, 1990 NU Form 10-K, File No. 1-5324) 10.14 Agreement dated July 19, 1990, among NAESCO and Seabrook Joint owners with respect to operation of Seabrook. (Exhibit 10.53, 1990 NU Form 10-K, File No. 1-5324) 10.15 Sharing Agreement between CL&P, WMECO, HP&E, HWP and PSNH dated as of June 1, 1992. (Exhibit 10.17, 1992 NU Form 10-K, File No. 1-5324) 10.16 Rate Agreement by and between NUSCO, on behalf of NU, and the Governor of the State of New Hampshire and the New Hampshire Attorney General dated as of November 22, 1989. (Exhibit 10.44, 1989 NU Form 10-K, File No. 1-5324) * 10.16.1 First Amendment to Rate Agreement dated as of December 5, 1989. * 10.16.2 Second Amendment to Rate Agreement dated as of December 12, 1989. * 10.16.3 Third Amendment to Rate Agreement dated as of December 3, 1993. * 10.16.4 Fourth Amendment to Rate Agreement dated as of September 21, 1994. * 10.16.5 Fifth Amendment to Rate Agreement dated as of September 9, 1994. 10.17 Form of Seabrook Power Contract between PSNH and NAEC, as amended and restated. (Exhibit 10.45, NU 1992 Form 10-K, File No. 1-5324) 10.18 Agreement (composite) for joint ownership, construction and operation of New Hampshire nuclear unit, as amended through the November 1, 1990 twenty-third amendment. (Exhibit No. 10.17, 1994 NU Form 10-K, File No. 1-5324) 10.18.1 Memorandum of Understanding dated November 7, 1988 between PSNH and Massachusetts Municipal Wholesale Electric Company (Exhibit 10.17, PSNH 1989 Form 10-K, File No. 1-6392) 10.18.2 Agreement of Settlement among Joint Owners dated as of January 13, 1989. (Exhibit 10.13.21, 1988 NU Form 10-K, File No. 1-5324) 10.18.2.1 Supplement to Settlement Agreement, dated as of February 7, 1989, between PSNH and Central Maine Power Company. (Exhibit 10.18.1, PSNH 1989 Form 10-K, File No. 1-6392) 10.19 Amended and Restated Agreement for Seabrook Project Disbursing Agent dated as of November 1, 1990. (Exhibit 10.4.7, File No. 33-35312) 10.19.1 Form of First Amendment to Exhibit 10.19. (Exhibit 10.4.8, File No. 33-35312) 10.19.2 Form (Composite) of Second Amendment to Exhibit 10.19. (Exhibit 10.18.2, 1993 NU Form 10-K, File No. 1-5324) 10.20 Agreement dated November 1, 1974 for Joint Ownership, Construction and Operation of William F. Wyman Unit No. 4 among PSNH, Central Maine Power Company and other utilities. (Exhibit 5.16 , File No. 2-52900) 10.20.1 Amendment to Exhibit 10.20 dated June 30, 1975. (Exhibit 5.48, File No. 2-55458) 10.20.2 Amendment to Exhibit 10.20 dated as of August 16, 1976. (Exhibit 5.19, File No. 2-58251) 10.20.3 Amendment to Exhibit 10.20 dated as of December 31, 1978. (Exhibit 5.10.3, File No. 2-64294) 10.21 Form of Service Contract dated as of July 1, 1966 between each of NU, CL&P and WMECO and the Service Company. (Exhibit 10.20, 1993 NU Form 10-K, File No. 1-5324) 10.21.1 Service Contract dated as of June 5, 1992 between PSNH and the Service Company. (Exhibit 10.12.4, 1992 NU Form 10-K, File No. 1-5324) 10.21.2 Service Contract dated as of June 5, 1992 between NAEC and the Service Company. (Exhibit 10.12.5, 1992 NU Form 10-K, File No. 1-5324) 10.21.3 Form of Annual Renewal of Service Contract. (Exhibit 10.20.3, 1993 NU Form 10-K, File No. 1-5324) 10.22 Memorandum of Understanding between CL&P, HELCO, HP&E, HWP and WMECO dated as of June 1, 1970 with respect to pooling of generation and transmission. (Exhibit 13.32, File No. 2-38177) 10.22.1 Amendment to Memorandum of Understanding between CL&P, HELCO, HP&E, HWP and WMECO dated as of February 2, 1982 with respect to pooling of generation and transmission. (Exhibit 10.21.1, 1993 NU Form 10-K, File No. 1-5324) 10.22.2 Amendment to Memorandum of Understanding between CL&P, HELCO, HP&E, HWP and WMECO dated as of January 1, 1984 with respect to pooling of generation and transmission. (Exhibit 10.21.2, 1994 NU Form 10-K, File No. 1-5324) 10.23 New England Power Pool Agreement effective as of November 1, 1971, as amended to November 1, 1988. (Exhibit 10.15, 1988 NU Form 10-K, File No. 1-5324.) 10.23.1 Twenty-sixth Amendment to Exhibit 10.23 dated as of March 15, 1989. (Exhibit 10.15.1, 1990 NU Form 10-K, File No. 1- 5324) 10.23.2 Twenty-seventh Amendment to Exhibit 10.23 dated as of October 1, 1990. (Exhibit 10.15.2, 1991 NU Form 10-K, File No. 1-5324) 10.23.3 Twenty-eighth Amendment to Exhibit 10.23 dated as of September 15, 1992. (Exhibit 10.18.3, 1992 NU Form 10-K, File No. 1-5324) 10.23.4 Twenty-ninth Amendment to Exhibit 10.23 dated as of May 1, 1993. (Exhibit 10.22.4, 1993 NU Form 10-K, File No. 1-5324) * 10.23.5 Thirty-second Amendment (Amendments 30 and 31 were withdrawn) to Exhibit 10.23 dated as of September 1, 1995. 10.24 Agreements among New England Utilities with respect to the Hydro- Quebec interconnection projects. (See Exhibits 10(u) and 10(v); 10(w), 10(x), and 10(y), 1990 and 1988, respectively, Form 10-K of New England Electric System, File No. 1-3446.) 10.25 Trust Agreement dated February 11, 1992, between State Street Bank and Trust Company of Connecticut, as Trustor, and Bankers Trust Company, as Trustee, and CL&P and WMECO, with respect to NBFT. (Exhibit 10.23, 1991 NU Form 10-K, File No. 1-5324) 10.25.1 Nuclear Fuel Lease Agreement dated as of February 11, 1992, between Bankers Trust Company, Trustee, as Lessor, and CL&P and WMECO, as Lessees. (Exhibit 10.23.1, 1991 NU Form 10-K, File No. 1-5324) 10.26 Simulator Financing Lease Agreement, dated as of February 1, 1985, by and between ComPlan and NNECO. (Exhibit 10.25, 1994 NU Form 10-K, File No. 1-5324) 10.27 Simulator Financing Lease Agreement, dated as of May 2, 1985, by and between The Prudential Insurance Company of America and NNECO. (Exhibit No. 10.26, 1994 NU Form 10-K, File No. 1-5324) 10.28 Lease dated as of April 14, 1992 between The Rocky River Realty Company (RRR) and Northeast Utilities Service Company (NUSCO) with respect to the Berlin, Connecticut headquarters (office lease). (Exhibit 10.29, 1992 NU Form 10-K, File No. 1-5324) 10.28.1 Lease dated as of April 14, 1992 between RRR and NUSCO with respect to the Berlin, Connecticut headquarters (project lease). (Exhibit 10.29.1, 1992 NU Form 10-K, File No. 1- 5324) 10.29 Millstone Technical Building Note Agreement dated as of December 21, 1993 between, by and between The Prudential Insurance Company of America and NNECO. (Exhibit 10.28, 1993 NU Form 10-K, File No. 1- 5324) 10.30 Lease and Agreement, dated as of December 15, 1988, by and between WMECO and Bank of New England, N.A., with BNE Realty Leasing Corporation of North Carolina. (Exhibit 10.63, 1988 NU Form 10-K, File No. 1-5324.) 10.31 Note Agreement dated April 14, 1992, by and between The Rocky River Realty Company (RRR) and Purchasers named therein (Connecticut General Life Insurance Company, Life Insurance Company of North America, INA Life Insurance Company of New York, Life Insurance Company of Georgia), with respect to RRR's sale of $15 million of guaranteed senior secured notes due 2007 and $28 million of guaranteed senior secured notes due 2017. (Exhibit 10.52, 1992 NU Form 10-K, File No. 1-5324) 10.31.1 Note Guaranty dated April 14, 1992 by Northeast Utilities pursuant to Note Agreement dated April 14, 1992 between RRR and Note Purchasers, for the benefit of The Connecticut National Bank as Trustee, the Purchasers and the owners of the notes. (Exhibit 10.52.1, 1992 NU Form 10-K, File No. 1- 5324) 10.31.2 Assignment of Leases, Rents and Profits, Security Agreement and Negative Pledge, dated as of April 14, 1992 among RRR, NUSCO and The Connecticut National Bank as Trustee, securing notes sold by RRR pursuant to April 14, 1992 Note Agreement. (Exhibit 10.52.2, 1992 NU Form 10-K, File No. 1-5324) 10.32 Master Trust Agreement dated as of September 2, 1986 between CL&P and WMECO and Colonial Bank as Trustee, with respect to reserve funds for Millstone 1 decommissioning costs. (Exhibit 10.80, 1986 NU Form 10-K, File No. 1-5324) 10.32.1 Notice of Appointment of Mellon Bank, N.A. as Successor Trustee, dated November 20, 1990, and Acceptance of Appointment. (Exhibit 10.41.1, 1992 NU Form 10-K, File No. 1-5324) 10.33 Master Trust Agreement dated as of September 2, 1986 between CL&P and WMECO and Colonial Bank as Trustee, with respect to reserve funds for Millstone 2 decommissioning costs. (Exhibit 10.81, 1986 NU Form 10-K, File No. 1-5324) 10.33.1 Notice of Appointment of Mellon Bank, N.A. as Successor Trustee, dated November 20, 1990, and Acceptance of Appointment. (Exhibit 10.42.1, 1992 NU Form 10-K, File No. 1-5324) 10.34 Master Trust Agreement dated as of April 23, 1986 between CL&P and WMECO and Colonial Bank as Trustee, with respect to reserve funds for Millstone 3 decommissioning costs. (Exhibit 10.82, 1986 NU Form 10-K, File No. 1-5324) 10.34.1 Notice of Appointment of Mellon Bank, N.A. as Successor Trustee, dated November 20, 1990, and Acceptance of Appointment. (Exhibit 10.43.1, 1992 NU Form 10-K, File No. 1-5324) 10.35 NU Executive Incentive Plan, effective as of January 1, 1991. (Exhibit 10.44, NU 1991 Form 10-K, File No. 1-5324) 10.36 Supplemental Executive Retirement Plan for Officers of NU System Companies, Amended and Restated effective as of January 1, 1992. (Exhibit 10.45.1, NU Form 10-Q for the Quarter Ended June 30, 1992, File No. 1-5324) 10.36.1 Amendment 1 to Exhibit 10.36, effective as of August 1, 1993. (Exhibit 10.35.1, 1993 NU Form 10-K, File No. 1-5324) 10.36.2 Amendment 2 to Exhibit 10.36, effective as of January 1, 1994. (Exhibit 10.35.2, 1993 NU Form 10-K, File No. 1-5324) * 10.36.3 Amendment 3 to Exhibit 10.36, effective as of January 1, 1996. 10.37 Loan Agreement dated as of December 2, 1991, by and between NU and Mellon Bank, N.A., as Trustee, with respect to NU's loan of $175 million to an ESOP Trust. (Exhibit 10.46, NU 1991 Form 10-K, File No. 1-5324) 10.37.1 First Amendment to Exhibit 10.37 dated February 7, 1992. (Exhibit 10.36.1, 1993 NU Form 10-K, File No. 1-5324) 10.37.2 Loan Agreement dated as of March 19, 1992 by and between NU and Mellon Bank, N.A., as Trustee, with respect to NU's loan of $75 million to the ESOP Trust. (Exhibit 10.49.1, 1992 NU Form 10-K, File No. 1-5324) 10.37.3 Second Amendment to Exhibit 10.37 dated April 9, 1992. (Exhibit 10.36.3, 1993 NU Form 10-K, File No. 1-5324) 10.38 Employment Agreement. (Exhibit 10.48, NU Form 10-Q for the Quarter Ended June 30, 1992, File No. 1-5324) * 10.39 Northeast Utilities Deferred Compensation Plan for Trustees, Amended and Restated December 13, 1994. * 10.40 Deferred Compensation Plan for Officers of Northeast Utilities System Companies adopted September 23, 1986. * 10.41 Reciprocal Support Agreement Among NNECO, NAESCO, CYAPC, YAEC and NUSCO dated January 1, 1996. 13 Annual Report to Security Holders (Each of the Annual Reports is filed only with the Form 10-K of that respective registrant.) * 13.1 Portions of the Annual Report to Shareholders of NU (pages 15-46) that have been incorporated by reference into this Form 10-K. 13.2 Annual Report of CL&P. 13.3 Annual Report of WMECO. 13.4 Annual Report of PSNH. 13.5 Annual Report of NAEC. *21 Subsidiaries of the Registrant. 27 Financial Data Schedules (Each Financial Data Schedule is filed only with the Form 10-K of that respective registrant.) 27.1 Financial Data Schedule of NU. 27.2 Financial Data Schedule of CL&P. 27.3 Financial Data Schedule of WMECO. 27.4 Financial Data Schedule of PSNH. 27.5 Financial Data Schedule of NAEC. EX-4.1 2 CL&P 1988 PCB LOC EXHIBIT 4.2.17.1 October 27, 1988 Irrevocable Letter of Credit No. 84179 Chemical Bank, as agent for the Trustee under Indenture of Trust dated as of October 1, 1988 Dear Sirs: At the request, on the instructions and for the account, of The Connecticut Light and Power Company, a Connecticut corporation (the "Company"), we hereby establish this irrevocable Letter of Credit in your favor, as agent for the Trustee under Indenture of Trust dated as of October 1, 1988 between The Industrial Development Authority of the State of New Hampshire (the "Issuer") and Baybank Middlesex (the "Trustee") as Trustee, (the "Indenture") pursuant to which $10,000,000 in aggregate principal amount of the Issuer's Pollution Control Revenue Bonds (The Connecticut Light and Power Company Project) Series 1988 (the "Bonds") were issued. We hereby irrevocably authorize you to draw on us in accordance with the terms and conditions hereinafter set forth, an aggregate amount not exceeding $10,833,334 (as reduced from time to time in accordance with the provisions hereof, the "Stated Amount") of which an aggregate amount not exceeding $10,000,000 may be drawn upon with respect to principal of the Bonds (or the principal portion of the purchase price of Bonds purchased pursuant to Section 2.4 of the Indenture) and of which an aggregate amount not exceeding $833,334 (representing 200 days of interest at 15% per annum) may be drawn upon with respect to interest on the Bonds (or the interest portion of the purchase price of Bonds purchased pursuant to Section 2.4 of the Indenture). Subject to the foregoing and the further provisions of this Letter of Credit, a demand for payment may be made by you by presentation to us at 299 Park Avenue, New York, New York 10171 (Attention: Letter of Credit Department) of your sight draft(s), accompanied by your drawing certificate: (a) in the form of Annex A attached hereto (an "A Drawing") if the drawing is made with respect to the payment of principal of the Bonds upon the acceleration, redemption or stated maturity thereof; (b) in the form of Annex B attached hereto (a "B Drawing") if the drawing is made with respect to the payment of interest on the Bonds on or prior to their stated maturity date; (c) in the form of Annex C attached hereto (a "C Drawing") if the drawing is made with respect to the payment of the portion of the purchase price of Bonds tendered for purchase pursuant to Section 2.4 of the Indenture ("Pledged Bonds") equal to the principal amount of such Bonds; and (d) in the form of Annex D attached hereto (a "D Drawing") if the drawing is made with respect to the payment of the portion of the purchase price of Pledged Bonds equal to the amount of accrued and unpaid interest on such Bonds. The aforesaid certificates, which form an integral part of this Letter of Credit, shall have all blanks appropriately filled in and shall be signed by your authorized officer, and any sight draft and the aforesaid certificates shall be either in the form of a letter on your letterhead or a communication by telecopy or tested telex. Any telecopy or tested telex pursuant to which a drawing is made hereunder shall be promptly confirmed to us in a letter on your letterhead. Each sight draft drawn under this credit must bear on its face the clause "Drawn under Union Bank of Switzerland, New York Branch Letter of Credit No. 84179". Demand for payment may be made by you under this Letter of Credit prior to the expiration hereof at any time during the Bank's business hours at its aforesaid address, on a Business Day (as hereinafter defined). As used herein the term "Business Day" means any day except a Saturday, Sunday or other day on which commercial banks in the City of New York and in the cities in which the principal offices of the Trustee, the Registrar, the Paying Agent, and the Tender Agent (all as defined in the Indenture) are located are required by law, regulation or executive order to close or on which such banks are generally voluntarily closed for business in such locations and on which the New York Stock Exchange is open. If demand for payment is made by you hereunder at or prior to 1:00 P.M., New York City time, on a Business Day, and provided that such demand for payment and the documents presented in connection therewith conform to the terms and conditions hereto, payment shall be made to you of the amount demanded, in immediately available funds, not later than 3:00 P.M., New York City time, on the same Business Day. If demand for payment is made by you hereunder after 1:00 P.M., New York City time, on a Business Day, and provided that such demand for payment and the documents presented in connection therewith conform to the terms hereof, payment shall be made to you of the amount demanded, in immediately available funds, not later than 10:00 A.M., New York City time, on the next succeeding Business Day. The demand for payment hereunder shall not exceed the Stated Amount. The Stated Amount shall be reduced by delivery to us of your certificate in the form of Annex E in the amount specified in such certificate. The Stated Amount shall also be reduced by the amount of any drawing hereunder, except that (i) the amount of each B Drawing in respect of interest shall forthwith be restored unless we shall notify you no later than 16 days after a drawing in respect of interest that the same shall not be restored by reason of the failure of the Company to have reimbursed such drawing; and (ii) the amount of each C Drawing and D Drawing shall be restored upon release by us of the Pledged Bonds in respect of which such C Drawing and D Drawing were made. This Letter of Credit shall expire at our close of business at our aforesaid address on the earlier to occur of (i) the Expiration Date (or if the same is not a Business Day, the first Business Day following the Expiration Date) or (ii) the date on which we receive from the Trustee a certificate in the form of Annex F hereto. This Letter of Credit shall be promptly surrendered to us by you upon such expiration. The Expiration Date shall initially be August 19, 1993 and shall be automatically extended for successive additional twelve month periods unless we shall give you, not later than fifty-one months prior to the then-current Expiration Date, written notice of our election not so to extend the Expiration Date. This Letter of Credit sets forth in full the terms of our undertaking, and this undertaking shall not in any way be modified, amended, amplified or limited by reference to any document, instrument or agreement referred to herein or in which this Letter of Credit is referred to or to which this Letter of Credit relates, and any such reference shall not be deemed to incorporate herein by reference any document, instrument or agreement. This Letter of Credit is transferable in its entirety (but not in part) to any transferee who has succeeded Baybank Middlesex as Trustee under the Indenture and may be successively transferred. Transfer of this Letter of Credit to such transferee shall be effected by the presentation to us of this Letter of Credit accompanied by a certificate substantially in the form of Annex G attached hereto. Only you (or a transferee as permitted by the terms of this Letter of Credit) may make drawings under this Letter of Credit. Upon the payment to you or your account of the amount specified in a sight draft drawn hereunder, we shall be fully discharged on our obligation under this Letter of Credit with respect to such draft, and we shall not thereafter be obligated to make any further payments under this Letter of Credit in respect of such draft to you or to any other person who may have made to you or who makes to you a demand for payment of the purchase price or principal of, or interest on, any Bond. Except as otherwise stated, this Letter of Credit is subject to the Uniform Customs and Practice for Documentary Credits (1983 Revision), International Chamber of Commerce Publication No. 400 and, to the extent the same are not dispositive, this Letter of Credit shall be governed by, and construed in accordance with, New York law. Communications to us with respect to this Letter of Credit shall be in writing and be addressed to us at 299 Park Avenue, New York, New York 10171 (Attention: Letter of Credit Department), specifically referring to the number of this Letter of Credit. Communications to you with respect to this Letter of Credit shall be in writing and be addressed to you at 55 Water Street, Room 505, New York, New York. Very truly yours, UNION BANK OF SWITZERLAND, NEW YORK BRANCH By: /s/Charles E. Arnold By: /s/Susan E. Zieg Annex A DRAWING CERTIFICATE [Date] Union Bank of Switzerland, New York Branch 299 Park Avenue New York, New York 10171 Attention: Letter of Credit Department Re: Drawing Certificate Gentlemen: Chemical Bank (the "Beneficiary") hereby certifies to Union Bank of Switzerland, New York Branch (the "Bank") with reference to Irrevocable Letter of Credit No. 84179 (the "Letter of Credit"; the terms "Bonds", "Indenture", "Stated Amount" and "Trustee" as used herein having their respective meanings set forth in the Letter of Credit) that: 1. The Beneficiary is the agent for the Trustee under the Indenture. 2. The Beneficiary is making a demand for payment under the Letter of Credit with respect to $ to be used for the payment of principal of the Bonds. 3. The amount of this demand for payment was computed in accordance with the terms and conditions of the Bonds and the Indenture and is made in accordance with Section 5.7 of the Indenture. 4. The amount of principal of the Bonds which is due and payable is $ and is the amount of the sight draft accompanying this Certificate. 5. The amount hereby demanded does not exceed the portion of the Stated Amount available to be drawn under the Letter of Credit in respect of principal of the Bonds. 6. Upon receipt by the Beneficiary of the amount demanded hereby, (a) the Beneficiary will apply the same directly to the payment when due of the appropriate amount owing on account of the Bonds pursuant to the Indenture, (b) no portion of said amount shall be applied by the Beneficiary for any other purpose, and (c) no portion of said amount shall be commingled with other funds held by the Beneficiary. IN WITNESS WHEREOF, the Beneficiary has executed and delivered this Certificate as of the day of , 19 . CHEMICAL BANK, as agent for the Trustee By: Annex B DRAWING CERTIFICATE [Date] Union Bank of Switzerland, New York Branch 299 Park Avenue New York, New York 10171 Attention: Letter of Credit Department Re: Drawing Certificate Gentlemen: Chemical Bank (the "Beneficiary") hereby certifies to Union Bank of Switzerland, New York Branch (the "Bank") with reference to Irrevocable Letter of Credit No. 84179 (the "Letter of Credit"; the terms "Bonds", "Indenture", "Stated Amount" and "Trustee" as used herein having their respective meanings set forth in the Letter of Credit) that: 1. The Beneficiary is the agent for the Trustee under the Indenture. 2. The Beneficiary is making a demand for payment under the Letter of Credit with respect to $ to be used for the payment of interest on the Bonds on or prior to their stated maturity date. 3. The amount of this demand for payment was computed in accordance with the terms and conditions of the Bonds and the Indenture and is demanded in accordance with Section 5.7 of the Indenture. 4. The amount of interest on the Bonds which is due and payable is $ , and is the amount of the sight draft accompanying this Certificate. 5. The amount hereby demanded does not exceed the portion of the Stated Amount available to be drawn under the Letter of Credit in respect of interest on the Bonds. 6. Upon receipt by the Beneficiary of the amount demanded hereby, (a) the Beneficiary will apply the same directly to the payment when due of the appropriate amount owing on account of the Bonds pursuant to the Indenture, (b) no portion of said amount shall be applied by the Beneficiary for any other purpose, and (c) no portion of said amount shall be commingled with other funds held by the Beneficiary. IN WITNESS WHEREOF, the Beneficiary has executed and delivered this Certificate as of the day of , 19 . CHEMICAL BANK, as agent for the Trustee By: Annex C DRAWING CERTIFICATE [Date] Union Bank of Switzerland, New York Branch 299 Park Avenue New York, New York 10171 Attention: Letter of Credit Department Re: Drawing Certificate Gentlemen: Chemical Bank (the "Beneficiary") hereby certifies to Union Bank of Switzerland, New York Branch (the "Bank") with reference to Irrevocable Letter of Credit No. 84179 (the "Letter of Credit" the terms "Bonds", "Indenture", "Pledged Bonds", "Stated Amount" and "Trustee" as used herein having their respective meanings set forth in the Letter of Credit) that: 1. The Beneficiary is the agent for the Trustee under the Indenture. 2. The Beneficiary is making a demand for payment under the Letter of Credit to be applied to the payment of the portion of the purchase price of Bonds tendered for purchase pursuant to Section 2.4 of the Indenture, equal to the principal amount thereof. 3. The amount of this demand for payment was computed in accordance with the terms and conditions of the Bonds and the Indenture and is made in accordance with Section 5.7 of the Indenture. 4. The amount of the portion of the purchase price equal to the principal amount of such Bonds is $ , and is the amount of the sight draft accompanying this Certificate. 5. The amount hereby demanded does not exceed the portion of the Stated Amount available to be drawn under the Letter of Credit in respect of principal of the Bonds. 6. Upon receipt by the Beneficiary of the amount demanded hereby, (a) the Beneficiary will apply the same directly to the payment when due of the appropriate amount owing on account of the purchase price of Pledged Bonds pursuant to the Indenture, (b) no portion of said amount shall be applied by the Beneficiary for any other purpose, and (c) no portion of said amount shall be commingled with other funds held by the Beneficiary. IN WITNESS WHEREOF, the Beneficiary has executed and delivered this Certificate as of the day of , 19 . CHEMICAL BANK, as agent for the Trustee By: Annex D DRAWING CERTIFICATE [Date] Union Bank of Switzerland, New York Branch 299 Park Avenue New York, New York 10171 Attention: Letter of Credit Department Re: Drawing Certificate Gentlemen: Chemical Bank (the "Beneficiary") hereby certifies to Union Bank of Switzerland, New York Branch (the "Bank") with reference to Irrevocable Letter of Credit No. 84179 (the "Letter of Credit"; the terms "Bonds", "Indenture", "Pledged Bonds", "Stated Amount" and "Trustee" as used herein having their respective meanings set forth in the Letter of Credit) that: 1. The Beneficiary is the agent for the Trustee under the Indenture. 2. The Beneficiary is making a demand for payment under the Letter of Credit to be applied to the payment of the purchase price of Bonds tendered for purchase pursuant to Section 2.4 of the Indenture, equal to the amount of accrued and unpaid interest on such Bonds to the date of purchase thereof. 3. The amount of this demand for payment was computed in accordance with the terms and conditions of the Bonds and the Indenture and is made in accordance with Section 5.7 of the Indenture. 4. The amount of such portion of the purchase price equal to accrued and unpaid interest on such Bond to the date of purchase thereof is $ , and is the amount of the sight draft accompanying this Certificate. 5. The amount hereby demanded does not exceed the portion of the Stated Amount available to be drawn under the Letter of Credit in respect of interest on the Bonds. 6. Upon receipt by the Beneficiary of the amount demanded hereby, (a) the Beneficiary will apply the same directly to the payment when due of the appropriate amount owing on account of the purchase price of Pledged Bonds pursuant to the Indenture, (b) no portion of said amount shall be applied by the Beneficiary for any other purpose, and (c) no portion of said amount shall be commingled with other funds held by the Beneficiary. IN WITNESS WHEREOF, the Beneficiary has executed and delivered this Certificate as of the day of , 19 . CHEMICAL BANK, as agent for the Trustee By: ANNEX E [Date] Union Bank of Switzerland, New York Branch 299 Park Avenue New York, New York 10171 Attention: Letter of Credit Department Re: Irrevocable Letter of Credit No. 84179 Gentlemen: Chemical Bank (the "Beneficiary") hereby certifies to Union Bank of Switzerland, New York Branch (the "Bank") with reference to Irrevocable Letter of Credit No. 84179 (the "Letter of Credit"; the terms "Bonds", "Indenture", "Stated Amount" and "Trustee" as used herein having their respective meanings set forth in the Letter of Credit) that: 1. The Beneficiary is the agent for the Trustee under the Indenture. 2. The Beneficiary hereby notifies you that on or prior to the date hereof $ principal amount of the Bonds have been paid, redeemed or defeased pursuant to the Indenture from Priority amounts (as defined in the Indenture). 3. Following the payment, redemption or the defeasance referred to in paragraph (2) above, the aggregate principal amount of all of the Bonds outstanding is $ . 4. The amount of interest (computed at a rate of 15% per annum), accruing on the Bonds referred to in paragraph (3) above in any period of 200 days is $ . 5. The amount available to be drawn by the Beneficiary under the Letter of Credit in respect of interest on the Bonds or the portion of the purchase price of Pledged Bonds equal to accrued interest is reduced to $ (such amount being equal to the amount specified in paragraph 4 above) upon receipt by the Bank of this certificate. 6. The Stated Amount of the Letter of Credit is reduced to $ (such amount being equal to the sum of the amounts specified in paragraphs 3, and 4 above), upon receipt by the Bank of this certificate. IN WITNESS WHEREOF, the Beneficiary has executed and delivered this Certificate this day of , 19 . CHEMICAL BANK, as agent for the Trustee By: Annex F [Date] Union Bank of Switzerland, New York Branch 299 Park Avenue New York, New York 10171 Attention: Letter of Credit Department Re: Irrevocable Letter of Credit No. 84179 Gentlemen: Chemical Bank (the "Beneficiary") hereby certifies to Union Bank of Switzerland, New York Branch (the "Bank") with reference to Irrevocable Letter of Credit No. 84179 (the "Letter of Credit"; the terms "Bonds", "Indenture" and "Trustee" as used herein having their respective meanings set forth in the Letter of Credit) that: 1. The Beneficiary is the agent for the Trustee under the Indenture. 2. The Beneficiary hereby notifies you that all Bonds have been paid, redeemed or defeased pursuant to the Indenture from Priority Amounts (as defined in the Indenture) or the Letter of Credit is no longer required to be maintained pursuant to the Indenture. 3. The Letter of Credit is attached hereto and is being surrendered to you herewith. IN WITNESS WHEREOF, the Beneficiary has executed and delivered this Certificate this day of , 19 . CHEMICAL BANK, as agent for the Trustee By: Annex G [Date] Union Bank of Switzerland, New York Branch 299 Park Avenue New York, New York 10171 Dear Sirs: We refer to Letter of Credit No. 84179, issued in favor of CHEMICAL BANK, as agent for the Trustee in the amount of $ . For value received we hereby irrevocably transfer to , hereinafter referred to as the transferee, all rights of the undersigned to draw under the above Letter of Credit in its entirety. By this transfer, all rights of the undersigned in such Letter of Credit are transferred to the transferee and the transferee shall have the sole rights relating to any amendments whether increases or extensions or other amendments and whether now existing or hereafter made. All amendments are to be advised direct to the transferee without necessity of any consent of or notice to the undersigned. The Letter of Credit is returned herewith. Please notify the transferee of this transfer and the conditions of the Letter of Credit. In connection with the above transactions, we herewith hand you our check to the order of Union Bank of Switzerland, New York Branch for $ representing its transfer fee, which is to be considered earned whether or not any drafts are drawn and whether or not payments are made under the above Letter of Credit. We also agree to pay to you on demand any expenses which may be incurred by you in connection with this transfer. Very truly yours, (Signature of Transferer) SIGNATURE AUTHENTICATED (Bank) (Authorized Signature) EX-4.2 3 INSTRUMENT DEFINE RIGHTS - CL&P 1988 PCB RA & SA EXHIBIT 4.2.17.2 Reimbursement and Security Agreement REIMBURSEMENT AND SECURITY AGREEMENT, dated as of October 1, 1988 between The CONNECTICUT LIGHT AND POWER COMPANY, a Connecticut corporation (the "Company"), and UNION BANK OF SWITZERLAND, NEW YORK BRANCH (the "Bank") WHEREAS, The Industrial Development Authority of the State of New Hampshire (the "Issuer") proposes (i) to issue $10,000,000 aggregate principal amount of its Pollution Control Revenue Bonds (The Connecticut Light and Power Company Project) Series 1988 (the "Bonds") pursuant to an Indenture of Trust dated as of October 1, 1988 (the "Indenture"), between the Issuer and Baybank Middlesex, as trustee (the "Trustee"), and (ii) to lend the proceeds of the sale of the Bonds to the Company pursuant to a Financing Agreement between the Issuer and the Company, dated as of October 1, 1988 (the "Loan Agreement"); WHEREAS, in order to provide security for the payment when due of the principal of, and interest on, the Bonds, the Company has requested the Bank to issue an irrevocable letter of credit substantially in the form of Exhibit A hereto (the "Letter of Credit") initially in the amount of $10,833,334 of which $1O,000,000 may be drawn on in respect of principal of the Bonds and $833,334 (representing 200 days of interest at 15% per annum) may be drawn on in respect of interest on the Bonds NOW THEREFORE, in consideration of the premises and in order to induce the Bank to issue the Letter of Credit, the parties hereto hereby agree as follows: SECTION 1 (a) Definitions. The following terms, as used herein, have the following respective meanings: "Adjusted Capitalization" means, at any date, an amount equal to the sum of (i) the Capitalization of the Company at such date, plus (ii) the excess, if any, of (x) the aggregate unpaid principal amount of all short-term indebtedness for borrowed money of the Company at such date over (y) 10% of the Capitalization of the Company as of the date of the most recently prepared financial statements of the Company which have been included in a Form 10-K or 10-Q filed with the Securities and Exchange Commission (or, if the Company is not at the time subject to the reporting requirements of the Securities Exchange Act of 1934, as amended, the most recent annual or quarterly financial statements, as the case may be, delivered pursuant to Section 6(a) hereof). "Agreement" means this Reimbursement and Security Agreement, as the same may from time to time be amended, supplemented or modified. "Beneficiary" means Chemical Bank, as agent for the Trustee. "Business Day" means any day except a Saturday, Sunday or other day on which commercial banks in the City of New York and in the cities in which the principal offices of the Trustee, the Registrar, the Paying Agent, and the Tender Agent (all as defined in the Indenture) are located are required by law, regulation or executive order to close or on which such banks are generally voluntarily closed for business in such locations and on which the New York Stock Exchange is open. "Capitalization of the Company" means at any date, an amount equal to the sum of (i) the total principal amount of all long-term indebtedness for borrowed money, secured or unsecured, of the Company then outstanding (excluding, however, indebtedness (not to exceed $320,000,000, provided, that, if the Company merges or consolidates with WMECO, the exclusion for the surviving entity shall be $400,000,000) existing under any nuclear fuel financing so long as the proceeds of such indebtedness are used solely to finance the purchase and carrying of nuclear fuel and so long as the appropriate regulatory authorities have not taken any action which would not allow the costs with respect to such financing to be recovered through the rate making process), (ii) the aggregate of the par value of, or stated capital represented by, the outstanding shares of all classes of capital stock of the Company and (iii) the surplus of the Company, paid in, earned and other, if any. "Code" means the United States Internal Revenue Code of 1986, as amended. "Common Equity" means an amount equal to the sum of the aggregate of the par value of, or stated capital represented by, the outstanding shares of common stock of the Company, and the surplus of the Company, paid in, earned and other, if any, as of the date of the most recently prepared financial statements of the Company which have been included in a Form 10-K or 10-Q filed with the Securities and Exchange Commission (or, if the Company is not at the time subject to the reporting requirements of the Securities Exchange Act of 1934, as amended, the most recent annual or quarterly financial statements, as the case may be, delivered pursuant to Section 6(a) hereof). "Controlled Group" means all members of a controlled group of corporations and all trades of businesses (whether or not incorporated) under common control, which, together with the Company, are treated as a single employer under Section 414(b) or 414(c) of the Code. "Date of Issuance" means the date on which the Letter of Credit is issued upon request of the Company pursuant to Section 2(a) hereof, which date shall in no event be later than October 31, 1988. "Debt" of any Person means at any date, without duplication, (i) all obligations of such Person for borrowed money, (ii) all obligations of such Person evidenced by bonds, debentures, notes or other similar instruments, (iii) all obligations of such Person to pay the deferred purchase price of property or services, except trade accounts payable arising in the ordinary course of business, (iv) all obligations of such Person as lessee under capital leases, (v) all Debt of others secured by a Lien on any asset of such Person, whether or not such Debt is assumed by such Person, and (vi) all Debt of others Guaranteed by such Person. "Default" means any event or condition which with the giving of notice or the lapse of time or both would, unless cured or waived, become an Event of Default. "Disclosure Document" means the Company's Annual Report on Form 10-K for the fiscal year ended December 31, 1987, the Company's Quarterly Reports on Form 10-Q for the fiscal quarters ended March 31, 1988 and June 30, 1988, and the Company's Current Reports on Form 8-K dated January 26, 1988, March 24, 1988 and June 22, 1988. "Drawing" means any "A Drawing", "B Drawing", "C Drawing" and "D Drawing" as such terms are defined in the Letter of Credit. "ERISA" means the Employee Retirement Income Security Act of 1974, as amended. "Event of Default" means any of the events specified in Section 7 hereof. "Expiration Date" means the date on which the Letter of Credit expires in accordance with its terms. "Guaranty" by any Person means any obligation, contingent or otherwise, of such Person directly or indirectly guaranteeing any Debt of any other Person or in any manner providing for the payment of any Debt of any other Person or otherwise protecting the holder of such Debt against loss (whether by agreement to keep-well, to purchase assets, goods, securities or services, to take-or-pay or otherwise); provided that the term "Guaranty" shall not include endorsements for collection or deposit in the ordinary course of business. The term "Guarantee" used as a verb has a correlative meaning. "HELCO" means the Hartford Electric Light Company, a previously existing Connecticut corporation which merged with and into the Company effective as of the close of business on June 30, 1982. "Lien" means with respect to any asset, (i) any mortgage, lien, pledge, charge, security interest or encumbrance of any kind in respect of such asset or (ii) the interest of a vendor or lessor under any conditional sale agreement, capital lease or other title retention agreement relating to such asset. "Northeast" means Northeast Utilities, a Massachusetts voluntary business association. "PBGC" means the Pension Benefit Guaranty Corporation and any entity succeeding to any or all of its functions under ERISA. "Person" means an Individual, a corporation, a partnership, an association, a trust or any other entity or organization, including a government or political subdivision or an agency or instrumentality thereof. "Plan" means at any time an employee pension benefit plan which is covered by Title IV of ERISA or subject to the minimum funding standards under Section 412 of the Code and is either (i) maintained by the Company or any member of the Controlled Group for employees of the Company or any member of the Controlled Group or (ii) maintained pursuant to a collective bargaining agreement or any other arrangement under which more than one employer makes contributions and to which the Company or any member of the Controlled Group is then making or accruing an obligation to make contributions or has within the preceding five plan years made contributions. "Pledged Bonds" has the meaning set forth in Section 8 hereof. "Related Documents" means the Bonds, the Indenture and the Loan Agreement and any other agreement or instrument relating hereto or thereto. "Reportable Event" shall have the meaning set forth in Section 5(h) hereof. "Significant Subsidiary" means at the time any determination thereof is to be made, a Subsidiary which is a "significant subsidiary" within the meaning of Regulation S-X of the Securities and Exchange Commission. "Stated Amount" has the meaning set forth in the Letter of Credit. "Subsidiary" means as to any Person, any corporation or other entity of which securities or other ownership interests having more than 50% of the ordinary voting power to elect the board of directors or other persons performing similar functions is at the time owned directly or indirectly by such Person; unless otherwise specified, "Subsidiary" shall mean a Subsidiary of the Company. "Tangible Net Worth" means at any date the stockholder's equity of the Company less its Intangible Assets, all determined as of such date. For purposes of this definition "Intangible Assets" means the amount (to the extent reflected in determining such consolidated stockholder's equity) of (i) all write-ups (other than write-ups resulting from foreign currency transactions and write-ups of assets of a going concern business made within twelve months after the acquisition of such business) subsequent to December 31, 1987 in the book value of any asset owned by the Company, (ii) all investments in unconsolidated Subsidiaries and all equity investments in Persons which are not Subsidiaries and (iii) all unamortized debt, discount and expense, unamortized deferred charges, goodwill, patents, trademarks, service marks, trade names, copyrights, franchises, organization or developmental expenses and other intangible items. "Unfunded Vested Liabilities" means with respect to any Plan at any time, the amount (if any) by which (i) the present value of all vested nonforfeitable benefits under such Plan exceeds (ii) the fair market value of all Plan assets allocable to such benefits, all determined as of the then most recent valuation date for such Plan, but only to the extent that such excess represents a potential liability of the Company or any member of the Controlled Group to the PBGC of the Plan under Title IV of ERISA. "Wholly-Owned Subsidiary" means as to any Person, any Subsidiary all of the shares of capital stock or other ownership interests of which (except directors' qualifying shares) are at the time directly or indirectly owned by such Person; unless otherwise specified, "Wholly-Owned Subsidiary" shall mean a Wholly-Owned Subsidiary of the Company. "WMECO" means Western Massachusetts Electric Company, a Massachusetts corporation and its successors. (b) Accounting Terms and Determinations. Unless otherwise specified herein, all accounting terms used herein shall be interpreted, all accounting determinations hereunder shall be made, and all financial statements required to be delivered hereunder shall be prepared, in accordance with generally accepted accounting principles as in effect from time to time, applied on a basis consistent with the most recent audited consolidated financial statements of the Company delivered to the Bank. SECTION 2. Issuance of the Letter of Credit; Conditions Precedent to Issuance. (a) Subject to satisfaction of the conditions precedent set forth in subsections (b) and (c) of this Section 2, the Bank shall issue the Letter of Credit in the Stated Amount, effective on the Date of Issuance and expiring on the Expiration Date. (b) As a condition precedent to the issuance of the Letter of Credit, the Bank shall have received on or before the Date of Issuance the following, each dated such date, in form and substance reasonably satisfactory to the Bank: (i) the facility fee referred to in Section 3(b)(i); (ii) an opinion of Messrs. Day, Berry & Howard, counsel to the Company, in form and substance satisfactory to the Bank; (iii) a copy of the opinion of Messrs. Kutak Rock & Campbell, bond counsel, delivered to the Issuer upon issuance of the Bonds; (iv) copies of all approvals, authorizations or consents of, or notices to or registrations with, any governmental body or agency required for the Company to enter into this Agreement and of all such approvals, authorizations, notices or registrations required to be obtained or made by the Company prior to the Date of Issuance in connection with the transactions contemplated by this Agreement, the Indenture, and any Related Document to which the Company is a party; (v) a certificate of the Company certifying the names and true signatures of the individuals authorized to sign this Agreement and the other documents to be delivered by the Company hereunder; (vi) executed copies (or duplicates thereof) of the other Related Documents, each of which shall be in form and substance reasonably satisfactory to the Bank; (vii) such other documents, instruments, approvals (and, if requested by the Bank, certified duplicates of executed copies thereof) or opinions as the Bank may reasonably request. (c) The following statements shall be true and correct on the Date of Issuance and the Bank shall have received a certificate signed by a senior officer of the Company dated the Date of Issuance, stating that: (i) the representations and warranties of the Company contained in Section 5 hereof or in the Related Documents are correct on and as of the Date of Issuance as though made on and as of such date; (ii) no Default or Event of Default shall have occurred and be continuing or would result from the issuance of the Letter of Credit; and (iii) no Event of Default as defined in tho Loan Agreement or event which, with the giving of notice or lapse of time, or both, could become such an Event of Default, shall have occurred and be continuing. SECTION 3. Reimbursement and Other Payments. (a) The Company agrees to pay to the Bank: (i) no later than the close of business on the day on which any amount is paid pursuant to an A Drawing under the Letter of Credit in respect of principal of the Bonds, a B Drawing in respect of interest on the Bonds or a D Drawing in respect of the portion of the purchase price of Bonds tendered for purchase pursuant to Section 2.4 of the Indenture which represents accrued interest on the Bonds, a sum equal to the amount so drawn; (ii) no later than the earliest of (x) the Expiration Date, (y) the date on which the Pledged Bonds with respect to which such C Drawing was made are remarketed and (z) the date on which the principal of the Bonds becomes due and payable, whether at stated maturity, by acceleration or otherwise, a sum equal to any amount paid pursuant to a C Drawing under the Letter of Credit in respect of the portion of the purchase price for Bonds tendered for purchase pursuant to Section 2.4 of the Indenture which represents principal of the Bonds (and interest on such amount as provided in clause (iii) below); (iii) interest on any amount unpaid by the Company under clause (ii) from the date such amount is drawn under the Letter of Credit until due, payable monthly in arrears, on the last day of each month and when such amount is paid, at a fluctuating interest rate per annum (computed on the basis of a year of 360 days for the actual number of days elapsed) equal to 1% per annum over the Bank's prime rate as announced to be in effect from time to time (the "Prime Rate") which rate shall change as and when said Prime Rate shall change; and (iv) interest on any and all amounts unpaid by the Company when due hereunder from the date such amounts become due until payment in full, payable on demand, at a fluctuating interest rate per annum (on the basis of a 360 day year for the actual number of days elapsed) equal to 2% per annum above the cost to the Bank of overnight funds in the amount or amounts so unpaid (but in no event higher than the maximum rate permitted by applicable law), the determination by the Bank of such cost to be conclusive and binding on the Company, absent manifest error. (b) The Company agrees that it will pay to the Bank (i) a facility fee in the amount of $10,833, payable on the Date of Issuance, (ii) letter of credit fees with respect to the Letter of Credit (computed on the basis of a year of 365, or 366 days, as the case may be, for the actual number of days elapsed), payable semi-annually in arrears on the last day of June and December in each year in an amount equal to 45/100 of 1% per annum of the Stated Amount in effect from time to time (provided that the letter of credit fees for the first six months from the Date of Issuance shall be non- refundable and shall be due and payable in all events and be based on the initial Stated Amount notwithstanding any reduction of the Stated Amount or any cancellation of the Letter of Credit), (iii) utilization fees in the amount of $100 for each Drawing under the Letter of Credit, payable on demand, and (iv) a transfer fee upon each transfer of the Letter of Credit in an amount equal to the Bank's then current letter of credit transfer fee. (c) If after the date hereof, any change in any law or regulation or in the interpretation thereof by any court or administrative or governmental authority charged with the administration thereof or the enactment of any law or regulation shall either (i) impose, modify or deem applicable any reserve, special deposit or similar requirement (excluding capital adequacy requirements), against letters of credit issued by, or assets held by, or deposits in or for the account of, the Bank or (ii) impose on the Bank any other condition regarding this Agreement or the Letter of Credit and the result of any event referred to in clause (i) or (ii) of this subsection shall be to increase the cost to the Bank of issuing or maintaining the Letter of Credit (which increase in cost shall be calculated in accordance with the Bank's reasonable allocation of the aggregate of such cost increases resulting from such events), then, upon written demand by the Bank, the Company shall pay to the Bank an amount equal to such increase in cost. Such amount shall bear interest thereon from the second Business Day after receipt by the Company of such demand until payment in full thereof at the rate provided in clause (iii) of subsection (a) of this Section. A certificate as to the amount of such increase in cost shall be submitted by the Bank to the Company together with the aforesaid demand therefor and shall be conclusive as to the amount thereof, absent manifest error. (d) All payments by the Company to the Bank hereunder shall be made in lawful currency of the United States and in immediately available funds at the Bank's New York office, which at the date hereof is located at 299 Park Avenue, New York, New York 10171. Whenever any payment hereunder shall be due on a day which is not a Business Day, the date for payment thereof shall be extended to the next succeeding Business Day, and any interest thereon shall be payable for such extended time at the specified rate. SECTION 4. Obligations Absolute. Subject to the provisions hereof, the obligations of the Company under Section 3(a) of this Agreement shall be absolute, unconditional and irrevocable, and shall be performed strictly in accordance with the terms of this Agreement, irrespective of any of the following circumstances: (i) any lack of validity or enforceability of the Letter of Credit or any of the Related Documents; (ii) any amendment or waiver of, or consent to departure from, all or any of the Related Documents; (iii) the existence of any claim, setoff, defense or other rights which the Company may have at any time against the Trustee, the Beneficiary or any transferee of the Letter of Credit (or any persons or entities for whom the Trustee, the Beneficiary or any such transferee may be acting), the Bank or any other Person or entity, whether in connection with this Agreement, the Related Documents or any unrelated transactions (provided that nothing herein shall prevent the assertion of such claim by separate suit or by compulsory counterclaim in a suit instituted by the Bank); (iv) any statement or any other document presented under the Letter of Credit proving to be forged, fraudulent, invalid or insufficient in any respect or any statement therein being untrue or inaccurate in any respect whatsoever; (v) payment by the Bank under the Letter of Credit against presentation of a draft or certificate which does not comply with the terms of the Letter of Credit, provided such payment shall not have constituted gross negligence or willful misconduct of the Bank; or (vi) any other circumstance or happening whatsoever, whether or not similar to any of the foregoing, provided that the same shall not have constituted gross negligence or willful misconduct of the Bank. SECTION 5. Representations and Warranties. The Company represents and warrants to the Bank as follows: (a) Organization. The Company is a corporation duly organized, validly existing and in good standing under the laws of the State of Connecticut; each Significant Subsidiary is a corporation duly organized, validly existing and in good standing under the laws of the state of its respective organization; and the Company and each Significant Subsidiary is duly qualified and in good standing as a foreign corporation authorized to do business in each jurisdiction where, because of the nature of its activities or properties, such qualification is required. (b) Authorization; No Conflict. The execution and delivery of, and the performance by the Company of its obligations under, this Agreement and the Related Documents to which it is a party are within the Company's corporate powers, have been duly authorized by all necessary corporate action, have received all necessary governmental or regulatory approval (including, without limitation, approvals of the Securities and Exchange Commission under the Public Utility Holding Company Act of 1935, as amended, and the Connecticut Department of Public Utility Control, which approvals have been duly obtained and are in full force and effect), and do not, subject to the Company's compliance with the requirements of its preferred stock provisions with respect to the incurrence of unsecured indebtedness and subject also to the Company's compliance with or satisfaction of all of its contractual obligations with respect to the incurrence of unsecured indebtedness or with respect to the amount of unsecured indebtedness which may be incurred or remain outstanding, and will not contravene or conflict with any provision of law or of the charter or by-laws of the Company or any Significant Subsidiary or of any agreement binding upon the Company or any Significant Subsidiaries. (c) Validity and Binding Nature. This Agreement and the Loan Agreement are legal, valid and binding obligations of the Company, enforceable against the Company in accordance with their respective terms. (d) Financial Statements. The Company's audited financial statements as at December 31, 1987, and unaudited financial statements as at March 31 and June 30, 1988, copies of which have been furnished to the Bank, have been prepared in conformity with generally accepted accounting principles (except, in the case of unaudited financial statements, for period-end adjustments) applied on a basis consistent with that of the preceding fiscal periods, and accurately present the financial condition of the Company as at such dates and the results of its operations for the periods then ended, and since June 30, 1988 there has been no material adverse change in its financial condition or operations. (e) Litigation and Contingent Liabilities. No litigation (including, without limitation, derivative actions), arbitration proceedings or governmental, judicial, administrative or regulatory proceedings are pending or, to the best of its knowledge, threatened against the Company or any Subsidiary in which the management of the Company believes there is a reasonable possibility of an outcome which could materially and adversely affect the business or operations of the Company and its Subsidiaries, except as set forth in the Schedule of Litigation heretofore delivered by the Company to the Bank or in the Company's Disclosure Documents, copies of which have been heretofore furnished by the Company to the Bank. Other than any liability incident to such litigation or proceedings so set forth, or arising out of the obligations referred to in the Company's Disclosure Documents, neither the Company nor any Subsidiary has any material contingent liabilities not provided for or disclosed in the financial statements (including the notes thereto) referred to in Section 5(d) hereof. (f) Liens. None of the assets of the Company or any Significant Subsidiary of the Company is subject to any Lien, except (i) for current taxes not delinquent or taxes being contested in good faith and by appropriate proceedings, (ii) liens arising in the ordinary course of business for sums not due or sums being contested in good faith and by appropriate proceedings, but not involving any deposits or advances or borrowed money or the deferred purchase price of property or services, (iii) to the extent shown or referred to in the financial statements of the Company referred to in Section 5(d) hereof (including the notes thereto), (iv) the lien of that certain Indenture of Mortgage and Deed of Trust dated as of May 1, 1921, as amended and supplemented, from the Company to Bankers Trust Company, as Trustee (the "Company Indenture"), and Liens permitted by the Company Indenture, (v) the lien of that certain First Mortgage Indenture and Deed of Trust dated as of January 1, 1958, as amended and supplemented, from HELCO to The First National Bank of Boston, as Successor Trustee (the "HELCO Indenture"), and Liens permitted by the HELCO Indenture, (vi) the lien of that certain Open-End Mortgage and Trust Agreement dated as of October 1, 1986, as amended, from the Company to Bank of Boston Connecticut, as trustee, with respect to the Company's interest in the Millstone Unit No. 1 nuclear electric generating facility, (vii) the lien of that certain Loan Agreement dated as of June 1, 1977, between the Company and HELCO and the Connecticut Development Authority, with respect to certain pollution control facilities located at several fossil-fired electric generating plants in Connecticut and (viii) liens pursuant to Connecticut General Statutes Section 22a-452a or any successor provision. (g) Subsidiaries; Ownership. The Company has no Subsidiaries except as disclosed in Exhibit B attached hereto and made a part hereof. All of the outstanding shares of stock of each Significant Subsidiary have been validly issued, are fully paid and nonassessable shares and are owned beneficially and of record, free from any Lien, pledge, charge, security interest or other encumbrance, by the Company or by a Subsidiary. No Subsidiary owns any shares of stock of the Company. (h) Pension Benefit Plans. Each Plan complies in all material respects with all applicable requirements of law and regulations, and (i) the Company has received no notice to the effect that it is not in full compliance with any of the requirements of ERISA, and the regulations promulgated thereunder and, to the best of its knowledge, there exists no event described in Section 4043 of ERISA, excluding subsections 4043(b)(2) and 4043(b)(3) thereof ("Reportable Event"), (ii) neither the Company nor any Significant Subsidiary has withdrawn from any such Plan or initiated steps to do so, and (iii) no steps have been taken to terminate any such Plan. (i) Investment Company Act. The Company is not an "investment company" or a company "controlled" by an "investment company", within the meaning of the Investment Company Act of 1940 as amended. (j) Public Utility Holding Company Act. Northeast, which is the sole holder of common stock of the Company, is a "holding company" within the meaning of the Public Utility Holding Company Act of 1935, as amended. (k) Accuracy of Information. All factual information heretofore or contemporaneously furnished by or on behalf of the Company or any Subsidiary to the Bank for purposes of or in connection with this Agreement or any transaction contemplated hereby is, and all other factual information hereafter furnished by or on behalf of the Company or any Subsidiary to the Bank will be, true and accurate in every material respect on the date as of which such information is dated or certified and not incomplete by omitting to state any material fact necessary to make such information not misleading. (l) Related Documents. The Company makes, to and for the benefit of the Bank, each of the representations and warranties of the Company contained in any of the Related Documents, as fully as if such representations and warranties were set forth at length herein. (m) Common Equity. Common Equity is equal to at least 30% of the Adjusted Capitalization. SECTION 6. Covenants. Until the Expiration Date and performance of all obligations of the Company hereunder, unless the Bank shall otherwise consent in writing, the Company will: (a) Reports Certificates and Other Information. Furnish to the Bank: (i) Within 105 days after each fiscal year of the Company, a copy of an annual report of the Company with respect to such fiscal year to the Securities and Exchange Commission on Form 10-K, containing financial statements with respect to such year prepared in conformity with generally accepted accounting principles applied on a basis consistent (except for such changes with which the Company's independent public accountants concur) with the audited financial statements of the Company as at December 31, 1987, duly certified by independent public accountants of nationally recognized standing selected by the Company, together with a certificate from such accountants to the effect that, in making the examination necessary for the signing of the annual audit report with respect to such financial statements by such accountants, they have not become aware of any Event of Default or Default that has occurred and is continuing, or, if they have become aware of any such event, describing it and the steps, if any, being taken to cure it. (ii) Within 50 days after each quarter (except the last quarter) of each fiscal year of the Company, a copy of a report of the Company with respect to such quarter to the Securities and Exchange Commission on Form 10- Q, containing financial statements with respect to such quarter prepared in the same manner as the audited financial statements referred to in Section 6(a)(i) hereof, signed by a proper accounting officer of the Company. (iii) Contemporaneously with the furnishing of a copy of each annual report and of each quarterly report provided for in this Section 6(a), a certificate dated the date of such annual report or such quarterly report and signed by the President, any Vice President, the Treasurer or any Assistant Treasurer of the Company, to the effect that no Event of Default or Default has occurred and is continuing, or, if there is any such event, describing it and the steps, if any, being taken to cure it. (iv) In addition to the reports referred to in clauses (i) and (ii) of this Section 6(a), (x) copies of each prospectus and Form 8-K filed by the Company or any Significant Subsidiary with the Securities and Exchange Commission, promptly upon the filing thereof, (y) the Company's financial forecasts and projections that are generally distributed to the financial community, if any, promptly upon the distribution thereof, and (z) within the same time frames applicable to financial statements and other data regarding the Company, the corresponding consolidated financial statements and other data for Northeast. (v) Forthwith upon the learning of the occurrence of any of the following (to the extent not otherwise disclosed pursuant to the preceding provisions of this Section 6(a)), written notice thereof, describing the same and the steps being taken with respect thereto: (i) the occurrence of an Event of Default or Default, or (ii) the institution of, or any adverse determination in, any litigation, arbitration proceedings or governmental, judicial, administrative or regulatory proceedings (other than general rate proceedings) which is material to the Company and the Subsidiaries taken on a consolidated basis, or which is material to Northeast and the Subsidiaries of Northeast taken on a consolidated basis, or (iii) the occurrence of a Reportable Event under, or the institution of steps by the Company or any member of the Controlled Group to withdraw from, or the institution of any steps to terminate, any Plan. (vi) From time to time such other information concerning the Company and the Subsidiaries as the Bank may reasonably request. If the Company ever ceases to be subject to the reporting requirements of the Securities Exchange Act of 1934, as amended, the requirements of (i) and (ii) shall be deemed complied with if the Company delivers the financial statements and certificates referred to therein. (b) Books, Records, and Inspections. Maintain, and cause each Significant Subsidiary to maintain, complete and accurate books and records; permit, and cause each Subsidiary to permit, access by the Bank to the books and records of the Company and of any Subsidiary; and permit, and cause each Subsidiary to permit, the Bank to inspect the properties and operations of the Company and of any Subsidiary. (c) Insurance. Maintain, and cause each significant Subsidiary to maintain, such insurance as may be required by law and such other insurance to such extent and against such hazards and liabilities, as is customarily maintained by companies similarly situated. (d) Taxes and Other Similar Charges. Pay, and cause each Significant Subsidiary the same shall become in default, all taxes, assessments and other similar charges except as contested in good faith and by appropriate proceedings. (e) Mergers, Consolidations, Sales. Not, and not permit any Significant Subsidiary to, be a party to any merger or consolidation, or, except in the ordinary course of its business, sell, transfer, convey or lease all or any substantial part of its assets, or sell or assign with or without recourse any receivables, except, after receipt of all necessary corporate and governmental or regulatory approvals, for (i) any such merger or consolidation, sale, transfer, conveyance, lease or assignment of or by any Wholly-Owned Subsidiary into, with or to the Company or into, with or to any other Wholly-Owned Subsidiary and any such purchase or other acquisition by the Company or any Wholly-Owned Subsidiary of the assets or stock of any Wholly-Owned Subsidiary, (ii) any such sale of assets (other than stock) which comprise all or any part of its interest in a nuclear power generating plant (whether completed or under construction), or which comprise the gas business and gas properties of the Company and (iii) any such merger or consolidation of the Company or any Significant Subsidiary into, with or to Northeast and/or a Wholly-Owned Subsidiary of Northeast if, but only if, (w) in the case of a merger or consolidation of any Significant Subsidiary, Tangible Net Worth immediately following, and giving effect to, such merger or consolidation shall equal or exceed Tangible Net Worth immediately prior thereto, (x) before and after giving effect to any such merger or consolidation, no Event of Default or Default shall have occurred and be continuing, (y) in the case of a merger or consolidation of the Company, the successor or surviving corporation, if not the Company, shall have assumed or succeeded to all of the liabilities of the Company (including the liabilities of the Company under this Agreement) and (z) the Bank shall have received the favorable written opinion of Day, Berry & Howard, or other counsel to the Company satisfactory to the Bank, to the effect of clause (y) of this Section 6(e)(iii). Notwithstanding the foregoing, the Company may sell or assign, with or without recourse, receivables (not constituting all or any substantial part of its assets), provided, that, in the reasonable opinion of the Bank, such sale or assignment of receivables will not materially adversely affect the financial condition of the Company or its ability to perform its obligations hereunder or under the Related Documents to which it is a party. (f) Maintenance of Properties. Cause all material properties used or useful in the conduct of the business of the Company or any Significant Subsidiary to be maintained and kept in reasonable condition, repair and working order, and cause to be made all necessary repairs, renewals, replacements, betterments and improvements thereof, all as in the judgment of the Company or such Significant Subsidiary may be necessary so that the business carried on in connection therewith may be properly and advantageously conducted at all times; provided, however, that the Company or such Significant Subsidiary shall not be prevented from discontinuing the operation and maintenance of any such properties if such discontinuance is, in the judgment of the Company or such Significant Subsidiary, desirable in the operation or maintenance of its business and not disadvantageous in any material respect to the Bank. (g) Conduct of Business. Carry out and conduct, and cause each Significant Subsidiary to carry out and conduct, its primary business in substantially the same manner and in substantially the same fields as such business is now carried on and conducted, and do or cause to be done all lawful things necessary to preserve and keep in full force and effect the corporate existence and the rights (charter and statutory) and franchises of the Company and of each Significant Subsidiary, except as otherwise provided in Section 6(e) hereof; PROVIDED, HOWEVER, that neither the Company nor any Significant Subsidiary shall be required to preserve any such right or franchise if it shall determine that the preservation thereof is no longer necessary, desirable or permissible in the operation of its business and that the loss thereof is not disadvantageous in any material respect to the Bank. (h) Compliance with Law. Comply, and cause each Significant Subsidiary to comply, in all material respects with all laws, rules, regulations and governmental orders (Federal, state and local) having applicability to it or to the business or businesses at any time conducted by the Company or such Significant Subsidiary, as the case may be, except to the extent that the failure to comply with any provision of the foregoing would not have a material adverse effect on the present or future financial condition or operations of the Company or such Significant Subsidiary, and would not impair the Company's ability to perform its obligations under this Agreement. (i) Negative Pledge. Not create, assume or permit to exist, nor permit any Significant Subsidiary to create, assume or permit to exist, any Liens on any assets now owned or hereafter acquired other than: (i) Liens created by the Company Indenture or the HELCO Indenture; (ii) Liens on the Company's interest in the Millstone Unit No. 1, Millstone Unit No. 2 or Millstone Unit No. 3 nuclear electric generating facilities or nuclear fuel for any or all nuclear units in which the Company has an interest (including, without limitation, Millstone Unit No. 1, Millstone Unit No. 2 and Millstone Unit No. 3); (iii) Liens permitted by the Company Indenture or the HELCO Indenture; (iv) any Lien created or assumed to secure debt owing by any Subsidiary to the Company or to any Wholly-Owned Subsidiary; (v) any purchase money security interest or construction mortgage on assets hereafter acquired or constructed by the Company or any Significant Subsidiary and any Lien on any assets existing at the time of acquisition thereof by the Company or any Significant Subsidiary, or created within 180 days from the date of completion of the acquisition or construction; PROVIDED that such Lien shall at all times be confined solely to the assets so acquired or constructed and any additions thereto; (vi) any existing Liens on assets now owned by the Company or any Significant Subsidiary, Liens on assets of any Significant Subsidiary existing at the time it becomes a Subsidiary and Liens existing on assets of a corporation or other going concern business when it is merged into or with the Company or a Significant Subsidiary or when substantially all of its assets are acquired by the Company or a Significant Subsidiary; PROVIDED that such Liens shall at all times be confined solely to such assets, or if such assets constitute a utility system, additions to or substitutions for such assets; (vii) Liens resulting from legal proceedings being contested in good faith and for which reserves which in the judgment of the Company are adequate have been established by the Company or the applicable Significant Subsidiary; (viii) Liens created in favor of the other contracting party in connection with advance or progress payments; (ix) any Liens in favor of any state of the United States or any political subdivision of any such state, or any agency of any such state or political subdivision, or trustee acting on behalf of holders of obligations issued by any of the foregoing or any financial institution lending to or purchasing obligations of any of the foregoing, which security is created or assumed for the purpose of financing all or part of the cost of acquiring or constructing the property subject thereto; (x) Liens resulting from conditional sale agreements, capital leases or other title retention agreements; (xi) Liens on property of the Company or any Significant Subsidiary related to the financing of pollution control facilities; (xii) any other Liens incurred in the ordinary course of business otherwise than to secure borrowings; (xiii) Liens under Connecticut General Statutes Section 22a-452a or any successor provision; (xiv) any extension, renewal or replacement of Liens permitted by clauses (i) to (v), (viii) to (xi) and (xiii); PROVIDED, HOWEVER, that the principal amount of debt secured thereby shall not, at the time of such extension, renewal or replacement, exceed the principal amount of indebtedness so secured and that such extension, renewal or replacement shall be limited to all or a part of the property which secured the Lien so extended, renewed or replaced; and (xv) Liens (in addition to those permitted pursuant to clauses (i) through (xiv) above) securing Debt in an aggregate principal amount not exceeding $200,000,000; provided, that, no such Lien shall be permitted on any receivable of the Company or any Significant Subsidiary unless in the reasonable opinion of the Bank the existence of such Lien will not materially adversely affect the financial condition of the Company or its ability to perform its obligations hereunder or under the Related Documents. (j) Pension Benefit Plans. Maintain, and cause each Significant Subsidiary to maintain, each Plan in compliance with all applicable requirements of law and regulations. (k) Related Documents. Not agree to any amendment or supplement to any Related Document without the prior written consent of the Bank. (l) Use of Proceeds. Use the proceeds of the Bonds to pay the costs of the Product as provided in the Loan Agreement. SECTION 7. Events of Default. (A) The following events shall be Events of Default hereunder unless waived by the Bank pursuant to Section 9 hereof: (a) the Company shall fail to pay when due any amount payable under Section 3 hereof, and such failure shall continue unremedied for five Business Days; (b) the Company shall fail to observe or perform any other covenant, restriction or agreement contained in this Agreement for 30 days after the Company becomes aware of such failure; (c) any representation, warranty, certification or statement made by the Company in this Agreement or any Related Document to which it is a party or in any certificate, financial statement or other document delivered pur- suant to this Agreement or any Related Document to which it is a party shall prove to have been incorrect in any material respect when made; (d) an event of default as defined in any mortgage, indenture, agreement or instrument under which there may be issued, or by which there may be secured or evidenced, any indebtedness of the Company or any Significant Subsidiary of $5,000,000 or more, whether such indebtedness now exists or shall hereafter be created, shall occur and shall continue beyond any grace or cure period applicable thereto and shall consist of default in payment of such indebtedness at maturity or shall result in such indebtedness becoming or being declared due and payable, or permitting the respective obligee to declare such indebtedness due and payable, prior to the date on which it would otherwise become due and payable; (e) an event of default as defined in the Indenture or the Loan Agreement shall occur and be continuing; (f) a final judgment or order for the payment of money in excess of $5,000,000 shall be rendered against the Company or any Significant Subsidiary and such final judgment or order shall continue unsatisfied and unstayed for a period of 30 days; (g) the Company or any member of the Controlled Group shall fail to pay when due an amount or amounts aggregating in excess of $1,000,000 which it shall have become liable to pay to the PBGC or to a Plan under Title IV of ERISA; or notice of intent to terminate a Plan or Plans having aggregate Unfunded Vested Liabilities in excess of $5,000,000 shall be filed under Title IV of ERISA by the Company, any member of the Controlled Group, any plan administrator or any combination of the foregoing; or the PBGC shall institute proceedings under Title IV of ERISA to terminate or to cause a trustee to be appointed to administer any such Plan or Plans or a condition shall exist by reason of which the PBGC would be entitled to obtain a decree adjudicating that any such Plan or Plans must be terminated and, at the time said proceeding is instituted or such condition exists, as the case may be, the liability of the Company or any member of the Controlled Group to the PBGC or such Plan or Plans under Title IV of ERISA may reasonably be expected to be in excess of $5,000,000; or a proceeding shall be instituted by a fiduciary of any such Plan or Plans to enforce Section 515 of ERISA and, at the time such proceeding is instituted, the liability of the Company or any member of the Controlled Group to such Plan or Plans is in excess of $1,000,000; or (h) the Company or any Significant Subsidiary shall commence a voluntary case or other proceeding seeking liquidation, reorganization or other relief with respect to itself or its debts under any bankruptcy, insolvency or other similar law now or hereafter in effect or seeking the appointment of a trustee, receiver, liquidator, custodian or other similar official of it or any substantial part of its property, or shall consent to any such relief or to the appointment of or taking possession by any such official in an involuntary case or other proceeding commenced against it, or shall make a general assignment for the benefit of creditors, or shall fail generally to pay its debts as they become due, or shall take any action to authorize any of the foregoing; or (i) an involuntary case or other proceeding shall be commenced against the Company or any Significant Subsidiary seeking liquidation, reorganization or other relief with respect to it or its debts under any bankruptcy, insolvency or other similar law now or hereafter in effect or seeking the appointment of a trustee, receiver, liquidator, custodian or other similar official of it or any substantial part of its property, and such involuntary case or other proceeding shall remain undismissed and unstayed for a period of 60 days; or an order for relief shall be entered against the Company or any Significant Subsidiary under the federal bankruptcy laws as now or hereafter in effect. (B) If an Event of Default occurs and is continuing hereunder, the Bank may in its sole discretion notify the Company and the Trustee of such occurrence. Upon receipt by the Trustee of such notice from the Bank, the Trustee shall immediately declare the principal of all Bonds then outstanding and the interest accrued thereon immediately due and payable. SECTION 8. Pledge. The Company hereby pledges, assigns, hypothecates, transfers, and delivers to the Bank all its right, title and interest to, and hereby grants to the Bank a first lien on, and security interest in, all right, title and interest of the Company in and to the following (the "Collateral"): (a) all Bonds which may from time to time be purchased with proceeds of C Drawings and/or D Drawings under the Letter of Credit (the "Pledged Bonds"); (b) all income, earnings, profits, interest, premium or other payments in whatever form in respect of the Pledged Bonds; (c) all proceeds (cash and non-cash) arising out of the sale, exchange, collection, enforcement or other disposition of all or any portion of the Pledged Bonds; as collateral security for the prompt and complete payment when due of all amounts due in respect of the reimbursement obligations of the Company set forth in clauses (ii) and (iii) of Section 3(a) with respect to such Pledged Bonds (the "Obligations"). In the event that the Company shall fail to pay any amount when due under clauses (ii) or (iii) of Section 3(a) with respect to the Pledged Bonds, the Bank, without demand of performance or other demand, advertisement or notice of any kind (except the notice specified below of time and place of public or private sale) to or upon the Company or any other person (all and each of which demands, advertisements and/or notices are hereby expressly waived), may forthwith collect, receive, appropriate and realize upon the Collateral, or any part thereof, and/or may forthwith sell, assign, give option or options to purchase, contract to sell or otherwise dispose of and deliver said Collateral, or any part thereof, in one or more parcels at public or private sale or sales, at any exchange, broker's board or at any of the Bank's offices or elsewhere upon such terms and conditions as it may deem advisable and at such prices as it may deem best, for cash or on credit or for future delivery without assumption of any credit risk, with the right to the Bank upon any such sale or sales, public or private, to purchase the whole or any part of said Collateral so sold, free of any right or equity of redemption in the Company, which right or equity is hereby expressly waived or released. The Bank shall apply the net proceeds of any such collection, recovery, receipt, appropriation, realization or sale, after deducting all reasonable costs and expenses of every kind incurred therein or incidental to the care, safekeeping or otherwise of any and all of the Collateral or in any way relating to the rights of the Bank hereunder, including reasonable attorney's fees and legal expenses, to the payment in whole or in part of the Obligations in such order as the Bank may elect, the Company remaining liable for any deficiency remaining unpaid after such application, and only after so applying such net proceeds and after the payment by the Bank of any other amount required by any provision of law, including, without limitation, Section 9-504(1)(c) of the Uniform Commercial Code, need the Bank account for the surplus, if any, to the Company. The Company agrees that the Bank need not give more than ten days' notice of the time and place of any public sale or of the time after which a private sale or other intended disposition is to take place and that such notice is reasonable notification of such matters. No notification need be given to the Company if it has signed after default a statement renouncing or modifying any right to notification of sale or other intended disposition. In addition to the rights and remedies granted to it in this Agreement and in any other instrument or agreement securing, evidencing or relating to any of the Obligations, the Bank shall have all the rights and remedies of a secured party under the Uniform Commercial Code of the State of New York. The Company covenants that the pledge, assignment and delivery of the Collateral hereunder will create a valid, perfected, first priority security interest in all right, title or interest of the Company in or to such Col- lateral, and the proceeds thereof, subject to no prior pledge, lien, mortgage, hypothecation, security interest, charge, option or encumbrance or to any agreement purporting to grant to any third party a security interest in the property or assets of the Company which would include the Collateral. The Company covenants and agrees that it will defend the Bank's right, title and security interest in and to the Collateral and the proceeds thereof against the claims and demands of all persons whomsoever. Provided the Company shall have paid all amounts then due under clause (i) of Section 3(a) and shall have paid all interest which may be owing under clause (iii) of Section 3(a), the Bank will promptly pay over to the Company any interest it may receive from the Trustee on any Pledged Bonds. Pledged Bonds shall be released from the security interest created hereunder upon satisfaction of the Obligations with respect to such Pledged Bonds. SECTION 9. Amendments and Waivers. No amendment or waiver of any provision of this Agreement nor consent to any departure by the Company or the Bank therefrom shall in any event be effective unless the same shall be in writing and signed by the Company and the Bank. Any such waiver or consent shall be effective only in the specific instance and for the specific purpose for which given. SECTION 10. Notices. All notices, requests and other communications to either party hereunder shall be in writing (including bank wire, telex or similar writing) and shall be given to such party, addressed to it, at its address or telex number set forth below or such other address or telex number as such party may hereafter specify for the purpose by notice to the other party. Each such notice, request or communication shall be effective (i) if given by telex, when such telex is transmitted to the telex number specified below and the appropriate answerback is received, (ii) if given by mail 5 days after such communication is deposited in the mails with first class postage prepaid, addressed as aforesaid or (iii) if given by any other means, when delivered at the address specified below: Party Address The Connecticut Light 107 Selden Street and Power Company Berlin, Connecticut 06037 (if delivered) or P.O. Box 270 Hartford, Connecticut 06141 (if mailed) Telex: 99370 Attn: Assistant Treasurer-Long Term Financing Union Bank of Switzerland, New York 299 Park Avenue Branch New York, New York 10171 Telex: UB 129 299 NYK Attn: Christopher W. Criswell or to such other address as either party may specify in a notice to the other. SECTION 11. No Waiver; Remedies. No failure on the part of the Bank to exercise, and no delay in exercising, any right hereunder shall operate as a waiver thereof nor shall any single or partial exercise of any right hereunder preclude any other or further exercise thereof or the exercise of any other right. The remedies herein provided are cumulative and not exclusive of any remedies provided by law. SECTION 12. Indemnification. The Company hereby indemnifies and holds harmless the Bank from and against any and all claims, damages, losses, liabilities, costs or expenses whatsoever which the Bank may incur (or which may be claimed against the Bank by any person or entity whatsoever) by reason of or in connection with the execution and delivery or transfer of, or payment or failure to pay under, the Letter of Credit as provided herein; provided that the Company shall not be required to indemnify the Bank for any claims, damages, losses, liabilities, costs or expenses to the extent, but only to the extent, caused by the willful misconduct or gross negligence of the Bank. Nothing in this Section 12 is intended to limit the Company's reimbursement obligation contained in Section 3(a) hereof. SECTION 13. Continuing Obligations. The obligations of the Company under this Agreement shall continue until the later of (i) the Expiration Date or (ii) the date upon which all amounts due and owing to the Bank hereunder shall have been paid in full. This Agreement shall (a) be binding upon the parties hereto and their respective successors and assignor and (b) inure to the benefit of and be enforceable by the parties hereto and their respective successors, transferees and assigns; PROVIDED, HOWEVER, that (i) the Company may not, except in connection with a merger, consolidation or sale of all or a substantial part of its assets permitted by Section 6(e), assign all or any part of this Agreement without the prior written consent of the Bank and (ii) the obligations of the Company pursuant to Sections 3 and 12 hereof shall survive the termination of this Agreement. SECTION 14. Liability of the Bank. The Company assumes all risks of the acts or omissions of the Trustee, the Beneficiary or any transferee of the Letter of Credit with respect to its use of the Letter of Credit. Neither the Bank nor any of its officers or directors shall be liable or responsible for: (a) the use which may be made of the Letter of Credit or for any acts or omissions of the Trustee, the Beneficiary or any transferee in connection therewith; or (b) the validity, sufficiency or genuineness of documents, or of any endorsement(s) thereon, even if such documents should in fact prove to be in any respect invalid, insufficient, fraudulent or forged. In furtherance and not in limitation of the foregoing, the Bank may accept, in the absence of gross negligence or willful misconduct, documents that appear on their face to be in order, without responsibility for further investigation, regardless of any notice or information to the contrary. SECTION 15. Costs, Expenses and Taxes. The Company agrees to pay on demand all reasonable costs and expenses in connection with the preparation, execution, delivery, filing and administration of this Agreement and any other documents delivered in connection with or related to this Agreement, including the reasonable fees and expenses of counsel for the Bank with respect thereto and with respect to advising the Bank as to its rights and responsibilities under this Agreement or any waiver or amendment of this Agreement. In addition, the Company shall pay any and all stamp and other taxes and fees payable or determined to be payable (and notified by the Bank to be payable) in connection with the execution, delivery, filing and recording of this Agreement and such other documents and agrees to save the Bank harmless from and against any and all liabilities with respect to or resulting from any delay in paying or omission to pay such taxes and fees. SECTION 16. Waiver of Right of Set-off; Limitation on Collateral. (a) The Bank hereby irrevocably waives any banker's lien or right of set-off that it may have at law or otherwise in order to appropriate and apply to the payment of any and all of the obligations of the Company now or hereafter existing in respect of the reimbursement obligation of the Company set forth in Section 3(a) of this Agreement, any balances, credits, deposits, accounts or moneys of the Company at any time with the Bank when and if there shall be a drawing under the Letter of Credit (or as a result thereof) during the pendency of any proceeding by or against the Company seeking relief in respect of the Company under Title 11 of the United States Code, as now constituted or hereafter amended; PROVIDED, HOWEVER, that such waiver shall not be operative if (i) it has been determined by the court in such proceeding that the exercise of the Bank's right of set-off or banker's lien will not lead to the Bank's being released, prevented, enjoined or restrained, permanently, preliminarily or temporarily, from fulfilling its obligations under the Letter of Credit and (ii) the exercise of such banker's lien or right of set-off would not constitute any payment (including pursuant to the Letter of Credit) to the Trustee a voidable preference payment under Federal bankruptcy law then in effect. (b) The Bank agrees that, except as to its security interest in Pledged Bonds, it will not at any time accept any collateral as security for the payment of the reimbursement obligation of the Company set forth in Section 3(a) of this Agreement unless provision is made prior to or simultaneously with the taking of such collateral security by the Bank for an equal and ratable security interest in such collateral security to be granted to the Trustee for the benefit of the holders from time to time of the Bonds. (c) The Bank agrees that any payments under the Letter of Credit will be made with the Bank's own funds and not with funds of the Issuer or the Company. SECTION 17. Severability. Any provision of this Agreement which is prohibited, unenforceable or not authorized in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such prohibition, unenforceability or non-authorization without invalidating the remaining provisions hereof or affecting the validity, enforceability or legality of such provision in any other jurisdiction. SECTION 18. Governing Law. This Agreement shall be governed by, and construed and interpreted in accordance with, the laws of the State of New York. SECTION 19. Headings. Section headings in this Agreement are included herein for convenience of reference only and shall not constitute a part of this Agreement for any other purpose. IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be duly executed and delivered by their respective officers thereunto duly authorized as of the date first above written. THE CONNECTICUT LIGHT AND POWER COMPANY By: /s/ Robert C. Aronson UNION BANK OF SWITZERLAND, NEW YORK BRANCH By: /s/Charles E. Arnold By:/s/ Susan E. Zeig SUBSIDIARIES -- EXHIBIT B Percentage of Voting Shares Owned by the Company Research Park, Inc. 100% The City and Suburban Electric and Gas Company 100%* Electric Power, Incorporated 100%* The Connecticut Transmission Corporation 100%* The Nutmeg Power Company 100%* The Mohawk Gas Company 100%* The Connecticut Steam Company 100%* *Inactive EX-4.3 4 CL&P 1992 SERIES A PCB'S LOC EXHIBIT 4.2.19.1 [EXECUTION COPY] LETTER OF CREDIT AND REIMBURSEMENT AGREEMENT Dated as of December 1, 1992 Among THE CONNECTICUT LIGHT AND POWER COMPANY as Account Party CANADIAN IMPERIAL BANK OF COMMERCE, NEW YORK AGENCY as Issuing Bank and as Agent and THE PARTICIPATING BANKS REFERRED TO HEREIN Relating to Business Finance Authority of the State of New Hampshire Pollution Control Refunding Revenue Bonds (The Connecticut Light and Power Company Project - 1992 Series A) LETTER OF CREDIT AND REIMBURSEMENT AGREEMENT Dated as of December 1, 1992 THIS LETTER OF CREDIT AND REIMBURSEMENT AGREEMENT (this "Agreement") is made by and among: (i) The Connecticut Light and Power Company, a corporation duly organized and validly existing under the laws of the State of Connecticut (the "Account Party"); (ii) Canadian Imperial Bank of Commerce, New York Agency ("CIBC"), as issuer of the Letter of Credit (the "Issuing Bank"); (iii) The Participating Banks (as hereinafter defined) from time to time party hereto; and (iv) CIBC as agent (together with any successor agent hereunder, the "Agent") for such Participating Banks and the Issuing Bank. PRELIMINARY STATEMENT The Business Finance Authority of the State of New Hampshire (the "Issuer") proposes to issue, pursuant to a Loan and Trust Agreement, dated as of December 1, 1992 (as supplemented or amended from time to time with the written consent of the Issuing Bank, the "Indenture"), by and among the Issuer, the Account Party and BayBank, as trustee (such entity, or its successor as trustee, being the "Trustee"), $21,000,000 aggregate principal amount of Business Finance Authority of the State of New Hampshire Pollution Control Refunding Revenue Bonds (The Connecticut Light and Power Company Project - 1992 Series A) (the "Bonds") and, pursuant to the Indenture, the Account Party has requested the Issuing Bank to issue its irrevocable letter of credit in favor of the Paying Agent (as defined below), in substantially the form of Exhibit 1.01A hereto (such letter of credit, as it may from time to time be extended or modified pursuant to the terms of this Agreement, being the "Letter of Credit"), in the amount of $21,311,000 (the "Stated Amount"), of which (i) $21,000,000 shall support the payment of principal of the Bonds (or the portion of the purchase or redemption price of the Bonds corresponding to principal), (ii) $311,000 shall support the payment of up to 45 days' interest on the principal amount of the Bonds (or the portion of the purchase or redemption price of the Bonds corresponding to interest), computed at a maximum interest rate of 12% per annum on the basis of the actual days elapsed and a year of 365 or 366 days (as applicable) and (iii) $0.00 shall support the payment of premium on the Bonds. The Issuing Bank has agreed to issue the Letter of Credit subject to the terms and conditions set forth herein (including the terms and conditions relating to the rights and obligations of the Participating Banks). NOW, THEREFORE, in consideration of the premises and in order to induce the Issuing Bank to issue the Letter of Credit and the Participating Banks to participate in the Letter of Credit and make advances hereunder, the parties hereto agree as follows: ARTICLE I DEFINITIONS AND ACCOUNTING TERMS SECTION 1.01 Certain Defined Terms. In addition to the terms defined in the Preliminary Statement hereto, as used in this Agreement, the following terms shall have the following meanings (such meanings to be applicable to the singular and plural forms of the terms defined): "Advances" means Initial Advances and Term Advances, without differentiation; individually, an "Advance". "Affiliate" means, with respect to any Person, any other Person directly or indirectly controlling (including, but not limited to all directors and officers of such Person), controlled by, or under direct or indirect common control with such Person. A Person shall be deemed to control another entity if such Person possesses, directly or indirectly, the power to direct or cause the direction of the management and policies of such entity, whether through the ownership of voting securities, by contract or otherwise. "Alternate Base Rate" means, for any Interest Period or any other period, a fluctuating interest rate per annum equal at all times to the highest from time to time of: (a) the rate of interest announced publicly by CIBC in New York, New York, from time to time, as CIBC's prime rate; and (b) 1/2 of one percent per annum above the Federal Funds Rate from time to time. Each change in the Alternate Base Rate shall take effect concurrently with any change in such prime rate or Federal Funds Rate, as the case may be. "Applicable Lending Office" means, with respect to each Participating Bank, (i)(A)such Participating Bank's "Domestic Lending Office" in the case of a Base Rate Advance, (B)such Participating Bank's "CD Lending Office" in the case of a CD Rate Advance and (C)such Participating Bank's "Eurodollar Lending Office" in the case of a Eurodollar Rate Advance, in each case as specified opposite such Participating Bank's name on Schedule I hereto (in the case of a Participating Bank initially party to this Agreement) or in the Participation Assignment pursuant to which such Participating Bank became a Participating Bank (in the case of any other Participating Bank), or (ii) such other office or affiliate of such Participating Bank as such Participating Bank may from time to time specify to the Account Party and the Agent. "Assessment Rate" means, for any Interest Period or any other period, the annual assessment rate per annum estimated by the Agent on the first day of such Interest Period or such other period, as the case may be, for determining the then average current annual assessment payable by insured banks to the Federal Deposit Insurance Corporation (or any successor) for insuring U.S. dollar deposits in the United States. The "Assessment Rate" shall be adjusted automatically on and as of the effective date of each change in any such rate. "Available Amount" in effect at any time means the maximum aggregate amount available to be drawn at such time under the Letter of Credit, the determination of such maximum amount to assume compliance with all conditions for drawing and no reduction for (i) any amount drawn by the Paying Agent to make a regularly scheduled payment of interest on the Bonds (unless such amount will not be reinstated under the Letter of Credit) or (ii) any amount not available to be drawn because Bonds are held by or for the account of the Account Party and/or in pledge for the benefit of the Issuing Bank. "Base Rate Advance" means an Advance in respect of which the Account Party has selected in accordance with Article III hereof, or this Agreement otherwise provides for, interest to be computed on the basis of the Alternate Base Rate. "Bonds" has the meaning assigned to that term in the Preliminary Statement. "Business Day" means a day of the year that is not a Sunday or legal holiday or a day on which banks are authorized to close in New York City and, (i) if the applicable Business Day relates to any Eurodollar Rate Advance, is a day on which dealings are carried on in the London interbank market and/or (ii) if the applicable Business Day relates to any action to be taken by, or notice furnished to or by, or payment to be made to or by, the Trustee, the Paying Agent or the Remarketing Agent, is a day on which (A) banking institutions are not authorized pursuant to law to close, (B) banking institutions in all of the cities in which the principal offices of the Issuing Bank, the Trustee, the Paying Agent and, if applicable, the Remarketing Agent are located are not required or authorized to remain closed and (C) the New York Stock Exchange is not closed. "CD Rate" means for any Interest Period for any CD Rate Advances comprising part of the same Term Borrowing, an interest rate per annum equal at all times during such Interest Period to the sum of: (i) the rate per annum obtained by dividing (x) the consensus bid rate determined by the Agent to be the average (rounded upward to the nearest whole multiple of 1/100 of 1% per annum, if such average is not such a multiple) of the bid rates per annum, at 9:00 A.M. (New York City time) (or as soon thereafter as practicable) on the first day of such Interest Period, of three New York certificate of deposit dealers of recognized standing selected by the Agent for the purchase at face value of certificates of deposit of CIBC in an aggregate amount substantially equal to the CD Rate Advance of CIBC comprising part of the same Term Borrowing and with a maturity equal to such Interest Period, by (y) a percentage equal to 100% minus the Domestic Reserve Percentage for such Interest Period, plus (ii) 0.875% per annum; plus (iii) the Assessment Rate for such Interest Period. "CD Rate Advance" means an Advance in respect of which the Account Party has selected in accordance with Article III hereof, and this Agreement provides for, interest to be computed on the basis of the CD Rate. "CL&P Indenture" has the meaning assigned to that term in Section 7.02(a)(i)(A) hereof. "Closing Date" means the Business Day upon which each of the conditions precedent enumerated in Sections 5.01 and 5.02 hereof shall be fulfilled to the satisfaction of the Agent, the Issuing Bank, the Participating Banks and the Account Party. All transactions contemplated to occur on the Closing Date shall occur contemporaneously on or prior to December 17, 1992, at the offices of King & Spalding, 120 West 45th Street, New York, New York 10036, at 10:00 A.M. (New York City time), or at such other place and time as the parties hereto may mutually agree. "Collateral" means all of the collateral in which liens, mortgages or security interests are purported to be granted by any or all of the Security Documents. "Commitment" means, for each Participating Bank, such Participating Bank's Percentage of the Available Amount. "Commitments" shall refer to the aggregate of the Commitments. "Confidential Information" has the meaning assigned to that term in Section 10.09 hereof. "Consolidated Capitalization" means, for any period, the aggregate of all amounts that would, in accordance with generally accepted accounting principles and consistent with those applied in the preparation of the Account Party's consolidated financial statements included in its Annual Report on Form 10-K for the year ended December 31, 1991, appear on the Account Party's consolidated balance sheet as the sum of (i) the total principal amount of all long-term Debt of the Account Party and its Subsidiaries (excluding, however, Debt not to exceed $400,000,000 existing under any nuclear fuel financing so long as the proceeds of such Debt are used solely to finance the purchase and carrying of nuclear fuel and so long as the appropriate regulatory authorities have not taken any action which would not allow the costs with respect to such financing to be recovered through the rate making process), (ii) the aggregate of the par value of, or stated capital represented by, the outstanding shares of all classes of common and preferred shares of the Account Party and its Subsidiaries, (iii) the consolidated surplus of the Account Party and its Subsidiaries, paid-in, earned and other, if any, and (iv) the excess, if any, of (A) the aggregate unpaid principal amount of all short-term Debt of the Account Party and its Subsidiaries over (B) 10% of the sum of clauses (i), (ii) and (iii) above. "Consolidated Common Equity" means, for any period, an amount equal to the sum of the aggregate of the par value of, or stated capital represented by, the outstanding common shares of the Account Party and its Subsidiaries and the surplus, paid-in, earned and other, if any, of the Account Party and its Subsidiaries as determined on a consolidated basis in accordance with generally accepted accounting principles. "Conversion", "Convert" or "Converted" each refers to a conversion of Term Advances pursuant to Section 3.04 hereof, including, but not limited to any selection of a longer or shorter Interest Period to be applicable to such Term Advances or any conversion of a Term Advance as described in Section 3.04(c) hereof. "Credit Termination Date" means the date on which the Letter of Credit shall terminate in accordance with its terms. "Debt" means, for any Person, without duplication, (i) indebtedness of such Person for borrowed money, including but not limited to obligations of such Person evidenced by bonds, debentures, notes or other similar instruments, (ii) obligations of such Person to pay the deferred purchase price of property or services (excluding any obligation of such Person to the United States Department of Energy or its successor with respect to disposition of spent nuclear fuel burned prior to April 3, 1983), (iii) obligations of such Person as lessee under leases which shall have been or should be, in accordance with generally accepted accounting principles, recorded as capital leases, (iv) obligations under direct or indirect guaranties in respect of, and obligations (contingent or otherwise) to purchase or otherwise acquire, or otherwise to assure a creditor against loss in respect of, indebtedness or obligations of others of the kinds referred to in clauses (i) through (iii), above, and (v) liabilities in respect of unfunded vested benefits under ERISA Plans. "Default Rate" means a fluctuating interest rate equal at all times to 2% per annum above the Alternate Base Rate in effect from time to time. "Domestic Reserve Percentage" means, for any Interest Period or any other period, the reserve percentage applicable on the first day of such Interest Period or such other period, as the case may be, under regulations issued from time to time by the Board of Governors of the Federal Reserve System (or any successor) for determining the maximum reserve requirement (including, but not limited to, any emergency, supplemental or other marginal reserve requirement) for CIBC with respect to liabilities consisting of or including (among other liabilities) U.S. dollar nonpersonal time deposits in the United States and with a maturity equal to such Interest Period or such other period, as the case may be. The Domestic Reserve Percentage shall be determined from time to time by the Agent and shall be adjusted automatically on and as of the effective date of each change in any reserve requirement. "ERISA" means the Employee Retirement Income Security Act of 1974, as amended from time to time. "ERISA Affiliate" means, with respect to any Person, any trade or business (whether or not incorporated) which is a "commonly controlled entity" of the Account Party within the meaning of the regulations under Section 414 of the Internal Revenue Code of 1986, as amended from time to time. "ERISA Multiemployer Plan" means a "multiemployer plan" subject to Title IV of ERISA. "ERISA Plan" means an employee benefit plan (other than an ERISA Multiemployer Plan) maintained for employees of the Account Party or any ERISA Affiliate and covered by Title IV of ERISA. "ERISA Plan Termination Event" means (i) a Reportable Event described in Section 4043 of ERISA and the regulations issued thereunder (other than a Reportable Event not subject to the provision for 30-day notice to the PBGC under such regulations) with respect to an ERISA Plan or an ERISA Multiemployer Plan, or (ii) the withdrawal of the Account Party or any of its ERISA Affiliates from an ERISA Plan or an ERISA Multiemployer Plan during a plan year in which it was a "substantial employer" as defined in Section 4001(a)(2) of ERISA, or (iii) the filing of a notice of intent to terminate an ERISA Plan or an ERISA Multiemployer Plan or the treatment of an ERISA Plan or an ERISA Multiemployer Plan under Section 4041 of ERISA, or (iv) the institution of proceedings to terminate an ERISA Plan or an ERISA Multiemployer Plan by the PBGC, or (v) any other event or condition which might constitute grounds under Section 4042 of ERISA for the termination of, or the appointment of a trustee to administer, any ERISA Plan or ERISA Multiemployer Plan. "Eurocurrency Liabilities" has the meaning assigned to that term in Regulation D of the Board of Governors of the Federal Reserve System, as in effect from time to time. "Eurodollar Rate" means for any Interest Period for any Eurodollar Rate Advances comprising part of the same Term Borrowing, an interest rate per annum equal at all times during such Interest Period to the sum of: (i) the rate per annum (rounded upward to the nearest whole multiple of 1/100 of 1% per annum, if such rate is not such a multiple) determined by the Agent at which deposits in United States dollars in amounts comparable to the Eurodollar Rate Advance of CIBC comprising part of such Term Borrowing and for comparable periods as such Interest Period are offered by the principal office of CIBC in London, England to prime banks in the London interbank market at 11:00 A.M. (London time) two Business Days before the first day of such Interest Period, plus (ii) 0.75% per annum. "Eurodollar Rate Advance" means an Advance in respect of which the Account Party has selected in accordance with Article III hereof, and this Agreement provides for, interest to be computed on the basis of the Eurodollar Rate. "Eurodollar Reserve Percentage" of any Participating Bank for each Interest Period for each Eurodollar Rate Advance means the reserve percentage applicable during such Interest Period (or if more than one such percentage shall be so applicable, the daily average of such percentages for those days in such Interest Period during which any such percentage shall be so applicable) under Regulation D or other regulations issued from time to time by the Board of Governors of the Federal Reserve System (or any successor) for determining the maximum reserve requirement (including, without limitation, any emergency, supplemental or other marginal reserve requirement, without benefit of or credit for proration, exemptions or offsets) for such Participating Bank with respect to liabilities or assets consisting of or including "eurocurrency liabilities" having a term equal to such Interest Period. "Event of Default" has the meaning assigned to that term in Section 8.01. "Federal Funds Rate" means, for any period, a fluctuating interest rate per annum equal for each day during such period to the weighted average of the rates on overnight Federal funds transactions with members of the Federal Reserve System arranged by Federal funds brokers, as published on the next succeeding Business Day by the Federal Reserve Bank of New York, or, if such rate is not so published on the next succeeding Business Day, the average of the quotations for such day on such transactions received by the Agent from three Federal funds brokers of recognized standing selected by it. "FERC" means the Federal Energy Regulatory Commission. "Governmental Approval" means any authorization, consent, approval, license, permit, certificate, exemption of, or filing or registration with, any governmental authority or other legal or regulatory body (including, without limitation, the Securities and Exchange Commission, the FERC, the Nuclear Regulatory Commission and the Connecticut Department of Public Utility Control), required in connection with either (i) the execution, delivery or performance of any Loan Document or Related Document or the grant and perfection of any lien or security interest contemplated by the Security Documents or (ii) the nature of the Account Party's or any Principal Subsidiary's business as conducted or the nature of the property owned or leased by it. "Hazardous Substance" means any waste, substance or material identified as hazardous, dangerous or toxic by any office, agency, department, commission, board, bureau or instrumentality of the United States of America or of the State or locality in which the same is located having or exercising jurisdiction over such waste, substance or material. "Indemnified Person" has the meaning assigned to that term in Section 10.04(b) hereof. "Indenture" has the meaning assigned to that term in the Preliminary Statement. "Initial Advance" has the meaning assigned to that term in Section 3.02(a) hereof. "Initial Repayment Date" has the meaning assigned to that term in Section 3.02(a) hereof. "Interest Component" has the meaning assigned to that term in the Letter of Credit. "Interest Drawing" has the meaning assigned to that term in the Letter of Credit. "Interest Period" has the meaning assigned to that term in Section 3.03(b) hereof. "Issuer" has the meaning assigned to that term in the Preliminary Statement. "Issuer Resolution" means the resolution adopted by the Issuer that authorized the issuance of the Bonds, approved the terms and provisions of the Bonds, and approved those of the documents related to the Bonds to which the Issuer is a party. "Letter of Credit" has the meaning assigned to that term in the Preliminary Statement. "Lien" has the meaning assigned to that term in Section 7.02(a) hereof. "Loan Documents" means this Agreement and the Security Documents. "Majority Lenders" means on any date of determination, (i) the Issuing Bank and (ii) Participating Banks who, collectively, on such date, have Percentages in the aggregate of at least 66-2/3%. Determination of those Participating Banks satisfying the criteria specified above for action by the Majority Lenders shall be made by the Agent and shall be conclusive and binding on all parties absent manifest error. "Moody's" means Moody's Investors Service, Inc. or any successor thereto. "NU" means Northeast Utilities, an unincorporated voluntary business association organized under the laws of the Commonwealth of Massachusetts. "Participant" shall have the meaning assigned to that term in Section 10.06(b) hereof. "Participating Banks" means the Persons listed on the signature pages hereof following the heading "Participating Banks" and any other Person who becomes a party hereto pursuant to Section 10.06 hereof. "Participation Assignment" means a participation assignment entered into pursuant to Section 10.06 hereof by any Participating Bank and an assignee, in substantially the form of Exhibit 1.01B hereto. "Participation Percentage" means, as of any date of determination (i) with respect to a Participating Bank initially a party hereto, the percentage set forth opposite such Participating Bank's name on the signature pages hereof, except as provided in clause (iii), below, (ii) with respect to a Participating Bank that became a party hereto by operation of Section 10.06(a) hereof, the Participation Percentage stated to be assumed by such assignee Participating Bank in the relevant Participation Assignment, except as provided in clause (iii), below, and (iii) with respect to any Participating Bank described in clauses (i) and (ii), above, that assigns a percentage of its interests in accordance with Section 10.06(a) hereof, its participation percentage as reduced by the percentage so assigned. "Paying Agent" means (i) BayBank, as the initial paying agent for the Bonds under the Indenture, and (ii) any successor paying agent for the Bonds under the Indenture. "PBGC" means the Pension Benefit Guaranty Corporation (or any successor entity) established under ERISA. "Person" means an individual, partnership, corporation (including a business trust), joint stock company, trust, estate, unincorporated association, joint venture or other entity, or a government or any political subdivision or agency thereof. "Pledge Agreement" means the Pledge Agreement, dated as of December 1, 1992, by the Account Party in favor of the Issuing Bank, in substantially the form of Exhibit 1.01C hereto, and as the same may from time to time be amended, modified or supplemented. "Pledged Bonds" shall have the meaning assigned to that term in the Pledge Agreement. "Premium Component" has the meaning assigned to that term in the Letter of Credit. "Principal Component" has the meaning assigned to that term in the Letter of Credit. "Principal Subsidiary" means a Subsidiary, whether owned directly or indirectly by the Account Party, which, with respect to the Account Party and its Subsidiaries taken as a whole, represents a material portion of the Account Party's consolidated assets or consolidated net income (or loss), (it being understood that, as of the date of this Agreement, the Account Party has no Principal Subsidiaries). "Purchase Contract" means the Bond Purchase Agreement, dated December 16, 1992, among the Issuer, the Account Party and Goldman, Sachs & Co. "Recipient" has the meaning assigned to that term in Section 10.09 hereto. "Regulatory Transaction" means any merger or consolidation of the Account Party with or into, or any purchase or acquisition by the Account Party of the assets of (and any related assumption by the Account Party of the liabilities of) any utility company or utility-related company, if such transaction is undertaken pursuant to an order or request of, or otherwise in fulfillment of the stated goals of, a utility regulatory agency having jurisdiction over NU or any of its Subsidiaries. "Regulatory Transaction Entity" means any utility company or utility- related company (other than the Account Party) that is the subject of a Regulatory Transaction. "Related Documents" means the Letter of Credit, the Bonds, the Indenture, any Remarketing Agreement and the Purchase Contract. "Remarketing Agent" has the meaning assigned to that term in the Indenture. "Remarketing Agreement" means (i) the Remarketing Agreement, dated as of December 1, 1992, between the Account Party and Goldman, Sachs & Co., as the same may be amended from time to time; and (ii) any successor remarketing agreement between the Account Party and a successor Remarketing Agent as shall be in effect from time to time in accordance with the terms of the Indenture. "S&P" means Standard and Poor's Corporation or any successor thereto. "Security Documents" means the Pledge Agreement and the Indenture. "Stated Amount" has the meaning assigned to that term in the Preliminary Statement hereto. "Stated Termination Date" means the expiration date specified in clause (i) of the first paragraph of Paragraph (1) of the Letter of Credit, as such date may be extended pursuant to Section 2.05 hereof. "Subsidiary" shall mean, with respect to any person (the Parent), any corporation, association or other business entity of which securities or other ownership interests representing 50% or more of the ordinary voting power are, at the time as of which any determination is being made, owned or controlled by the Parent or one or more Subsidiaries of the Parent or by the Parent and one or more Subsidiaries of the Parent. "Tender Drawing" has the meaning assigned to that term in the Letter of Credit. "Term Advance" has the meaning assigned to that term in Section 3.02(b) hereof, and refers to a Base Rate Advance, a CD Rate Advance or a Eurodollar Rate Advance (each of which shall be a "Type" of Term Advance). The Type of a Term Advance may change from time to time when such Term Advance is Converted. For purposes of this Agreement, all Term Advances of a Participating Bank (or portions thereof) made as, or Converted to, the same Type and Interest Period on the same day shall be deemed a single Term Advance by such Participating Bank until repaid or next Converted. "Term Borrowing" means a borrowing consisting of Term Advances of the same Type and Interest Period made on the same day by the Participating Banks, ratably in accordance with their respective Participation Percentages. A Term Borrowing may be referred to herein as being a "Type" of Term Borrowing, corresponding to the Type of Term Advances comprising such Term Borrowing. For purposes of this Agreement, all Term Advances made as, or Converted to, the same Type and Interest Period on the same day shall be deemed a single Term Borrowing until repaid or next Converted. "Termination Date" means the Stated Termination Date or the earlier date of termination of the Commitments pursuant to Sections 2.02 or 8.02 hereunder. "Trustee" has the meaning assigned to that term in the Preliminary Statement hereto. "Type" has the meaning assigned to such term in the definitions of "Term Advance" and "Term Borrowing" herein. "Unmatured Default" means the occurrence and continuance of an event which, with the giving of notice or lapse of time or both, would constitute an Event of Default. SECTION 1.02 Computation of Time Periods. In the computation of periods of time under this Agreement any period of a specified number of days or months shall be computed by including the first day or month occurring during such period and excluding the last such day or month. In the case of a period of time "from" a specified date "to" or "until" a later specified date, the word "from" means "from and including" and the words "to" and "until" each means "to but excluding". SECTION 1.03 Accounting Terms. All accounting terms not specifically defined herein shall be construed in accordance with generally accepted accounting principles applied on a basis consistent with the application employed in the preparation of the Account Party's consolidated financial statements included in its Annual Report on Form 10-K for the year ended December 31, 1991. SECTION 1.04 Computations of Outstandings. Whenever reference is made in this Agreement to the principal amount outstanding on any date under this Agreement, such reference shall refer to the sum of (i) the Available Amount on such date, (ii) the aggregate principal amount of all Advances outstanding on such date and (iii) the aggregate amount of all demand loans under Section 3.01 hereunder on such date, in each case after giving effect to all transactions to be made on such date and the application of the proceeds thereof. ARTICLE II THE LETTER OF CREDIT SECTION 2.01 The Letter of Credit. The Issuing Bank agrees, on the terms and conditions hereinafter set forth (including, without limitation, the applicable conditions precedent set forth in Article V hereof), to issue the Letter of Credit to the Paying Agent, upon not less than three Business Days prior notice from the Account Party, on the Closing Date. SECTION 2.02 Termination of the Commitments. The obligation of the Issuing Bank to issue the Letter of Credit shall automatically terminate if unexercised at 5:00 P.M. (New York City time) on December 31, 1992. SECTION 2.03 Commissions and Fees. (a) The Account Party hereby agrees to pay to the Agent, for the account of the Participating Banks ratably in accordance with their respective Participation Percentages, a letter of credit commission on the Available Amount in effect from time to time from the date of issuance of the Letter of Credit until the Termination Date (disregarding for such purpose any temporary diminution thereof arising from drawings under the Letter of Credit to pay interest (or purchase price corresponding to interest) on the Bonds, regardless of whether the amount so drawn shall be thereafter reinstated), at a rate equal to 0.60% per annum, payable quarterly in arrears on the first day of March, June, September and December in each year, commencing on the first such date to occur following the date of issuance of the Letter of Credit, and on the Credit Termination Date. (b) The Account Party also agrees to pay to the Agent, for the account of the Issuing Bank, such other fees as may be agreed upon from time to time by the Account Party and the Issuing Bank. SECTION 2.04 Reinstatement of the Letter of Credit. (a) The Interest Component and the Principal Component shall, from time to time, be reinstated by the Issuing Bank in accordance with, and only to the extent provided in, the Letter of Credit. In no event shall reductions in the Premium Component be reinstated. (b) Interest Component. With respect to reinstatement of reductions in the Interest Component resulting from Interest Drawings: (i) The Issuing Bank may only deliver to the Paying Agent any notice of non-reinstatement pursuant to Paragraph 5(i)(A) of the Letter of Credit if (A) the Issuing Bank and/or the Participating Banks have not been reimbursed in full by the Account Party for one or more drawings, together with interest, if any, owing thereon pursuant to this Agreement, or (B) an Event of Default has occurred and is then continuing. (ii) If, subsequent to any such delivery of a notice of non- reinstatement, the circumstances giving rise to the delivery of such notice of non-reinstatement shall have ceased to exist (whether as a result of reimbursement of unreimbursed drawings, or waiver or cure of an Event of Default, or otherwise), then, provided that no other Event of Default shall have occurred and be continuing, the Issuing Bank shall deliver to the Paying Agent, by hand delivery or facsimile transmission, a Notice of Reinstatement in the form of Exhibit 5 to the Letter of Credit reinstating that portion of the Interest Component in respect of which such notice of non-reinstatement was given. (c) Principal Component. With respect to reinstatement of a reduction in the Principal Component resulting from any Tender Drawing, IF: (i) such reduction has not been reinstated pursuant to Paragraph 5(ii)(A) of the Letter of Credit; (ii) the Issuing Bank and/or the Participating Banks shall have been reimbursed by the Account Party for such Tender Drawing; (iii) any demand loan(s) and Advance(s) made in respect of such Tender Drawing shall have been repaid by the Account Party, together with any interest thereon and any other amounts payable hereunder in connection therewith; AND (iv) no Event of Default shall have occurred and then be continuing; THEN, the Issuing Bank shall deliver to the Paying Agent, by hand delivery or facsimile transmission, a Notice of Reinstatement in the form of Exhibit 5 to the Letter of Credit reinstating the Principal Component to the extent of such Tender Drawing. SECTION 2.05 Extension of the Stated Termination Date. Unless the Letter of Credit shall have previously expired in accordance with its terms, at least 105 days but not more than 120 days before the Stated Termination Date, the Account Party may, by notice to the Agent (any such notice being irrevocable), request the Issuing Bank and the Participating Banks to extend the Stated Termination Date of the Letter of Credit for a period of one year. If the Account Party shall make such request, the Agent shall promptly inform the Issuing Bank and the Participating Banks and, no later than 60 days prior to the Stated Termination Date, the Agent shall notify the Account Party in writing (with a copy of such notice to the Trustee and the Paying Agent) if the Issuing Bank and the Participating Banks consent to such request and the conditions of such consent (including conditions relating to legal documentation). The granting of any such consent shall be in the sole and absolute discretion of the Issuing Bank and the Participating Banks, and if the Agent shall not so notify the Account Party, such lack of notification shall be deemed to be a determination not to consent to such request. ARTICLE III REIMBURSEMENT AND ADVANCES SECTION 3.01 Reimbursement on Demand. Subject to the provisions of Section 3.02 hereof, the Account Party hereby agrees to pay (whether with the proceeds of Initial Advances made pursuant to this Agreement or otherwise) to the Issuing Bank on demand (a) on and after each date on which the Issuing Bank shall pay any amount under the Letter of Credit pursuant to any draft, but only after so paid by the Issuing Bank, a sum equal to such amount so paid (which sum shall constitute a demand loan from the Issuing Bank to the Account Party from the date of such payment by the Issuing Bank until so paid by the Account Party), plus (b) interest on any amount remaining unpaid by the Account Party to the Issuing Bank under clause (a), above, from the date such amount becomes payable on demand until payment in full, at the Default Rate in effect from time to time. No reinstatement of the Interest Component or the Principal Component despite the failure by the Account Party to reimburse the Issuing Bank for any previous drawing to pay interest on the Bonds shall limit or impair the Account Party's obligations under this Section 3.01. SECTION 3.02 Advances. Each Participating Bank agrees to make Initial Advances and Term Advances for the account of the Account Party from time to time upon the terms and subject to the conditions set forth in this Agreement. (a) Initial Advances; Repayment of Initial Advances. If the Issuing Bank shall honor any Tender Drawing and if the conditions precedent set forth in Section 5.03 of this Agreement have been satisfied as of the date of such honor, then, each Participating Bank's payment made to the Issuing Bank pursuant to Section 3.07 hereof in respect of such Tender Drawing shall be deemed to constitute an advance made for the account of the Account Party by such Participating Bank (each such advance being an "Initial Advance" made by such Participating Bank). Each Initial Advance shall be made as a Base Rate Advance, shall bear interest at the Alternate Base Rate and shall not be entitled to be Converted. Subject to Article VIII of this Agreement, each Initial Advance and all interest thereon shall be due and payable on the earlier to occur of (i) the date 30 days from the date of such Initial Advance (such repayment date being the "Initial Repayment Date" for such Initial Advance) and (ii) the Termination Date. The Account Party may repay the principal amount of any Initial Advance with (and to the extent of) the proceeds of a Term Advance made pursuant to subsection (b), below, and may prepay Initial Advances in accordance with Section 3.06 hereof. (b) Term Advances; Repayment. Subject to the satisfaction of the conditions precedent set forth in Section 5.04 hereof and the other conditions of this subsection (b), each Participating Bank agrees to make one or more advances for the account of the Account Party ("Term Advances") on each Initial Repayment Date in an aggregate principal amount equal to the amount of such Participating Bank's Initial Advances maturing on such Initial Repayment Date. All Term Advances comprising a single Term Borrowing shall be made upon written notice given by the Account Party to the Agent not later than 11:00 A.M. (New York City time) (A) in the case of a Term Borrowing comprised of Base Rate Advances, on the Business Day of such proposed Term Borrowing, (B) in the case of a Term Borrowing comprised of CD Rate Advances, two Business Days prior to the date of such Term Borrowing and (C) in the case of a Term Borrowing comprised of Eurodollar Rate Advances, three Business Days prior to the date of such proposed Term Borrowing. The Agent shall notify each Participating Bank of the contents of such notice promptly after receipt thereof. Each such notice shall specify therein the following information: (W) the date on which such Term Borrowing is to be made, (X) the principal amount of Term Advances comprising such Term Borrowing, (Y) the Type of Term Borrowing and (Z) the duration of the initial Interest Period, if applicable, proposed to apply to the Term Advances comprising such Term Borrowing. The proceeds of each Participating Bank's Term Advances shall be applied solely to the repayment of the Initial Advances made by such Participating Bank and shall in no event be made available to the Account Party. The principal amount of each Term Advance, together with all accrued and unpaid interest thereon, shall be due and payable on the earlier to occur of (x) the same calendar date occurring 35 months following the date upon which such Term Advance is made (or, if such month does not have a corresponding date, on the last day of such month) and (y) the Termination Date. SECTION 3.03 Interest on Advances. The Account Party shall pay interest on the unpaid principal amount of each Advance from the date of such Advance until such principal amount is paid in full at the applicable rate set forth below: (a) Alternate Base Rate. Except to the extent that the Account Party shall elect to pay interest on any Advance for any Interest Period pursuant to paragraph (c) or (d) of this Section 3.03, the Account Party shall pay interest on each Advance (including all Initial Advances) from the date thereof until the date such Advance is due, at a fluctuating interest rate per annum in effect from time to time equal to the Alternate Base Rate in effect from time to time. The Account Party shall pay interest on each Advance bearing interest in accordance with this subsection quarterly in arrears on the first day of March, June, September and December in each year and on the Termination Date or the earlier date for repayment of such Advance (including the Initial Repayment Date therefor, in the case of an Initial Advance). b. Interest Periods. Subject to the other requirements of this Section 3.03, the Account Party may from time to time elect to have the interest on all Term Advances comprising part of the same Term Borrowing determined and payable for a specified period (an "Interest Period" for such Term Advances) in accordance with paragraph (c) or (d) of this Section 3.03. The first day of an Interest Period for such Term Advances shall be the date such Advance is made or most recently Converted, which shall be a Business Day. All Interest Periods shall end on or prior to the Stated Termination Date. Any Interest Period for a Term Advance that would otherwise end after the Termination Date or earlier date for the repayment of such Advance shall be deemed to end on the Termination Date or such earlier repayment date, as the case may be. (c) CD Rate. Subject to the requirements of this Section 3.03 and Article V hereof, the Account Party may from time to time elect to have any Term Advances comprising part of the same Term Borrowing made as, or Converted to, CD Rate Advances. The Interest Period applicable to such CD Rate Advances shall be of 30, 60, 90 or 180 days' duration, as the Account Party shall select in its notice delivered to the Agent pursuant to Section 3.02(b) or 3.04 hereof, as applicable. If the Account Party shall have made such election, the Account Party shall pay interest on such CD Rate Advances at the CD Rate, for the applicable Interest Period for such CD Rate Advances, which interest shall be payable on the last day of such Interest Period, on the date for repayment for such CD Rate Advances and also, in the case of any Interest Period of 180 days' duration, on the 90th day of such Interest Period. (d) Eurodollar Rate. Subject to the requirements of this Section 3.03 and Article V hereof, the Account Party may from time to time elect to have any Term Advances comprising part of the same Term Borrowing made as, or Converted to, Eurodollar Rate Advances. The Interest Period applicable to such Eurodollar Rate Advances shall be of one, two, three or six whole months' duration, as the Account Party shall select in its notice delivered to the Agent pursuant to Section 3.02(b) or 3.04 hereof, as applicable. If the Account Party shall have made such election, the Account Party shall pay interest on such Eurodollar Rate Advances at the Eurodollar Rate, for the applicable Interest Period for such Eurodollar Rate Advances, which interest shall be payable on the last day of such Interest Period, on the date for repayment for such Eurodollar Rate Advances and also, in the case of any Interest Period of six months' duration, on that day of the third month of such Interest Period which corresponds with the first day of such Interest Period (or, if any such month does not have a corresponding day, then on the last day of such month). Any Interest Period pertaining to Eurodollar Rate Advances that begins on the last Business Day of a calendar month (or on a day for which there is no numerically corresponding day in the calendar month at the end of such Interest Period) shall end on the last Business Day of a calendar month. (e) Interest Rate Determinations. The Agent shall give prompt notice to the Account Party and the Participating Banks of the Eurodollar Rate or CD Rate determined from time to time by the Agent to be applicable to each Eurodollar Rate Advance or CD Rate Advance, as the case may be. SECTION 3.04 Conversion of Term Advances. Subject to the satisfaction of the conditions precedent set forth in Section 5.03 hereof, the Account Party may elect to Convert one or more Term Advances of any Type to one or more Term Advances of the same or any other Type on the following terms and subject to the following conditions: (a) Each Conversion shall be made as to all Term Advances comprising a single Term Borrowing upon written notice given by the Account Party to the Agent not later than 11:00 A.M. (New York City time) on the third Business Day prior to the date of the proposed Conversion. The Agent shall notify each Participating Bank of the contents of such notice promptly after receipt thereof. Each such notice shall specify therein the following information: (A) the date of such proposed Conversion (which in the case of CD Rate Advances or Eurodollar Rate Advances shall be the last day of the Interest Period then applicable to such Term Advances to be Converted), (B) Type of, and Interest Period, if any, applicable to the Term Advances proposed to be Converted, (C) the aggregate principal amount of Term Advances proposed to be Converted, and (D) the Type of Term Advances to which such Term Advances are proposed to be Converted and the Interest Period, if any, to be applicable thereto. (b) During the continuance of an Unmatured Default or an Event of Default, the right of the Account Party to Convert Term Advances to CD Rate Advances or to Eurodollar Rate Advances shall be suspended, and all CD Rate Advances and Eurodollar Rate Advances then outstanding shall be Converted to Base Rate Advances on the last day of the Interest Period then in effect, if, on such day, an Unmatured Default or an Event of Default shall be continuing. (c) If no notice of Conversion is received by the Agent as provided in subsection (a) above with respect to any outstanding CD Rate Advances or Eurodollar Rate Advances, the Agent shall treat such absence of notice as a deemed notice of Conversion providing for such Advances to be Converted to Base Rate Advances on the last day of the Interest Period then in effect for such CD Rate Advances or Eurodollar Rate Advances. SECTION 3.05 Other Terms Relating to the Making and Conversion of Advances. (a) Notwithstanding anything in Section 3.02, 3.03 or 3.04, above, to the contrary: (i) at no time shall more than six different Term Borrowings be outstanding hereunder; and (ii) each Term Borrowing consisting of CD Rate Advances or Eurodollar Rate Advances shall be in the aggregate principal amount of $10,000,000 or an integral multiple of $1,000,000 in excess thereof. (b) Each notice of borrowing pursuant to Section 3.02(b) hereof and each notice of Conversion pursuant to Section 3.04 hereof shall be irrevocable and binding on the Account Party. SECTION 3.06 Prepayment of Advances. (a) The Account Party shall have no right to prepay any principal amount of any Advances except in accordance with subsections (b) and (c) below. (b) The Account Party may, upon at least one Business Day's notice to the Agent stating the proposed date and aggregate principal amount of the prepayment and the specific Initial Advances or Term Borrowing(s) to be prepaid, and if such notice is given, the Account Party shall, prepay, in whole or ratably in part, together with accrued interest to the date of such prepayment on the principal amount prepaid and any amounts due pursuant to Section 4.03, the outstanding principal amount of (i) all Initial Advances made on the same date or (ii) all Term Advances comprising the same Term Borrowing, in each case as the Account Party shall designate in such notice; provided, however, that each partial prepayment shall be in an aggregate principal amount not less than $10,000,000, or, if less, the aggregate principal amount of all Advances then outstanding. (c) Prior to or simultaneously with the resale of all of the Bonds purchased with the proceeds of a Tender Drawing, the Account Party shall prepay, or cause to be prepaid, in full, the then outstanding principal amount of all Initial Advances and of all Term Advances comprising the same Term Borrowing(s) arising pursuant to such Tender Drawing, together with all interest thereon to the date of such prepayment. If less than all of such Bonds are resold, then prior to or simultaneously with such resale the Account Party shall prepay or cause to be prepaid that portion of such Advances, together with all interest thereon to the date of such prepayment, equal to the then outstanding principal amount thereof multiplied by a fraction, the numerator of which shall be the principal amount of the Bonds resold and the denominator of which shall be the principal amount of all of the Bonds purchased with the proceeds of the relevant Tender Drawing. SECTION 3.07 Participation; Reimbursement of Issuing Bank. (a) The Issuing Bank hereby sells and transfers to each Participating Bank, and each Participating Bank hereby acquires from the Issuing Bank, an undivided interest and participation to the extent of such Participating Bank's Participation Percentage in and to (i) the Letter of Credit, including the obligations of the Issuing Bank under and in respect thereof and the Account Party's reimbursement and other obligations in respect thereof and (ii) each demand loan or deemed demand loan made by the Issuing Bank, whether now existing or hereafter arising. (b) If the Issuing Bank (i) shall not have been reimbursed in full for any payment made by the Issuing Bank under the Letter of Credit on the date of such payment or (ii) shall make any demand loan to the Account Party, the Issuing Bank shall promptly notify the Agent and the Agent shall promptly notify each Participating Bank of such non-reimbursement or demand loan and the amount thereof. Upon receipt of such notice from the Agent, each Participating Bank shall pay to the Issuing Bank, directly, an amount equal to such Participating Bank's ratable portion (according to such Participating Bank's Participation Percentage) of such unreimbursed amount or demand loan paid or made by the Issuing Bank, plus interest on such amount at a rate per annum equal to the Federal Funds Rate from the date of such payment by the Issuing Bank to the date of payment to the Issuing Bank by such Participating Bank. All such payments by each Participating Bank shall be made in United States dollars and in same day funds: (x) not later than 2:45 P.M. (New York City time) on the day such notice is received by such Participating Bank if such notice is received at or prior to 12:30 P.M. (New York City time) on a Business Day; or (y) not later than 12:00 Noon (New York City time) on the Business Day next succeeding the day such notice is received by such Participating Bank, if such notice is received after 12:30 P.M. (New York City time) on a Business Day. If a Participating Bank shall have paid to the Issuing Bank its ratable portion of any unreimbursed amount or demand loan paid or made by the Issuing Bank, together with all interest thereon required by the second sentence of this subsection (b), such Participating Bank shall be entitled to receive its ratable share of all interest paid by the Account Party in respect of such unreimbursed amount or demand loan from the date paid or made by the Issuing Bank. If such Participating Bank shall have made such payment to the Issuing Bank, but without all such interest thereon required by the second sentence of this subsection (b), such Participating Bank shall be entitled to receive its ratable share of the interest paid by the Account Party in respect of such unreimbursed amount or demand loan only from the date it shall have paid all interest required by the second sentence of this subsection (b). (c) Each Participating Bank's obligation to make each payment to the Issuing Bank, and the Issuing Bank's right to receive the same, shall be absolute and unconditional and shall not be affected by any circumstance whatsoever, including, without limitation, the foregoing or Section 4.06 hereof, or the occurrence or continuance of an Event of Default, or the non- satisfaction of any condition precedent set forth in Sections 5.03 or 5.04 hereof, or the failure of any other Participating Bank to make any payment under this Section 3.07. Each Participating Bank further agrees that each such payment shall be made without any offset, abatement, withholding or reduction whatsoever. (d) The failure of any Participating Bank to make any payment to the Issuing Bank in accordance with subsection (b) above, shall not relieve any other Participating Bank of its obligation to make payment, but neither the Issuing Bank nor any Participating Bank shall be responsible for the failure of any other Participating Bank to make such payment. If any Participating Bank shall fail to make any payment to the Issuing Bank in accordance with subsection (b) above, then such Participating Bank shall pay to the Issuing Bank forthwith on demand such corresponding amount together with interest thereon, for each day until the date such amount is repaid to the Issuing Bank at the Federal Funds Rate. Nothing herein shall in any way limit, waive or otherwise reduce any claims that any party hereto may have against any non-performing Participating Bank. (e) If any Participating Bank shall fail to make any payment to the Issuing Bank in accordance with subsection (b) above, then, in addition to other rights and remedies which the Issuing Bank may have, the Agent is hereby authorized, at the request of the Issuing Bank, to withhold and to apply the payment of such amounts owing to such Participating Bank to the Issuing Bank and any related interest, that portion of any payment received by the Agent that would otherwise be payable to such Participating Bank. In furtherance of the foregoing, if any Participating Bank shall fail to make any payment to the Issuing Bank in accordance with subsection (b), above, and such failure shall continue for five Business Days following written notice of such failure from the Issuing Bank to such Participating Bank, the Issuing Bank may acquire, or transfer to a third party in exchange for the sum or sums due from such Participating Bank, such Participating Bank's interest in the related unreimbursed amounts and demand loans and all other rights of such Participating Bank hereunder in respect thereof, without, however, relieving such Participating Bank from any liability for damages, costs and expenses suffered by the Issuing Bank as a result of such failure. The purchaser of any such interest shall be deemed to have acquired an interest senior to the interest of such Participating Bank and shall be entitled to receive all subsequent payments which the Issuing Bank or the Agent would otherwise have made hereunder to such Participating Bank in respect of such interest. ARTICLE IV PAYMENTS SECTION 4.01 Payments and Computations. (a) The Account Party shall make each payment hereunder (i) in the case of reimbursement obligations pursuant to Section 3.01 hereof (excluding any portion thereof in respect of which an Initial Advance is to be made), not later than 2:30 P.M. (New York City time) on the day the related drawing under the Letter of Credit is paid by the Issuing Bank, and (ii) in all other cases, not later than 12:30 P.M. (New York City time) on the day when due, in each case in lawful money of the United States of America to the Agent at its address referred to in Section 10.02 hereof in immediately available funds. The Agent will promptly thereafter cause to be distributed like funds relating to the payment of reimbursements, principal, interest, fees or other amounts payable to the Issuing Bank and the Participating Banks to whom the same are payable, ratably, at its address set forth in Section 10.02 hereof (in the case of the Issuing Bank) or for the account of their respective Applicable Lending Offices (in the case of the Participating Banks), in each case to be applied in accordance with the terms of this Agreement. (b) The Account Party hereby authorizes the Issuing Bank, and each Participating Bank, if and to the extent payment owed to the Issuing Bank, or such Participating Bank, as the case may be, is not made when due hereunder, to charge from time to time against any or all of the Account Party's accounts with the Issuing Bank or such Participating Bank, as the case may be, any amount so due. (c) All computations of interest based on the Alternate Base Rate when based on CIBC's prime rate referred to in the definition of "Alternate Base Rate" and all computations of fees and commissions hereunder shall be made by the Agent on the basis of a year of 365 or 366 days, as the case may be. All other computations of interest hereunder (including computations of interest based on the CD Rate, the Eurodollar Rate and the Federal Funds Rate (including the Alternate Base Rate if and so long as such Rate is based on the Federal Funds Rate), and of other amounts pursuant to Section 4.03 hereof, shall be made by the Agent or the party claiming such other amounts, as the case may be, on the basis of a year of 360 days. In each such case, such computation shall be made for the actual number of days (including the first day, but excluding the last day) occurring in the period for which such interest, commissions or fees are payable. Each such determination by the Agent or a Participating Bank, as the case may be, shall be conclusive and binding for all purposes, absent manifest error. (d) Whenever any payment hereunder shall be stated to be due, or the last day of an Interest Period hereunder shall be stated to occur, on a day other than a Business Day, such payment shall be made and the last day of such Interest Period shall occur on the next succeeding Business Day, and such extension of time shall in such case be included in the computation of payment of interest, commissions and fees hereunder; provided, however, that if such extension would cause payment of interest on or principal of Eurodollar Rate Advances to be made, or the last day of an Interest Period for a Eurodollar Rate Advance to occur, in the next following calendar month, such payment shall be made on the next preceding Business Day and such reduction of time shall in such case be included in the computation of payment of interest hereunder. (e) Unless the Agent shall have received notice from the Account Party prior to the date on which any payment is due to the Issuing Bank or the Participating Banks hereunder that the Account Party will not make such payment in full, the Agent may assume that the Account Party has made such payment in full to the Agent on such date and the Agent may, in reliance upon such assumption, cause to be distributed to the Issuing Bank and/or each Participating Bank on such due date an amount equal to the amount then due the Issuing Bank and/or such Participating Bank. If and to the extent the Account Party shall not have so made such payment in full to the Agent, the Issuing Bank and/or each such Participating Bank shall repay to the Agent forthwith on demand such amount distributed to the Issuing Bank and/or such Participating Bank, together with interest thereon, for each day from the date such amount is distributed to the Issuing Bank and/or such Participating Bank until the date the Issuing Bank and/or such Participating Bank repays such amount to the Agent, at the Federal Funds Rate. (f) If, after the Agent has paid to the Issuing Bank or any Participating Bank any amount pursuant to subsection (a) above, such payment is rescinded or must otherwise be returned or must be paid over by the Agent or the Issuing Bank to any Person, whether pursuant to any bankruptcy or insolvency law, Section 4.04 hereof or otherwise, such Participating Bank shall, at the request of the Agent or the Issuing Bank, promptly repay to the Agent or the Issuing Bank, as the case may be, an amount equal to its ratable share of such payment, together with any interest required to be paid by the Agent or the Issuing Bank with respect to such payment. SECTION 4.02 Default Interest. Any amounts payable hereunder that are not paid when due shall (to the fullest extent permitted by law) bear interest, from the date when due until paid in full, at the Default Rate, payable on demand. SECTION 4.03 Yield Protection. (a) Change in Circumstances. Notwithstanding any other provision herein, if after the date hereof, the adoption of or any change in applicable law or regulation or in the interpretation or administration thereof by any governmental authority charged with the interpretation or administration thereof (whether or not having the force of law) shall (i) change the basis of taxation of payments to the Issuing Bank or any Participating Bank of the principal of or interest on any Eurodollar Rate Advance or CD Rate Advance made by such Participating Bank or any fees or other amounts payable hereunder (other than changes in respect of taxes imposed on the overall net income of the Issuing Bank or such Participating Bank, or its Applicable Lending Office, by the jurisdiction in which the Issuing Bank or such Participating Bank has its principal office or in which such Applicable Lending Office is located or by any political subdivision or taxing authority therein), or (ii) shall impose, modify or deem applicable any reserve, special deposit or similar requirement against letters of credit (or participatory interests therein) issued by, commitments or assets of, deposits with or for the account of, or credit extended by, the Issuing Bank or such Participating Bank (excluding, in the case of CD Rate Advances, any such requirement included in the CD Rate), or (iii) shall impose on the Issuing Bank or such Participating Bank any other condition affecting this Agreement, the Letter of Credit or participatory interests therein or Eurodollar Rate Advances or CD Rate Advances, and the result of any of the foregoing shall be (A) to increase the cost to the Issuing Bank or such Participating Bank of issuing, maintaining or participating in this Agreement or the Letter of Credit or of agreeing to make, making or maintaining any Advance or (B) to reduce the amount of any sum received or receivable by the Issuing Bank or such Participating Bank hereunder (whether of principal, interest or otherwise), then the Account Party will pay to the Issuing Bank or such Participating Bank, upon demand, such additional amount or amounts as will compensate the Issuing Bank or such Participating Bank for such additional costs incurred or reduction suffered. (b) Capital. If the Issuing Bank or any Participating Bank shall have determined that the applicability of any law, rule, regulation or guideline adopted pursuant to or arising out of the July 1988 report of the Basle Committee on Banking Regulations and Supervisory Practices entitled "International Convergence of Capital Measurement and Capital Standards", or the adoption after the date hereof of any law, rule, regulation or guideline regarding capital adequacy, or any change in any of the foregoing or in the interpretation or administration of any of the foregoing by any governmental authority, central bank or comparable agency charged with the interpretation or administration thereof, or compliance by the Issuing Bank or any Participating Bank (or any Applicable Lending Office of the Issuing Bank or such Participating Bank), or any holding company of any such entity, with any request or directive regarding capital adequacy (whether or not having the force of law) of any such authority, central bank or comparable agency, has or would have the effect (i) of reducing the rate of return on such entity's capital or on the capital of such entity's holding company, if any, as a consequence of this Agreement, the Letter of Credit or such entity's participatory interest therein, any Commitment hereunder or the portion of the Advances made by such entity pursuant hereto to a level below that which such entity or such entity's holding company could have achieved, but for such applicability, adoption, change or compliance (taking into consideration such entity's policies and the policies of such entity's holding company with respect to capital adequacy), or (ii) of increasing or otherwise determining the amount of capital required or expected to be maintained by such entity or such entity's holding company based upon the existence of this Agreement, the Letter of Credit or such entity's participatory interest therein, any Commitment hereunder, the portion of the Advances made by such entity pursuant hereto and other similar such credits, participations, commitments, agreements or assets, then from time to time the Account Party shall pay to the Issuing Bank or such Participating Bank, upon demand, such additional amount or amounts as will compensate such entity or such entity's holding company for any such reduction or allocable capital cost suffered. (c) Eurodollar Reserves. The Account Party shall pay to each Participating Bank upon demand, so long as such Participating Bank shall be required under regulations of the Board of Governors of the Federal Reserve System to maintain reserves with respect to liabilities or assets consisting of or including Eurocurrency Liabilities, additional interest on the unpaid principal amount of such Participating Bank's portion of each Eurodollar Rate Advance, from the date of such Advance until such principal amount is paid in full, at an interest rate per annum equal at all times to the remainder obtained by subtracting (i) the rate described in clause (i) of the definition of "Eurodollar Rate" for the Interest Period for such Advance from (ii) the rate obtained by dividing such rate by a percentage equal to 100% minus the Eurodollar Reserve Percentage of such Participating Bank for such Interest Period. Such additional interest shall be determined by such Participating Bank and notified to the Account Party and the Issuing Bank. (d) Breakage Indemnity. The Account Party shall indemnify each Participating Bank against any loss, cost or reasonable expense which such Participating Bank may sustain or incur as a consequence of (i) any failure by the Account Party to fulfill on the date of any Advance or Conversion hereunder the applicable conditions set forth in Articles III and V, (ii) any failure by the Account Party to Convert any Advance hereunder after irrevocable notice of Conversion has been given pursuant to Section 3.04 hereof, (iii) any payment, prepayment or Conversion of a Eurodollar Rate Advance or CD Rate Advance required or permitted by any other provision of this Agreement or otherwise made or deemed made on a date other than the last day of the Interest Period applicable thereto, (iv) any default in payment or prepayment of the principal amount of any Advance or any part thereof or interest accrued thereon, as and when due and payable (at the due date thereof, by irrevocable notice of prepayment or otherwise) or (v) the occurrence of any Event of Default, including, in each such case, any loss or reasonable expense sustained or incurred or to be sustained or incurred in liquidating or employing deposits from third parties acquired to effect or maintain such Advance or any part thereof as a Eurodollar Rate Advance or CD Rate Advance. Such loss, cost or reasonable expense shall include an amount equal to the excess, if any, as reasonably determined by such Participating Bank, of (A) its cost of obtaining the funds for the Advance being paid, prepaid, Converted or not borrowed (based on the Eurodollar Rate or CD Rate) for the period from the date of such payment, prepayment, Conversion or failure to borrow to the last day of the Interest Period for such Advance (or, in the case of a failure to borrow, the Interest Period for such Advance which would have commenced on the date of such failure) over (B) the amount of interest (as reasonably determined by such Participating Bank) that would be realized by such Participating Bank in reemploying the funds so paid, prepaid, Converted or not borrowed for such period or Interest Period, as the case may be. For purposes of this subsection (d), it shall be presumed that each Participating Bank shall have funded each such Advance with a fixed-rate instrument bearing the rates and maturities designated in the determination of the applicable interest rate for such Advance. (e) Notices. A certificate of the Issuing Bank or any Participating Bank setting forth such entity's claim for compensation hereunder and the amount necessary to compensate such entity or its holding company pursuant to subsections (a) through (d) of this Section 4.03 shall be submitted to the Account Party and the Issuing Bank and shall be conclusive and binding for all purposes, absent manifest error. The Account Party shall pay the Issuing Bank or such Participating Bank directly the amount shown as due on any such certificate within ten days after its receipt of the same. The failure of any entity to provide such notice or to make demand for payment under this Section 4.03 shall not constitute a waiver of such Participating Bank's rights hereunder; provided, that such entity shall not be entitled to demand payment pursuant to subsections (a) through (d) of this Section 4.03 in respect of any loss, cost, expense, reduction or reserve if such demand is made more than one year following the later of such entity's incurrence or sufferance thereof or such entity's actual knowledge of the event giving rise to such entity's rights pursuant to such subsections. The protection of this Section 4.03 shall be available to the Issuing Bank and each Participating Bank regardless of any possible contention of the invalidity or inapplicability of the law, rule, regulation, guideline or other change or condition which shall have occurred or been imposed. (f) Change in Legality. Notwithstanding any other provision herein, if the adoption of or any change in any law or regulation or in the interpretation or administration thereof by any governmental authority charged with the administration or interpretation thereof shall make it unlawful for any Participating Bank to make or maintain any Eurodollar Rate Advance or to give effect to its obligations as contemplated hereby with respect to any Eurodollar Rate Advance, then, by written notice to the Account Party and the Issuing Bank, such Participating Bank may: (i) declare that Eurodollar Rate Advances will not thereafter be made by such Participating Bank hereunder, whereupon the right of the Account Party to select Eurodollar Rate Advances for any Advance or Conversion shall be forthwith suspended until such Participating Bank shall withdraw such notice as provided hereinbelow or shall cease to be a Participating Bank hereunder; and (ii) require that all outstanding Eurodollar Rate Advances be Converted to Base Rate Advances, in which event all Eurodollar Rate Advances shall be automatically Converted to Base Rate Advances as of the effective date of such notice as provided hereinbelow. Upon receipt of any such notice, the Agent shall promptly notify the Participating Banks thereof. Promptly upon becoming aware that the circumstances that caused such Participating Bank to deliver such notice no longer exist, such Participating Bank shall deliver notice thereof to the Account Party and the Agent withdrawing such prior notice (but the failure to do so shall impose no liability upon such Participating Bank). Promptly upon receipt of such withdrawing notice from such Participating Bank, the Agent shall deliver notice thereof to the Account Party and the Participating Banks and such suspension shall terminate. Prior to any Participating Bank giving notice to the Account Party under this subsection (f), such Participating Bank shall use reasonable efforts to change the jurisdiction of its Applicable Lending Office, if such change would avoid such unlawfulness and would not, in the sole determination of such Participating Bank, be otherwise disadvantageous to such Participating Bank. Any notice to the Account Party by any Participating Bank shall be effective as to each Eurodollar Rate Advance on the last day of the Interest Period currently applicable to such Eurodollar Rate Advance; provided that if such notice shall state that the maintenance of such Advance until such last day would be unlawful, such notice shall be effective on the date of receipt by the Account Party and the Agent. (g) Market Rate Disruptions. If, (i) the Agent determines that an adequate basis does not exist for the determination of the CD Rate for CD Rate Advances, or the Eurodollar Rate for Eurodollar Rate Advances or (ii) if the Majority Lenders shall notify the Agent that the Eurodollar Rate or CD Rate, as the case may be, will not adequately reflect the cost to such Majority Lenders of making, funding or maintaining their respective Eurodollar Rate Advances or CD Rate Advances, the right of the Account Party to select or receive or Convert into such Type of Advances shall be forthwith suspended until the Agent shall notify the Account Party and the Participating Banks that the circumstances causing such suspension no longer exist, and until such notification from the Agent, each request for or Conversion into such Type of Advance hereunder shall be deemed to be a request for or Conversion into Base Rate Advances. SECTION 4.04 Sharing of Payments, Etc. If any Participating Bank shall obtain any payment (whether voluntary, involuntary, through the exercise of any right of set-off, or otherwise, but excluding any proceeds received by assignments or sales of participations in accordance with Section 10.06 hereof to a Person that is not an Affiliate of the Account Party) on account of the Advances owing to it (other than pursuant to Section 4.03 hereof) in excess of its ratable share of payments on account of the Advances obtained by all the Participating Banks, such Participating Bank shall forthwith purchase from the other Participating Banks such participation in the portions of the Advances owing to them as shall be necessary to cause such purchasing Participating Bank to share the excess payment ratably with each of them; provided, however, that if all or any portion of such excess payment is thereafter recovered from such purchasing Participating Bank, such purchase from each Participating Bank shall be rescinded and such Participating Bank shall repay to the purchasing Participating Bank the purchase price to the extent of such recovery together with an amount equal to such Participating Bank's ratable share (according to the proportion of (i) the amount of such Participating Bank's required repayment to (ii) the total amount so recovered from the purchasing Participating Bank) of any interest or other amount paid or payable by the purchasing Participating Bank in respect of the total amount so recovered. The Account Party agrees that any Participating Bank so purchasing a participation from another Participating Bank pursuant to this Section 4.04 may, to the fullest extent permitted by law, exercise all its rights of payment (including the right of set-off) with respect to such participation as fully as if such Participating Bank were the direct creditor of the Account Party in the amount of such participation. Notwithstanding the foregoing, if any Participating Bank shall obtain any such excess payment involuntarily, such Participating Bank may, in lieu of purchasing participation from the other Participating Banks in accordance with this Section 4.04, on the date of receipt of such excess payment, return such excess payment to the Agent for distribution in accordance with Section 4.01(a) hereof. SECTION 4.05 Taxes. (a) All payments by the Account Party hereunder shall be made in accordance with Section 4.01, free and clear of and without deduction for all present or future taxes, levies, imposts, deductions, charges or withholdings, and all liabilities with respect thereto, excluding, in the case of each Participating Bank and the Issuing Bank, taxes imposed on its overall net income, and franchise taxes imposed on it, by the jurisdiction under the laws of which such Participating Bank or the Issuing Bank (as the case may be) is organized or any political subdivision thereof and, in the case of each Participating Bank, taxes imposed on its overall net income, and franchise taxes imposed on it, by the jurisdiction of such Participating Bank's Applicable Lending Office or any political subdivision thereof (all such non-excluded taxes, levies, imposts, deductions, charges, withholdings and liabilities being hereinafter referred to as "Taxes"). If the Account Party shall be required by law to deduct any Taxes from or in respect of any sum payable hereunder to any Participating Bank or the Issuing Bank, (i) the sum payable shall be increased as may be necessary so that after making all required deductions (including deductions applicable to additional sums payable under this Section 4.05) such Participating Bank or the Issuing Bank (as the case may be) receives an amount equal to the sum it would have received had no such deductions been made, (ii) the Account Party shall make such deductions and (iii) the Account Party shall pay the full amount deducted to the relevant taxation authority or other authority in accordance with applicable law. (b) In addition, the Account Party agrees to pay any present or future stamp or documentary taxes or any other excise or property taxes, charges or similar levies that arise from any payment made hereunder or from the execution, delivery or registration of, or otherwise with respect to, this Agreement (hereinafter referred to as "Other Taxes"). (c) The Account Party will indemnify each Participating Bank and the Issuing Bank for the full amount of Taxes and Other Taxes (including, without limitation, any Taxes and any Other Taxes imposed by any jurisdiction on amounts payable under this Section 4.05) paid by such Participating Bank or the Issuing Bank (as the case may be) and any liability (including penalties, interest and expenses) arising therefrom or with respect thereto, whether or not such Taxes or Other Taxes were correctly or legally asserted. This indemnification shall be made within 30 days from the date such Participating Bank or the Issuing Bank (as the case may be) makes written demand therefor. If any Taxes or Other Taxes for which a Participating Bank or the Issuing Bank has received payments from the Account Party hereunder shall be finally determined to have been incorrectly or illegally asserted and are refunded to such Participating Bank, such Participating Bank shall promptly forward to the Account Party any such refunded amount. The Account Party's, the Issuing Bank's and each Participating Bank's obligations under this Section 4.05 shall survive the payment in full of the Advances. (d) Within 30 days after the date of any payment of Taxes, the Account Party will furnish to the Issuing Bank, at its address referred to in Section 10.02 hereof, the original or a certified copy of a receipt evidencing payment thereof. (e) Each Participating Bank not incorporated in the United States or a jurisdiction within the United States shall, on or prior to the date it becomes a Participating Bank hereunder, deliver to the Account Party and the Issuing Bank such certificates, documents or other evidence, as required by the Internal Revenue Code of 1986, as amended from time to time (the "Code"), or treasury regulations issued pursuant thereto, including Internal Revenue Service Form 4224 and any other certificate or statement of exemption required by Treasury Regulation Section 1.1441-1(a) or Section 1.1441-6(c) or any subsequent version thereof, properly completed and duly executed by such Participating Bank establishing that it is (i) not subject to withholding under the Code or (ii) totally exempt from United States of America tax under a provision of an applicable tax treaty. Each Participating Bank shall promptly notify the Account Party and the Issuing Bank of any change in its Applicable Lending Office and shall deliver to the Account Party and the Issuing Bank together with such notice such certificates, documents or other evidence referred to in the immediately preceding sentence. Unless the Account Party and the Issuing Bank have received forms or other documents satisfactory to them indicating that payments hereunder are not subject to United States of America withholding tax or are subject to such tax at a rate reduced by an applicable tax treaty, the Account Party or the Issuing Bank shall withhold taxes from such payments at the applicable statutory rate in the case of payments to or for any Participating Bank organized under the laws of a jurisdiction outside the United States of America. Each Participating Bank represents and warrants that each such form supplied by it to the Issuing Bank and the Account Party pursuant to this Section 4.05, and not superseded by another form supplied by it, is or will be, as the case may be, complete and accurate. (f) Any Participating Bank claiming any additional amounts payable pursuant to this Section 4.05 shall use reasonable efforts (consistent with legal and regulatory restrictions) to file any certificate or document requested by the Account Party or to change the jurisdiction of its Applicable Lending Office if the making of such a filing or change would avoid the need for or reduce the amount of any such additional amounts which may thereafter accrue and would not, in the sole determination of such Participating Bank, be otherwise disadvantageous to such Participating Bank. SECTION 4.06 Obligations Absolute. The obligations of the Account Party under this Agreement shall be unconditional and irrevocable, and shall be paid strictly in accordance with the terms of this Agreement (as the same may be amended from time to time) under all circumstances, including, without limitation, the following circumstances: (i) any lack of validity or enforceability of this Agreement or any of the Security Documents or Related Documents or any document or agreement delivered in connection therewith; (ii) any change in the time, manner or place of payment of, or in any other term of, all or any of the obligations of the Account Party in respect of the Letter of Credit or any other amendment or waiver of or any consent to departure from all or any of the Loan Documents or the Related Documents or any document or agreement delivered in connection therewith; (iii) the existence of any claim, set-off, defense or other right which the Account Party may have at any time against the Paying Agent, the Trustee or any other beneficiary, or any transferee, of the Letter of Credit (or any persons or entities for whom the Paying Agent, the Trustee, any such beneficiary or any such transferee may be acting), the Agent, the Issuing Bank, or any other person or entity, whether in connection with this Agreement, the transactions contemplated in any of the Loan Documents or the Related Documents, or any unrelated transaction; (iv) any statement or any other document presented under the Letter of Credit proving to be forged, fraudulent, invalid or insufficient in any respect or any statement therein being untrue or inaccurate in any respect, except to the extent that a court of competent jurisdiction shall determine that the Issuing Bank shall have engaged in gross negligence or willful misconduct with respect thereto; (v) payment by the Issuing Bank under the Letter of Credit against presentation of a draft or certificate which does not comply with the terms of the Letter of Credit, except to the extent that a court of competent jurisdiction shall determine that the Issuing Bank shall have engaged in gross negligence or willful misconduct with respect thereto; (vi) any exchange of, release of or non-perfection of any interest in any collateral, or any release or amendment or waiver of or consent to departure from any guarantee, for all or any of the obligations of the Account Party in respect of the Letter of Credit; or (vii) any other circumstance or happening whatsoever, whether or not similar to any of the foregoing. SECTION 4.07 Evidence of Indebtedness. The Issuing Bank and each Participating Bank shall maintain, in accordance with their usual practice, an account or accounts evidencing the indebtedness of the Account Party resulting from each drawing under the Letter of Credit (in the case of the Issuing Bank) and from each Advance (in the case of each Participating Bank) made from time to time hereunder and the amounts of principal and interest payable and paid from time to time hereunder. In any legal action or proceeding in respect of this Agreement, the entries made in such account or accounts shall, in the absence of manifest error, be conclusive evidence of the existence and amounts of the obligations of the Account Party therein recorded. ARTICLE V CONDITIONS PRECEDENT SECTION 5.01 Conditions Precedent to the Issuance of the Letter of Credit. The obligation of the Issuing Bank to issue the Letter of Credit and of each Participating Bank to make the Advances to be made by it is subject to the fulfillment of the conditions precedent that the Agent shall have received on or before the day of such issuance the following, each dated such day (except where specified otherwise below), in form and substance satisfactory to each Participating Bank (except where specified otherwise below) and in sufficient copies for each Participating Bank: (a) Agreements: (i) Counterparts of this Agreement, duly executed and delivered by the Account Party, the Agent, the Issuing Bank and each Participating Bank listed on the signature pages hereto. (ii) Counterparts of the Pledge Agreement, duly executed by the Account Party, the Agent and the Issuing Bank. (iii) Executed copies (or duplicate copies thereof certified as of the Closing Date by the Account Party in a manner satisfactory to the Agent to be a true copy) of the Indenture, duly executed by the parties thereto. (b) Corporate Matters: (i) A certificate of the Secretary of the Account Party certifying that attached thereto are (A) a true and correct listing of the documents comprising the Articles of Incorporation of the Account Party and a true and correct copy of the By-laws of the Account Party, in each case as in effect on the Closing Date and (B) true and correct copies of the resolutions of the Board of Directors of the Account Party approving, if and to the extent necessary, this Agreement, the other Loan Documents, the Related Documents to which it is a party and the other documents to be delivered by or on behalf of the Account Party hereunder and thereunder, and of all documents evidencing other necessary corporate action, if any, with respect to the execution, delivery and performance by or on behalf of the Account Party of this Agreement, the other Loan Documents and such Related Documents and certifying that such resolutions and other corporate actions, if any, are in full force and effect and have not been revoked, rescinded or modified. (ii) A certificate of the Secretary of the Account Party certifying the names and true signatures of the officers of the Account Party authorized to sign this Agreement, the other Loan Documents, the Related Documents to which it is a party and the other documents to be delivered hereunder and thereunder. (c) Governmental Approvals: (i) A certificate of a duly authorized officer of the Account Party certifying that attached thereto are true and correct copies of all Governmental Approvals referred to in clause (i) of the definition of "Governmental Approval" required to be obtained or made by the Company. (d) Financial, Accounting and Compliance Matters: (i) A certificate signed by the Treasurer or Assistant Treasurer of the Account Party, certifying as to the absence of any material adverse change in the financial condition, operations, properties or prospects of the Account Party since December 31, 1991. (ii) A certificate signed by the Chief Financial Officer, Treasurer or Assistant Treasurer of NU, certifying as to the absence of any material adverse change in the financial condition, operations, properties or prospects of NU since December 31, 1991. (iii) A certificate of a duly authorized officer of the Account Party to the effect that: (A) the representations and warranties contained in Section 6.01 are correct in all material respects on and as of the Closing Date before and after giving effect to the issuance of the Letter of Credit; and (B) no event has occurred and is continuing which constitutes an Event of Default or Unmatured Default, or would result from the issuance of the Letter of Credit. (e) Relating to the Issuance of the Bonds: (i) An executed copy (or a duplicate copy thereof certified by the Account Party in a manner satisfactory to the Agent to be a true copy) of the Remarketing Agreement, duly executed by the Remarketing Agent and the Account Party. (ii) An executed copy (or a duplicate copy thereof certified by the Account Party in a manner satisfactory to the Agent to be a true copy) of the Purchase Contract, duly executed by Goldman, Sachs & Co., the Issuer and the Account Party. (iii) A letter from Palmer & Dodge, counsel to the Issuer, addressed to the Agent, the Issuing Bank and the Participating Banks and stating therein that the Agent, the Issuing Bank and the Participating Banks may rely on the opinion of such firm in the form of Exhibit H to the Purchase Contract and delivered pursuant to Section 14(i)(2)(G) of the Purchase Contract, together with copies of such opinion. (iv) A letter from Palmer & Dodge, Bond Counsel, addressed to the Agent, the Issuing Bank and the Participating Banks and stating therein that the Agent, the Issuing Bank and the Participating Banks may rely on the opinion of such firm in the form of Appendix C to the Purchase Contract and delivered pursuant to Section 14(i)(2)(H) of the Purchase Contract, together with a copy of such opinion. (v) Copies of the Preliminary Official Statement and Official Statement used in connection with the offering and remarketing of the Bonds, and any amendments, supplements or "stickers" thereto. (vi) Copies of the Issuer Resolution, and, to the extent not otherwise referenced in this Section 5.01(e), of all other agreements, documents, certificates and opinions delivered in connection with the issuance of the Bonds. (f) Opinions of Counsel: Favorable opinions of: (i) Day, Berry & Howard, counsel to the Account Party, in substantially the form of Exhibit 5.01A and as to such other matters as the Majority Lenders, through the Agent, may reasonably request; and (ii) King & Spalding, special New York counsel to the Agent and the Issuing Bank, in substantially the form of Exhibit 5.01B. (g) Miscellaneous: (i) Letters from S&P and Moody's to the effect that the Bonds have been rated A-1+ and VMIG-1, respectively, such letters to be in form and substance satisfactory to the Issuing Bank. (ii) Such other approvals, opinions and documents as the Majority Lenders, through the Issuing Bank, may reasonably request as to the legality, validity, binding effect or enforceability of the Loan Documents or the financial condition, properties, operations or prospects of the Account Party. SECTION 5.02 Additional Conditions Precedent to the Issuance of the Letter of Credit. The obligation of the Issuing Bank to issue the Letter of Credit and of each Participating Bank to make the Advances to be made by it shall be subject to the further conditions precedent that, on the date of the issuance of the Letter of Credit: (a) the representations and warranties contained in Section 6.01 shall be correct in all material respects on and as of the Closing Date before and after giving effect to the issuance of the Letter of Credit; (b) no event shall have occurred and be continuing which constitutes an Event of Default or Unmatured Default, or would result from the issuance of the Letter of Credit; and (c) The Account Party shall have paid all fees under or referenced in Section 2.03 hereof, to the extent then due and payable. SECTION 5.03 Conditions Precedent to Initial Advances and Conversions of Advances. The obligation of each Participating Bank to make any Initial Advance or to Convert any Term Advance shall be subject to the conditions precedent that, on the date of such Initial Advance or Conversion, the following statements shall be true: (a) the representations and warranties contained in Section 6.01 of this Agreement (other than the last sentence of subsection (f) and clause (ii) of subsection (g) thereof) are true and correct on and as of the date of such Initial Advance or Conversion, before and after giving effect to such Initial Advance or Conversion and to the application of the proceeds (if any) therefrom, as though made on and as of such date; and (b) no event has occurred and is continuing which constitutes an Event of Default. Unless the Account Party shall have previously advised the Agent in writing that one or more of the statements contained in subsections (a) and (b) of this Section 5.03 is no longer true, the Account Party shall be deemed to have represented and warranted, on and as of the date of any Initial Advance or Conversion, that the above statements are true. SECTION 5.04 Conditions Precedent to Term Advances. The obligation of each Participating Bank to make any Term Advance shall be subject to the conditions precedent that, on the date of such Term Advance the following statements shall be true: (a) the representations and warranties contained in Section 6.01 of this Agreement (including the last sentence of subsection (f) and clause (ii) of subsection (g) thereof) are true and correct on and as of the date of such Term Advance, before and after giving effect to such Term Advance and to the application of the proceeds therefrom, as though made on and as of such date; and (b) no event has occurred and is continuing which constitutes an Event of Default or an Unmatured Default. Unless the Account Party shall have previously advised the Agent in writing that one or more of the statements contained in subsections (a) and (b) of this Section 5.04 is no longer true, the Account Party shall be deemed to have represented and warranted, on and as of the date of any Term Advance, that the above statements are true. SECTION 5.05 Reliance on Certificates. The Agent, the Issuing Bank and the Participating Banks shall be entitled to rely conclusively upon the certificates delivered from time to time by officers of the Account Party, NU and the other parties to the Loan Documents and Related Documents as to the names, incumbency, authority and signatures of the respective persons named therein until such time as the Agent may receive a replacement certificate, in form acceptable to the Agent, from an officer of such Person identified to the Agent as having authority to deliver such certificate, setting forth the names and true signatures of the officers and other representatives of such Person thereafter authorized to act on behalf of such Person. ARTICLE VI REPRESENTATIONS AND WARRANTIES SECTION 6.01 Representations and Warranties of the Account Party. The Account Party represents and warrants as follows: (a) Each of the Account Party and its Principal Subsidiaries is a corporation duly organized, validly existing and in good standing under the laws of the jurisdiction of its organization, has the requisite corporate power and authority to own its property and assets and to carry on its business as now conducted and is qualified to do business in every jurisdiction where, because of the nature of its business or property, such qualification is required, except where the failure so to qualify would not have a material adverse effect on the financial condition, properties, prospects or operations of the Account Party or of the Account Party and its Principal Subsidiaries taken as a whole. The Account Party has the corporate power to execute, deliver and perform its obligations under this Agreement, each other Loan Document and each Related Document to which it will be a party. (b) The execution, delivery and performance by the Account Party of each Loan Document and Related Document to which it is a party are within the Account Party's corporate powers, have been duly authorized by all necessary corporate action, and do not and will not contravene (i) the Account Party's charter or by-laws or any law or legal restriction or (ii) any contractual restriction binding on or affecting the Account Party or its properties or any of its Principal Subsidiaries or its properties. (b) Each of the Account Party and its Principal Subsidiaries is not in violation of any law, or in default with respect to any judgment, writ, injunction, decree, rule or regulation of any court or governmental agency or instrumentality, where such violation or default would have a material adverse effect on the financial condition, properties, prospects or operations of the Account Party or of the Account Party and its Principal Subsidiaries taken as a whole. (c) All Governmental Approvals referred to in clause (i) in the definition of "Governmental Approvals" have been duly obtained or made, and all applicable periods of time for review, rehearing or appeal with respect thereto have expired, except as described below. If the period for appeal of the order of the Securities and Exchange Commission approving the transactions contemplated hereby has not expired, the filing of an appeal of such order will not affect the validity of said transactions, unless such order has been otherwise stayed or any of the parties hereto has actual knowledge that any of such transactions constitutes a violation of the Public Utility Holding Company Act of 1935 or any rule or regulation thereunder. No such stay exists and the Account Party has no reason to believe that any of such transactions constitutes any such violation. If the period for appeal of the decision of the Connecticut Department of Public Utility Control (the "CDPUC") approving the transactions contemplated hereby has not expired, the filing of an appeal of such decision will not affect the validity of said transactions, unless operation of such decision has been stayed or suspended by the CDPUC or a reviewing court prior to the consummation of such transactions. No such stay or suspension exists. No representation or warranty is made concerning the applicable periods of time for review, rehearing or appeal with respect to Governmental Approvals of the Issuer or the Governor and Executive Council of the State of New Hampshire in connection with the issuance of the Bonds. The Account Party and each of its Principal Subsidiaries have obtained or made all Governmental Approvals referred to in clause (ii) of the definition of "Governmental Approvals", except (i) those which are not yet required but which are obtainable in the ordinary course of business as and when required, (ii) those the absence of which would not materially adversely affect the financial condition, properties, prospects or operations of the Account Party or any Principal Subsidiary and (iii) those which the Account Party is diligently attempting in good faith to obtain, renew or extend, or the requirement for which the Account Party is contesting in good faith by appropriate proceedings or by other appropriate means; in each case described in the foregoing clause (iii), such attempt or contest, and any delay resulting therefrom, is not reasonably expected to have a material adverse effect on the financial condition, properties, prospects or operations of the Account Party or any Principal Subsidiary or to magnify to any significant degree any such material adverse effect that would reasonably be expected to result from the absence of such Governmental Approval. (e) This Agreement, each other Loan Document and each Related Document to which the Account Party is a party have been duly executed and delivered by or on behalf of the Account Party and are legal, valid and binding obligations of the Account Party enforceable against the Account Party in accordance with their respective terms; subject to the qualifications, however, that the enforcement of the rights and remedies herein and therein is subject to bankruptcy and other similar laws of general application affecting rights and remedies of creditors and the application of general principles of equity (regardless of whether considered in a proceeding in equity or at law) and that indemnification against violations of securities and similar laws may be subject to matters of public policy. (f) (i) The audited balance sheet of the Account Party as at December 31, 1991, and the audited statements of income and cash flows of the Account Party for the fiscal year then ended as set forth in the Account Party's Annual Report on Form 10-K for such fiscal year and (ii) the unaudited balance sheet of the Account Party as at September 30, 1992 and the unaudited statements of income and cash flows of the Account Party for the nine-month period then ended as set forth in the Account Party's Quarterly Report on Form 10-Q for the period then ended, fairly present in all material respects the financial condition and results of operations of the Account Party at and for the respective periods ended on such dates, and have been prepared in accordance with generally accepted accounting principles consistently applied. Since June 30, 1992, there has been no material adverse change in the financial condition, operations, properties or prospects of the Account Party and its Subsidiaries, if any, taken as a whole. (g) There is no pending or known threatened action or proceeding (including, without limitation, any action or proceeding relating to any environmental protection laws or regulations) affecting the Account Party or its properties, or any of its Principal Subsidiaries or its properties, before any court, governmental agency or arbitrator (i) which affects or purports to affect the legality, validity or enforceability of the Loan Documents or the Related Documents or any of them or (ii) as to which there is a reasonable possibility of an adverse determination and which, if adversely determined, would materially adversely affect the financial condition, properties, prospects or operations of the Account Party and its Principal Subsidiaries taken as a whole; except, (A) for purposes of clause (i) only, such as is described under "Litigation" in the Official Statement used in connection with the offering and remarketing of the Bonds and (B) for purposes of clause (ii) only, such as is described in the Account Party's Annual Report on Form 10-K for the fiscal year ended December 31, 1991, in the Account Party's Quarterly Reports on Form 10-Q for the periods ended March 31, June 30 or September 30, 1992, or in the Account party's Current Report on Form 8-K, dated January 29, 1992 or in Schedule II hereto. (h) No ERISA Plan Termination Event has occurred nor is reasonably expected to occur with respect to any ERISA Plan which would materially adversely affect the financial condition, properties, prospects or operations of the Account Party and its Subsidiaries taken as a whole, except as disclosed to and consented to in writing by the Majority Lenders. Since the date of the most recent Schedule B (Actuarial Information) to the annual report of each such ERISA Plan (Form 5500 Series), there has been no material adverse change in the funding status of the ERISA Plans referred to therein, and no "prohibited transaction" has occurred with respect thereto that, singly or in the aggregate with all other "prohibited transactions" and after giving effect to all likely consequences thereof, would be reasonably expected to have a material adverse effect on the financial condition, properties, prospects or operations of the Account Party and its Subsidiaries taken as a whole. Neither the Account Party nor any of its ERISA Affiliates has incurred nor reasonably expects to incur any material withdrawal liability under ERISA to any ERISA Multiemployer Plan, except as disclosed to and consented to in writing by the Majority Lenders. (i) The Account Party or one of its Principal Subsidiaries has good and marketable title (or, in the case of personal property, valid title) or valid leasehold interests in the electric generating plants of which it is named as "owner" in Item 2 of the Account Party's Annual Report on Form 10-K for the fiscal year ended December 31, 1991 under the caption "System Generating Plants", except for minor defects in title that do not interfere with the ability of the Account Party or any of its Principal Subsidiaries to conduct its business as now conducted. All such assets and properties are free and clear of any Lien, other than Liens permitted under Section 7.02(a) hereof. (j) All outstanding shares of capital stock having ordinary voting power for the election of directors of the Account Party have been validly issued, are fully paid and nonassessable and are owned beneficially by NU, free and clear of any Lien. NU is a "holding company" (as defined in the Public Utility Holding Company Act of 1935, as amended). (k) The Account Party and each of its Principal Subsidiaries has filed all tax returns (Federal, state and local) required to be filed and paid taxes shown thereon to be due, including interest and penalties, or, to the extent the Account Party or any of its Principal Subsidiaries is contesting in good faith an assertion of liability based on such returns, has provided adequate reserves in accordance with generally accepted accounting principles for payment thereof. (l) No exhibit, schedule, report or other written information provided by or on behalf of the Account Party or its agents to the Agent, the Issuing Bank or the Participating Banks in connection with the negotiation, execution and closing of this Agreement, the other Loan Documents or the Related Documents knowingly contained when made any material misstatement of fact or knowingly omitted to state any material fact necessary to make the statements contained therein not misleading in light of the circumstances under which they were made. (m) No proceeds of any Advance will be used in violation of, or in any manner that would result in a violation by any party hereto of, Regulations G, T, U or X promulgated by the Board of Governors of the Federal Reserve System or any successor regulations. The Account Party (A) is not an "investment company" within the meaning ascribed to that term in the Investment Company Act of 1940 and (B) is not engaged in the business of extending credit for the purpose of buying or carrying margin stock. ARTICLE VII COVENANTS OF THE ACCOUNT PARTY SECTION 7.01 Affirmative Covenants. So long as any amounts shall remain available to be drawn under the Letter of Credit or any Advance or other amounts shall remain unpaid hereunder or any Participating Bank shall have any Commitment, the Account Party will, unless the Majority Lenders shall otherwise consent in writing: (a) Use of Proceeds. Apply all proceeds of each Advance solely as specified in Section 3.02 and Section 6.01(m) hereof. (b) Payment of Taxes, Etc. Pay and discharge before the same shall become delinquent, and cause each of its Principal Subsidiaries to pay and discharge before the same shall become delinquent, all taxes, assessments and governmental charges, royalties or levies imposed upon it or upon its property except to the extent the Account Party or any of its Principal Subsidiaries is contesting the same in good faith by appropriate proceedings and has set aside adequate reserves in accordance with generally accepted accounting principles for the payment thereof. (c) Maintenance of Insurance. Maintain, or cause to be maintained, insurance (including appropriate plans of self-insurance) covering the Account Party, its Principal Subsidiaries and their respective properties, in effect at all times in such amounts and covering such risks as may be required by law and in addition as is usually carried by companies engaged in similar businesses and owning similar properties. (d) Preservation of Existence, Etc. Subject at all times to Section 7.02(b) hereof, preserve and maintain, and cause each of its Principal Subsidiaries to preserve and maintain, its existence, corporate or otherwise, material rights (statutory and otherwise) and franchises except for such rights and franchises which do not materially adversely affect the financial condition, properties, prospects or operations of the Account Party or any of its Principal Subsidiaries. (e) Compliance with Laws, Etc. Comply, and cause each of its Principal Subsidiaries to comply, in all material respects with the requirements of all applicable laws, rules, regulations and orders of any governmental authority, including, without limitation, any such laws, rules, regulations and orders issued by the Securities and Exchange Commission or relating to zoning, environmental protection, use and disposal of Hazardous Substances, land use, construction and building restrictions, ERISA and employee safety and health matters relating to business operations, except to the extent (i) that the Account Party or any of its Principal Subsidiaries is contesting the same in good faith by appropriate proceedings or (ii) that any such non-compliance, and the enforcement or correction thereof, would not materially adversely affect the financial condition, properties, prospects or operations of the Account Party or any of its Principal Subsidiaries. (f) Inspection Rights. At any time and from time to time upon reasonable notice, permit the Issuing Bank and its agents and representatives to examine the records and books of account of, and the properties of, the Account Party and any of its Principal Subsidiaries. (g) Keeping of Books. Keep proper records and books of account, in which full and correct entries shall be made of all financial transactions of the Account Party and its Principal Subsidiaries and the assets and business of the Account Party and its Principal Subsidiaries, in accordance with generally accepted accounting practices consistently applied. (h) Conduct of Business. Conduct its primary business, and cause each of its Principal Subsidiaries to conduct its primary business, in substantially the same manner and in substantially the same fields as such business is conducted on the Closing Date. (i) Maintenance of Properties, Etc. (i) As to properties of the type described in Section 6.01(i) hereof, subject at all times to Section 7.02(b) hereof, maintain, and cause its Principal Subsidiaries to maintain, title of the quality described therein; and (ii) preserve, maintain, develop, and operate, and cause its Principal Subsidiaries to preserve, maintain, develop and operate, in substantial conformity with all laws, material contractual obligations and prudent practices prevailing in the industry, all of its properties which are used or useful in the conduct of its or its Principal Subsidiaries' respective businesses in good working order and condition, ordinary wear and tear excepted, except to the extent such non-conformity would not materially adversely affect the financial condition, properties, prospects or operations of the Account Party or any of its Principal Subsidiaries; provided, however, that the Account Party or any Principal Subsidiary will not be prevented from discontinuing the operation and maintenance of any such properties if such discontinuance is, in the judgment of the Account Party or such Principal Subsidiary, desirable in the operation or maintenance of its business and would not materially adversely affect the financial condition, properties, prospects or operations of the Account Party or such Principal Subsidiary. (j) Governmental Approvals. Duly obtain, and cause each of its Principal Subsidiaries to duly obtain, on or prior to such date as the same may become legally required, and thereafter maintain in effect at all times, all Governmental Approvals on its or such Principal Subsidiary's part to be obtained, except with respect to those Governmental Approvals referred to in clause (ii) of the definition of "Governmental Approvals", (i) those the absence of which would not materially adversely affect the financial condition, properties, prospects or operations of the Account Party or any Principal Subsidiary and (ii) those which the Account Party is diligently attempting in good faith to obtain, renew or extend, or the requirement for which the Account Party is contesting in good faith by appropriate proceedings or by other appropriate means; provided, however, that the exception afforded by clause (ii), above, shall be available only if and for so long as such attempt or contest, and any delay resulting therefrom, does not have a material adverse effect on the financial condition, properties, prospects or operations of the Account Party or any Principal Subsidiary and does not magnify to any significant degree any such material adverse effect that would reasonably be expected to result from the absence of such Governmental Approval. (k) Consolidated Common Equity to Consolidated Capitalization Ratio. Maintain at all times a ratio of Consolidated Common Equity to Consolidated Capitalization of not less than 0.30:1.00. (l) Further Assurances. Promptly execute and deliver all further instruments and documents, and take all further action, that may be necessary or that any Participating Bank through the Issuing Bank may reasonably request in order to fully give effect to the interests and properties purported to be covered by the Security Documents. (m) Related Documents. Perform and comply in all material respects with each of the provisions of each Related Document to which it is a party. SECTION 7.02 Negative Covenants. So long as any amount shall remain available to be drawn under the Letter of Credit or any Advance or other amounts shall remain unpaid hereunder or any Participating Bank shall have any Commitment, the Account Party will not, without the written consent of the Majority Lenders: (a) Liens, Etc. Create, incur, assume or suffer to exist any lien, security interest, or other charge or encumbrance (including the lien or retained security title of a conditional vendor) of any kind, or any other type of preferential arrangement the intent or effect of which is to assure a creditor against loss or to prefer one creditor over another creditor upon or with respect to any of its properties or assets (any of the foregoing being referred to herein as a "Lien"), excluding, however, from the operation of the foregoing restrictions the Liens created or perfected under or in connection with the Pledge Agreement, and the following, whether now existing or hereafter created or perfected: (i) Liens created by (A) the Indenture of Mortgage and Deed of Trust dated as of May 1, 1921, from the Account Party to Bankers Trust Company, as Trustee, as amended and supplemented (the "CL&P Indenture"), or (B) the First Mortgage Indenture and Deed of Trust dated as of January 1, 1958, from the Hartford Electric Light Company ("HELCO") to the First National Bank of Boston, as Successor Trustee, as amended and supplemented (the "HELCO Indenture"); (ii) Liens on the Account Party's interest in the Millstone Unit No. 1, Millstone Unit No. 2 or Millstone Unit No. 3 nuclear generating units in Waterford, Connecticut, or nuclear fuel for any or all nuclear units in which the Account Party has an interest (including, without limitation, Millstone Unit No. 1, Millstone Unit No. 2 and Millstone Unit No. 3); (iii) "Permitted Liens" or "Permitted Encumbrances" under the CL&P Indenture or the HELCO Indenture; (iv) any Lien on assets of any of its Subsidiaries created or assumed to secure Debt owing by any of its Subsidiaries to the Account Party or to any wholly-owned Subsidiary of the Account Party; (v) any purchase money Lien or construction mortgage on assets hereafter acquired or constructed by the Account Party or any of its Subsidiaries and any Lien on any assets existing at the time of acquisition thereof by the Account Party or any of its Subsidiaries, or created within 180 days from the date of completion of such acquisition or construction; provided that such Lien shall at all times be confined solely to the assets so acquired or constructed and any additions thereto; (vi) any existing Liens on assets now owned by the Account Party or any of its Subsidiaries; Liens on assets or stock of any class of, or any partnership or joint venture interest in, any of its Subsidiaries existing at the time it becomes a Subsidiary of the Account Party, and liens existing on assets of a corporation or other going concern when it is merged into or with the Account Party or a Subsidiary of the Account Party, or when substantially all of its assets are acquired by the Account Party or a Subsidiary of the Account Party; provided that such Liens shall at all times be confined solely to such assets, or if such assets constitute a utility system, additions to or substitutions for such assets; (vii) Liens resulting from legal proceedings being contested in good faith by appropriate legal or administrative proceedings by the Account Party or any of its Subsidiaries, and as to which the Account Party or any of its Subsidiaries, as the case may be, to the extent required by generally accepted accounting principles applied on a consistent basis, shall have set aside on its books adequate reserves; (viii) Liens created in favor of the other contracting party in connection with advance or progress payments; (ix) any Liens in favor of any state of the United States or any political subdivision of any such state, or any agency of any such state or political subdivisions, or trustee acting on behalf of holders of obligations issued by any of the foregoing or any financial institutions lending to or purchasing obligations of any of the foregoing, which Lien is created or assumed for the purpose of financing all or part of the cost of acquiring or constructing the property subject thereto; (x) Liens resulting from conditional sale agreements, capital leases or other title retention agreements; (xi) Liens on property of the Account Party or any of its Subsidiaries related to the financing of pollution control facilities; (xii) Liens on accounts receivable and power contracts resulting from financing transactions; (xiii) any other Liens incurred in the ordinary course of business otherwise than to secure Debt; and (xiv) any extension, renewal or replacement of Liens permitted by clauses (i) through (vi) and (viii) through (xiii); provided, however, that the principal amount of Debt secured thereby shall not, at the time of such extension, renewal or replacement, exceed the principal amount of Debt so secured and that such extension, renewal or replacement shall be limited to all or a part of the property which secured the Lien so extended, renewed or replaced; (b) Mergers, and Sales of Assets, Etc. Merge with or into or consolidate with or into, any person, or permit any of its Subsidiaries to be a party to, any merger or consolidation, or purchase or otherwise acquire all or substantially all of the assets or stock of any class of, or any partnership or joint venture interest in, any other person or entity, or sell, transfer, convey or lease all or any substantial part of its assets (other than sales, transfers or conveyances of receivables and power contracts), except for, and then only after receipt of all necessary corporate and governmental or regulatory approvals and provided, that, before and after giving effect to any such merger, consolidation, purchase, acquisition, sale, transfer, conveyance or lease, no Event of Default or Unmatured Default shall have occurred and be continuing: (i) any such merger or consolidation, sale, transfer, conveyance, lease or assignment of or by any wholly-owned Subsidiary of the Account Party into the Account Party or into, with or to any other wholly-owned Subsidiary of the Account Party and any such purchase or other acquisition by the Account Party or any wholly-owned Subsidiary of the Account Party of the assets or stock of any wholly-owned Subsidiary of the Account Party; (ii) any such sale of assets (other than stock) which comprise all or any part of its interest in a nuclear power generating plant (whether completed or under construction); (iii) any such merger or consolidation of the Account Party with or into another wholly-owned Subsidiary of NU and/or a Regulatory Transaction Entity and/or an entity owning a cogeneration or independent power project, pursuant to "step-in" or similar rights granted pursuant to a pre-existing power purchase contract, if (but only if): (A) the successor or surviving corporation, if not the Account Party, shall have assumed or succeeded to all of the liabilities of the Account Party (including the liabilities of the Account Party under this Agreement), and (B) the Agent shall have received the favorable written opinion of counsel to the Account Party, in form and substance satisfactory to the Agent and the Majority Lenders, to the effect of the foregoing subclause (A); provided, however, in the event of a merger or consolidation with a Regulatory Transaction Entity, if the purchase price plus the amount of any liabilities assumed in connection with such merger or consolidation exceeds $100,000,000, the Account Party shall deliver to the Agent with sufficient copies for each Participating Bank 30 days prior to such merger or consolidation, a certificate of a duly authorized officer of the Account Party demonstrating projected compliance with the ratio set forth in Section 7.01(k) hereof for and as of each of the three consecutive fiscal quarters immediately succeeding such merger or consolidation and certifying that such projections were prepared in good faith and on reasonable assumptions; (iv) any purchase or acquisition of all or substantially all of the assets of or stock of any class of, or any partnership or joint venture interest in (and any assumption of the related liabilities) (A) an entity owning a cogeneration or independent power project, pursuant to "step-in" or similar rights granted pursuant to a pre-existing power purchase contract; (B) a Regulatory Transaction Entity; or (C) any other Person if the purchase price of such acquisition plus the amount of any liabilities assumed by the Account Party in connection therewith does not exceed $50,000,000 in the aggregate; provided, however, in the event of a purchase or acquisition of a Regulatory Transaction Entity, if the purchase price plus the amount of any liabilities assumed in connection with such purchase or acquisition exceeds in the aggregate $100,000,000, the Account Party shall deliver to the Agent with sufficient copies for each Participating Bank 30 days prior to such purchase or acquisition, a certificate of a duly authorized officer of the Account Party demonstrating projected compliance with the ratio set forth in Section 7.01(k) hereof for and as of each of the three consecutive fiscal quarters immediately succeeding such purchase or acquisition and certifying that such projections were prepared in good faith and on reasonable assumptions; or (v) any purchase or acquisition of a joint venture interest in a generating and/or transmission facility or in a mutual insurance company providing nuclear liability or nuclear property or replacement power insurance. (c) Compliance with ERISA. (i) Terminate, or permit any ERISA Affiliate to terminate, any ERISA Plan so as to result in any liability of the Account Party or any Principal Subsidiary to the PBGC in an amount greater than $1,000,000, or (ii) permit to exist any occurrence of any Reportable Event (as defined in Title IV of ERISA) which, alone or together with any other Reportable Event with respect to the same or another ERISA Plan, has a reasonable possibility of resulting in liability of the Account Party or any Subsidiary to the PBGC in an aggregate amount exceeding $1,000,000, or any other event or condition, which presents a material risk of such a termination by the PBGC of any ERISA Plan or has a reasonable possibility of resulting in a liability of the Account Party or any Subsidiary to the PBGC in an aggregate amount exceeding $1,000,000. SECTION 7.03 Reporting Obligations. So long as any amount shall remain available to be drawn under the Letter of Credit or any Advance or other amounts shall remain unpaid hereunder or any Participating Bank shall have any Commitment, the Account Party will, unless the Majority Lenders shall otherwise consent in writing, furnish to the Agent in sufficient copies for the Issuing Bank and each Participating Bank, the following: (i) as soon as possible and in any event within ten days after the occurrence of each Event of Default or Unmatured Default continuing on the date of such statement, a statement of the Chief Financial Officer, Treasurer or Assistant Treasurer of the Account Party setting forth details of such Event of Default or Unmatured Default and the action which the Account Party proposes to take with respect thereto; (ii) as soon as available and in any event within 50 days after the end of each of the first three quarters of each fiscal year of the Account Party, a copy of the Account Party's Quarterly Report on Form 10-Q, if any, submitted to the Securities and Exchange Commission with respect to such quarter, containing financial statements in reasonable detail and duly certified (subject to year-end audit adjustments) by the Chief Financial Officer, Treasurer, Assistant Treasurer or Comptroller of the Account Party as having been prepared in accordance with the system of management financial reports of the Account Party applied on a basis consistent with the financial statements referred to in Section 6.01(f) hereof and accompanied by a certificate of a duly authorized officer of the Account Party (X) stating that no Event of Default or Unmatured Default has occurred and is continuing or, if an Event of Default or Unmatured Default has occurred and is continuing, describing the nature thereof and the action which the Account Party proposes to take with respect thereto and (Y) demonstrating compliance with Section 7.01(k) hereof for and as of the end of such fiscal quarter, such demonstration to be in a schedule (in form satisfactory to the Agent) which sets forth the computations used in determining such compliance; (iii) as soon as available and in any event within 105 days after the end of each fiscal year of the Account Party, a copy of the Account Party's Annual Report on Form 10-K submitted to the Securities and Exchange Commission with respect to such year, containing financial statements certified by a nationally-recognized independent public accountant and to be accompanied by a certificate of the Chief Financial Officer, Treasurer, Assistant Treasurer or Comptroller of the Account Party (X) stating that no Event of Default or Unmatured Default has occurred and is continuing, or if an Event of Default or Unmatured Default has occurred and is continuing, describing the nature thereof and the action which the Account Party proposes to take with respect thereto and (Y) demonstrating compliance with Section 7.01(k) hereof for and as of the end of such fiscal year, such demonstration to be in a schedule (in form satisfactory to the Agent) which sets forth the computations used in determining such compliance; (iv) as soon as possible and in any event (A) within 30 days after the Chief Financial Officer, Treasurer or any Assistant Treasurer of the Account Party knows or has reason to know that any ERISA Plan Termination Event described in clause (i) of the definition of ERISA Plan Termination Event with respect to any ERISA Plan or ERISA Multiemployer Plan has occurred and (B) within 10 days after the Account Party knows or has reason to know that any other ERISA Plan Termination Event with respect to any ERISA Plan or ERISA Multiemployer Plan has occurred, a statement of the Chief Financial Officer, Treasurer or Assistant Treasurer of the Account Party describing such ERISA Plan Termination Event and the action, if any, which the Account Party proposes to take with respect thereto; (v) promptly after receipt thereof by the Account Party or any of its ERISA Affiliates from the PBGC, copies of each notice received by the Account Party or any such ERISA Affiliate of the PBGC's intention to terminate any ERISA Plan or ERISA Multiemployer Plan or to have a trustee appointed to administer any ERISA Plan or ERISA Multiemployer Plan; (vi) promptly after receipt thereof by the Account Party or any of its ERISA Affiliates from an ERISA Multiemployer Plan sponsor, a copy of each notice received by the Account Party or any of its ERISA Affiliates concerning the imposition or amount of withdrawal liability in an aggregate principal amount of at least $10,000,000 pursuant to Section 4202 of ERISA in respect of which the Account Party may be liable; (vii) promptly after the Account Party or any Subsidiary becomes aware of the commencement thereof, notice of all actions, suits, proceedings or other events of the type described in Section 6.01(g) hereof; (viii) promptly after the filing thereof, copies of each prospectus (excluding any prospectus contained in any Form S-8) and Current Report on Form 8-K, if any, which the Account Party or any Principal Subsidiary files with the Securities and Exchange Commission or any governmental authority which may be substituted therefor; (ix) promptly after receipt thereof, any assertion of the character described in Section 8.01(h) hereof and the action the Account Party proposes to take with respect thereto; and (x) promptly after requested, such other information respecting the financial condition, operations, properties, prospects or otherwise, of the Account Party or its Subsidiaries as the Agent on behalf of the Majority Lenders may from time to time reasonably request in writing. ARTICLE VIII DEFAULTS SECTION 8.01 Events of Default. The following events shall each constitute an "Event of Default" if the same shall occur and be continuing after the grace period and notice requirement (if any) applicable thereto: (a) The Account Party shall fail to pay any interest on any Advance or pursuant to Section 4.02 hereof within two days after the same becomes due; the Account Party shall fail to reimburse the Issuing Bank for any Interest Drawing (as defined in the Letter of Credit) within two days after such reimbursement becomes due; or the Account Party shall fail to make any other payment required to be made pursuant to Article II or Article III hereof when due; or (b) Any representation or warranty made by the Account Party (or any of its officers or agents) in this Agreement, the Pledge Agreement or the Purchase Contract, or in any certificate or other writing delivered pursuant to this Agreement or the Purchase Contract, shall prove to have been incorrect in any material respect when made or deemed made; or (c) The Account Party shall fail to perform or observe any term or covenant on its part to be performed or observed contained in Sections 7.01(d) or (k), Section 7.02(b) or Section 7.03(i) hereof; or (d) The Account Party shall fail to perform or observe any other term or covenant on its part to be performed or observed contained in this Agreement or the Pledge Agreement and any such failure shall remain unremedied, after the earlier of written notice having been given to the Account Party by the Agent, the Issuing Bank or any Participating Bank, and actual knowledge thereof by the Account Party, for a period of 30 days; or (e) The Account Party or any Principal Subsidiary shall fail to pay any of its Debt when due (including any interest or premium thereon but excluding Debt arising hereunder and excluding other Debt aggregating in no event more than $10,000,000 in principal amount at any one time) whether by scheduled maturity, required prepayment, acceleration, demand or otherwise, and such failure shall continue after the applicable grace period, if any, specified in any agreement or instrument relating to such Debt; or any other default under any agreement or instrument relating to any such Debt, or any other event, shall occur and shall continue after the applicable grace period, if any, specified in such agreement or instrument, if the effect of such default or event is to accelerate, or to permit the acceleration of, the maturity of such Debt; or any such Debt shall be declared to be due and payable, or required to be prepaid (other than by a regularly scheduled required prepayment or as a result of the Account Party's or such Principal Subsidiary's exercise of a prepayment option) prior to the stated maturity thereof; or (f) The Account Party or any Principal Subsidiary shall generally not pay its debts as such debts become due, or shall admit in writing its inability to pay its debts generally, or shall make an assignment for the benefit of creditors; or any proceeding shall be instituted by or against the Account Party or such Principal Subsidiary seeking to adjudicate it a bankrupt or insolvent, or seeking liquidation, winding up, reorganization, arrangement, adjustment, protection, relief, or composition of its debts under any law relating to bankruptcy, insolvency, or reorganization or relief of debtors, or seeking the entry of an order for relief or the appointment of a receiver, trustee, or other similar official for it or for any substantial part of its property and, in the case of a proceeding instituted against the Account Party or such Principal Subsidiary, either the Account Party or such Principal Subsidiary shall consent thereto or such proceeding shall remain undismissed or unstayed for a period of 90 days or any of the actions sought in such proceeding (including without limitation the entry of an order for relief against the Account Party or such Principal Subsidiary or the appointment of a receiver, trustee, custodian or other similar official for the Account Party or such Principal Subsidiary or any of its property) shall occur; or the Account Party or such Principal Subsidiary shall take any corporate or other action to authorize any of the actions set forth above in this subsection (f); or (g) Any judgment or order for the payment of money in excess of $10,000,000 shall be rendered against the Account Party or its properties, or any Principal Subsidiary or its properties, and either (i) enforcement proceedings shall have been commenced by any creditor upon such judgment or order and shall not have been stayed or (ii) there shall be any period of 30 consecutive days during which a stay of enforcement of such judgment or order, by reason of a pending appeal or otherwise, shall not be in effect; or (h) Any material provision of any Loan Document or any Related Document shall for any reason other than the express terms thereof or the exercise of any right or option expressly contained therein cease to be valid and binding on the Account Party, or shall be determined to be invalid or unenforceable by any court, governmental agency or authority having jurisdiction over the Account Party, or the Account Party shall deny that it has any further liability or obligation under this Agreement or any Related Document, or any party to a Related Document shall so assert in writing; provided, that in the case of any party other than the Account Party making such assertion in respect of any Related Document, such assertion shall not in and of itself constitute an Event of Default hereunder until (i) such asserting party shall cease to perform under and in compliance with such Related Document, (ii) the Account Party shall fail to diligently prosecute, by appropriate action or proceedings, a rescission of such assertion or a binding determination as to the merits thereof or (iii) such a binding determination shall have been made in favor of such asserting party's position; or (i) The Security Documents shall for any reason, except to the extent permitted by the terms thereof, fail or cease to create valid and perfected Liens (to the extent purported to be granted by such documents and subject to the exceptions permitted thereunder) in any of the Collateral (other than Liens in favor of the Trustee with respect to the interests of the Issuer under the Indenture), provided, that such failure or cessation relating to any non-material portion of such Collateral shall not constitute an Event of Default hereunder unless the same shall not have been corrected within 30 days after the Account Party becomes aware thereof; or (j) NU shall cease to own 100% of the issued and outstanding shares of the capital stock of the Account Party having ordinary voting power for the election of directors, free and clear of any Liens; or (k) An event of default (as defined therein) shall have occurred and be continuing under the Indenture. SECTION 8.02 Remedies Upon Events of Default. Upon the occurrence and during the continuance of any Event of Default, then, and in any such event, the Agent with the concurrence of the Issuing Bank may, and upon the direction of the Majority Lenders the Agent shall (i) if the Letter of Credit shall not have been issued, instruct the Issuing Bank to (whereupon the Issuing Bank shall) by notice to the Account Party declare its commitment to issue the Letter of Credit to be terminated, whereupon the same shall forthwith terminate, (ii) if the Letter of Credit shall have been issued, instruct the Issuing Bank to (whereupon the Issuing Bank shall) furnish to the Trustee and the Paying Agent written notice of such Event of Default in accordance with Section 6.01(a)(iv) of the Indenture and of the Issuing Bank's determination to terminate the Letter of Credit on the fifth business day (as defined in the Indenture) following the Trustee's and Paying Agent's receipt of such notice, (iii) if the Letter of Credit shall have been issued, instruct the Issuing Bank to (whereupon the Issuing Bank shall) furnish to the Trustee and the Paying Agent written notice that the Interest Component will not be reinstated in the amount of one or more Interest Drawings, all as provided in the Letter of Credit; (iv) declare the Advances and all other principal amounts outstanding hereunder, all interest thereon and all other amounts payable hereunder to be forthwith due and payable, whereupon the Advances and all other principal amounts outstanding hereunder, all such interest and all such other amounts shall become and be forthwith due and payable, without presentment, demand, protest or further notice of any kind, all of which are hereby expressly waived by the Account Party, and (v) instruct the Issuing Bank to (whereupon the Issuing Bank shall) exercise all the rights and remedies provided herein and under and in respect of the Security Documents; provided, however, that in the event of the occurrence of any Event of Default described in Section 8.01(f) with respect to the Account Party, (A) the commitment of the Issuing Bank to issue the Letter of Credit and the Commitments and the obligations of the Participating Banks to make Advances shall automatically be terminated, and (B) the Advances and all other principal amounts outstanding hereunder, all interest accrued and unpaid thereon and all other amounts payable hereunder shall automatically become due and payable, without presentment, demand, protest or any notice of any kind, all of which are hereby expressly waived by the Account Party. ARTICLE IX THE AGENT, THE PARTICIPATING BANKS AND THE ISSUING BANK SECTION 9.01 Authorization of Agent; Actions of Agent and Issuing Bank. The Issuing Bank and each Participating Bank hereby appoint and authorize the Agent to take such action as agent on their behalf and to exercise such powers under this Agreement as are delegated to the Agent by the terms hereof, together with such powers as are reasonably incidental thereto; provided, however, that neither the Agent nor the Issuing Bank shall be required to take any action which exposes the Agent or the Issuing Bank to personal liability or which is contrary to this Agreement or applicable law. As to any matters not expressly provided for by any Related Document (including, without limitation, enforcement or collection thereof), neither the Agent nor the Issuing Bank shall be required to exercise any discretion or take any action. The Agent agrees to deliver promptly (i) to the Issuing Bank and each Participating Bank copies of each notice delivered to it by the Account Party and (ii) to each Participating Bank copies of each notice delivered to it by the Issuing Bank, in each case pursuant to the terms of this Agreement. SECTION 9.02 Reliance, Etc. Neither the Agent, the Issuing Bank, nor any of their directors, officers, agents or employees shall be liable for any action taken or omitted to be taken by it or them under or in connection with this Agreement or any Related Document, except for its or their own gross negligence or willful misconduct as determined by a court of competent jurisdiction. Without limitation of the generality of the foregoing, each of the Agent and the Issuing Bank (i) may consult with legal counsel (including counsel for the Account Party), independent public accountants and other experts selected by it and shall not be liable for any action taken or omitted to be taken in good faith by it in accordance with the advice of such counsel, accountants or experts; (ii) makes no warranty or representation to any Participating Bank and shall not be responsible to any Participating Bank for any statements, warranties or representations made in or in connection with this Agreement or any Related Document; (iii) shall not have any duty to ascertain or to inquire as to the performance or observance of any of the terms, covenants or conditions of this Agreement or any Related Document on the part of the Account Party to be performed or observed, or to inspect any property (including the books and records) of the Account Party; (iv) shall not be responsible to any Participating Bank for the due execution, legality, validity, enforceability, genuineness, sufficiency or value of this Agreement or any Related Document or any other instrument or document furnished pursuant hereto and thereto; and (v) shall incur no liability under or in respect of this Agreement or any Related Document by acting upon any notice, consent, certificate or other instrument or writing (which may be by telegram, cable or telex), including, without limitation, any thereof from time to time purporting to be from the Trustee, believed by it to be genuine and signed or sent by the proper party or parties. SECTION 9.03 The Agent, the Issuing Bank and Affiliates. The Agent and the Issuing Bank shall have the same rights and powers under this Agreement as any other Participating Bank and may exercise (or omit from exercising) the same as though they were not the Agent and the Issuing Bank, respectively, and the term "Participating Bank" shall, unless otherwise expressly indicated, include CIBC in its individual capacity. The Agent, the Issuing Bank and their respective Affiliates may accept deposits from, lend money to, act as trustee under indentures of, and generally engage in any kind of business with, the Account Party, any of its subsidiaries and any Person who may do business with or own securities of the Account Party or any such subsidiary, all as if CIBC was not the Agent or the Issuing Bank, and without any duty to account therefor to the Participating Banks. SECTION 9.04 Participating Bank Credit Decision. Each of the Issuing Bank and each Participating Bank acknowledges that it has, independently and without reliance upon the Agent, the Issuing Bank or any other Participating Bank and based on the financial information referred to in Section 6.01(f) hereof and such other documents and information as it has deemed appropriate, made its own credit analysis and decision to enter into this Agreement. Each of the Issuing Bank and each Participating Bank also acknowledges that it will, independently and without reliance upon the Agent, the Issuing Bank or any other Participating Bank and based on such documents and information as it shall deem appropriate at the time, continue to make its own credit decisions in taking or not taking action under this Agreement. SECTION 9.05 Indemnification. The Participating Banks agree to indemnify the Agent and the Issuing Bank (to the extent not reimbursed by the Account Party), ratably according to their respective Participation Percentages, from and against any and all liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements of any kind or nature whatsoever which may be imposed on, incurred by, or asserted against the Agent or the Issuing Bank in any way relating to or arising out of this Agreement or any action taken or omitted by the Agent or the Issuing Bank under this Agreement, provided that no Participating Bank shall be liable for any portion of such liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements resulting from the Agent's or the Issuing Bank's gross negligence or willful misconduct. Without limitation of the foregoing, each Participating Bank agrees to reimburse the Agent and the Issuing Bank promptly upon demand for its ratable share of any out-of-pocket expenses (including counsel fees) incurred by the Agent and the Issuing Bank in connection with the preparation, execution, delivery, administration, modification, amendment, waiver or enforcement (whether through negotiations, legal proceedings or otherwise) of, or legal advice in respect of rights or responsibilities under, this Agreement to the extent that the Agent and the Issuing Bank are entitled to reimbursement for such expenses pursuant to Section 10.04 hereof but are not reimbursed for such expenses by the Account Party. SECTION 9.06 Successor Agent. The Agent may resign at any time by giving written notice thereof to the Issuing Bank, the Participating Banks and the Account Party, with any such resignation to become effective only upon the appointment of a successor Agent pursuant to this Section 9.06. Upon any such resignation, the Issuing Bank shall have the right to appoint a successor Agent, which shall be another commercial bank or trust company reasonably acceptable to the Account Party, organized or licensed under the laws of the United States, or of any State thereof. Upon the acceptance of any appointment as Agent hereunder by a successor Agent and the execution and delivery by the Account Party and the successor Agent of an agreement relating to the fees, if any, to be paid to the successor Agent in connection with its acting as Agent hereunder, such successor Agent shall thereupon succeed to and become vested with all the rights, powers, privileges and duties of the retiring Agent, and the retiring Agent shall be discharged from its duties and obligations under this Agreement. After any retiring Agent's resignation hereunder as Agent, the provisions of this Article IX shall inure to its benefit as to any actions taken or omitted to be taken by it while it was Agent under this Agreement. SECTION 9.07 Issuing Bank. (a) All notices received by the Issuing Bank pursuant to this Agreement or any Related Document (other than the Letter of Credit) shall be promptly delivered to the Agent for distribution to the Participating Banks. (b) The Issuing Bank shall not amend or waive any provision or consent to the amendment or waiver of any Related Document without the written consent of the Majority Lenders. (c) Upon receipt by the Issuing Bank from time to time of any amount pursuant to the terms of any Related Document (other than pursuant to the terms of this Agreement), the Issuing Bank shall promptly deliver to the Agent such amount. ARTICLE X MISCELLANEOUS SECTION 10.01 Amendments, Etc. No amendment or waiver of any provision of this Agreement or the Pledge Agreement, nor consent to any departure by the Account Party therefrom, shall in any event be effective unless the same shall be in writing and signed by the Majority Lenders, and then such waiver or consent shall be effective only in the specific instance and for the specific purpose for which given; provided, however, that no amendment, waiver or consent shall, unless in writing and signed by the Issuing Bank and all the Participating Banks, do any of the following: (a) waive, modify or eliminate any of the conditions specified in Article V, (b) increase the Commitments of the Participating Banks that may be maintained hereunder or subject the Participating Banks to any additional obligations, (c) reduce the principal of, or interest on, the Advances, any amount reimbursable on demand pursuant to Section 3.01, or any fees or other amounts payable hereunder, (d) postpone any date fixed for any payment of principal of, or interest on, the Advances, such reimbursable amounts or any fees or other amounts payable hereunder (other than fees payable to the Issuing Bank or the Agent pursuant to Section 2.03(b) hereof), (e) change the percentage of the Commitments or of the aggregate unpaid principal amount of the Advances, or the number of Participating Banks which shall be required for the Participating Banks or any of them to take any action hereunder, (f) amend this Agreement or the Pledge Agreement in a manner intended to prefer one or more Participating Banks over any other Participating Banks, (g) amend this Section 10.01, or (h) release any of the Collateral otherwise than in accordance with any provisions for such release contained in the Security Documents, or change any provision of any Security Document providing for the release of all or substantially all of the Collateral; and provided, further, that no amendment, waiver or consent shall, unless in writing and signed by the Issuing Bank or the Agent in addition to the Participating Banks required above to take such action, affect the rights or duties of the Issuing Bank or the Agent, as the case may be, under this Agreement or the Pledge Agreement. SECTION 10.02 Notices, Etc. All notices and other communications provided for hereunder and under the other Loan Documents shall be in writing (including telegraphic, telex, telecopy or cable communication) and mailed, telegraphed, telexed, telecopied, cabled or delivered: (i) if to the Account Party, to it in care of Northeast Utilities Service Company at 107 Selden Street, Berlin, Connecticut 06037 (telecopy: (203) 665-5457), Attention: Assistant Treasurer; (ii) if to the Issuing Bank or the Agent, to it at its address at Two Paces West, 2727 Paces Ferry Road, Suite 1200, Atlanta, Georgia 30339, Attention: Clare Coyne, (telephone: (404) 319-4836, telecopy: (404) 319- 4950), with a copy to: Utilities Group, 200 West Madison Street, Suite 2300, Chicago, Illinois 60606, (telephone: (312) 855-3212, telecopy: (312) 750-0927); (iii) if to any Participating Bank, to it at its address set forth on the signature pages hereof or in the Participation Assignment pursuant to which it became a Participating Bank; or as to each party other than any Participating Bank, at such other address as shall be designated by such party in a written notice to the other parties, and, as to any Participating Bank, at such other address as shall be designated by such Participating Bank in a written notice to the Account Party and the Agent. All such notices and communications shall, when mailed, telegraphed, telexed, telecopied or cabled, be effective five days after when deposited in the mails, or when delivered to the telegraph company, confirmed by telex answerback, telecopied or delivered to the cable company, respectively, except that notices and communications to the Agent or the Issuing Bank pursuant to Article II, III or IV shall not be effective until received by the Agent or the Issuing Bank, as the case may be. SECTION 10.03 No Waiver of Remedies. No failure on the part of any Participating Bank or the Issuing Bank to exercise, and no delay in exercising, any right hereunder or under any Loan Document shall operate as a waiver thereof; nor shall any single or partial exercise of any such right preclude any other or further exercise thereof or the exercise of any other right. The remedies herein provided are cumulative and not exclusive of any remedies provided by law. SECTION 10.04 Costs, Expenses and Indemnification. (a) The Account Party agrees to pay on demand all costs and expenses, if any (including, without limitation, reasonable counsel fees and expenses), of (i) the Agent and the Issuing Bank in connection with the preparation, negotiation, execution and delivery of the Loan Documents and the administration of the Loan Documents, the care and custody of any and all collateral, and any proposed modification, amendment, or consent relating thereto; and (ii) the Agent, the Issuing Bank and each Participating Bank in connection with the enforcement (whether through negotiations, legal proceedings or otherwise) of this Agreement or any other Loan Document. (b) The Account Party hereby agrees to indemnify and hold the Agent, the Issuing Bank and each Participating Bank and their respective officers, directors, employees, professional advisors and affiliates (each, an "Indemnified Person") harmless from and against any and all claims, damages, losses, liabilities, costs or expenses (including reasonable attorney's fees and expenses, whether or not such Indemnified Person is named as a party to any proceeding or investigation or is otherwise subjected to judicial or legal process arising from any such proceeding or investigation) which any of them may incur or which may be claimed against any of them by any person or entity (except to the extent such claims, damages, losses, liabilities, costs or expenses arise from the gross negligence or willful misconduct of the Indemnified Person): (i) by reason of or in connection with the execution, delivery or performance of any of the Loan Documents or the Related Documents or any transaction contemplated thereby, or the use by the Account Party of the proceeds of any Advance or the use by the Paying Agent or the Trustee of the proceeds of any drawing under the Letter of Credit; (ii) in connection with or resulting from the utilization, storage, disposal, treatment, generation, transportation, release or ownership of any Hazardous Substance (A) at, upon or under any property of the Account Party or any of its Affiliates or (B) by or on behalf of the Account Party or any of its Affiliates at any time and in any place; (iii) in connection with any documentary taxes, assessments or charges made by any governmental authority by reason of the execution and delivery of any of the Loan Documents; (iv) by reason of or in connection with the execution and delivery or transfer of, or payment or failure to make payment under, the Letter of Credit; provided, however, that the Account Party shall not be required to indemnify the Agent, the Issuing Bank or any Participating Bank pursuant to this Section for any claims, damages, losses, liabilities, costs or expenses to the extent caused by (A) the Issuing Bank's willful misconduct or gross negligence, as determined by a court of competent jurisdiction, in determining whether documents presented under the Letter of Credit are genuine or comply with the terms of the Letter of Credit or (B) the Issuing Bank's willful or grossly negligent failure, as determined by a court of competent jurisdiction, to make lawful payment under the Letter of Credit after the presentation to it by the Paying Agent of a draft and certificate strictly complying with the terms and conditions of the Letter of Credit; or (v) by reason of any inaccuracy or alleged inaccuracy in any material respect, or any untrue statement or alleged untrue statement of any material fact, contained in any preliminary official statement relating to the Bonds or in any Preliminary Official Statement or Official Statement relating to the Bonds or any amendment or supplement thereto, except to the extent contained in or arising from information in any Preliminary Official Statement or Official Statement relating to the Bonds supplied in writing by and describing the Issuing Bank. (c) Nothing contained in this Section 10.04 is intended to limit the Account Party's obligations set forth in Articles II, III and IV. The Account Party's obligations under this Section 10.04 shall survive the creation and sale of any participation interest pursuant to Section 10.06 hereof and shall survive as well the repayment of all amounts owing to the Agent, the Issuing Bank and the Participating Banks under the Loan Documents and the termination of the Commitments. If and to the extent that the obligations of the Account Party under this Section 10.04 are unenforceable for any reason, the Account Party agrees to make the maximum contribution to the payment and satisfaction thereof which is permissible under applicable law. SECTION 10.05 Right of Set-off. (a) Upon (i) the occurrence and during the continuance of any Event of Default and (ii) the taking of any action or the giving of any instruction by the Agent as specified by Section 8.02 hereof, the Issuing Bank and each Participating Bank are hereby authorized at any time and from time to time, to the fullest extent permitted by law, to set off and apply any and all deposits (general or special, time or demand, provisional or final) at any time held and other indebtedness at any time owing by the Issuing Bank or such Participating Bank to or for the credit or the account of the Account Party against any and all of the obligations of the Account Party now or hereafter existing under this Agreement in favor of the Issuing Bank or such Participating Bank, irrespective of whether or not the Issuing Bank or such Participating Bank shall have made any demand under this Agreement and although such obligations may be unmatured. The Issuing Bank and each Participating Bank agrees promptly to notify the Account Party after any such set-off and application provided that the failure to give such notice shall not affect the validity of such set-off and application. The rights of the Issuing Bank and each Participating Bank under this Section are in addition to other rights and remedies (including, without limitation, other rights of set-off) which the Issuing Bank and/or such Participating Bank may have. (b) The Account Party agrees that it shall have no right of off-set, deduction or counterclaim in respect of its obligations hereunder, and that the obligations of the Issuing Bank and of the several Participating Banks hereunder are several and not joint. Nothing contained herein shall constitute a relinquishment or waiver of the Account Party's rights to any independent claim that the Account Party may have against the Issuing Bank or any Participating Bank, but no Participating Bank shall be liable for the conduct of the Issuing Bank or any other Participating Bank, and the Issuing Bank shall not be liable for the conduct of any Participating Bank. SECTION 10.06 Binding Effect; Assignments and Participants. (a) This Agreement shall become effective when it shall have been executed and delivered by the Account Party, the Agent, the Issuing Bank and each Participating Bank named on the signature pages hereto and thereafter shall be binding upon and inure to the benefit of the Account Party, the Agent, the Issuing Bank and each Participating Bank and their respective successors and assigns, except that the Account Party shall not have the right to assign its rights hereunder or any interest herein without the prior written consent of the Issuing Bank and each Participating Bank, and the Issuing Bank may not assign its commitment to issue the Letter of Credit or its obligations under or in respect of the Letter of Credit. (b) Each Participating Bank may assign all or any portion of its rights under this Agreement, under the Letter of Credit or in any security hereunder, including, without limitation, any instruments securing the Account Party's obligations hereunder; provided that (i) no assignment by any Participating Bank may be made to any Person, other than to another Participating Bank, except with the prior written consent of the Issuing Bank and the Account Party (which consent, in the case of the Account Party, shall not be unreasonably withheld and, in the case of an assignment to an Affiliate of a Participating Bank shall not be required), (ii) any assignment shall be of a constant and not a varying percentage of all of the assignor's rights and obligations hereunder and (iii) the parties to each such assignment shall execute and deliver to the Agent a Participation Assignment, together with a processing fee of $3,000. Upon receipt of a completed Participation Assignment and the processing fee, the Agent will record in a register maintained for such purpose the name of the assignee and the percentage participation interest assigned by the assignor and assumed by the assignee for purposes of the determination of such assignor's and assignee's respective Participation Percentages. Upon such execution, delivery, acceptance and recording, from and after the effective date specified in each Participation Assignment, which effective date shall be at least five Business Days after the execution thereof, the assignee shall, to the extent of such assignment, become a party hereto and have all of the rights and obligations of a Participating Bank hereunder and, to the extent of such assignment, such assigning Participating Bank shall be released from its obligations hereunder (without relieving such Participating Bank from any liability for damages, costs and expenses suffered by the Issuing Bank or the Account Party as a result of the failure by such Participating Bank to perform its obligations hereunder). (c) Each Participating Bank may grant participations to one or more Persons in all or any part of, or any interest (undivided or divided) in, such Participating Bank's rights and obligations under this Agreement (any such Person being referred to hereinafter as a "Participant" and such interests are collectively, referred to hereinafter as the "Rights"); provided, however, that (i) such Participating Bank's obligations under this Agreement shall remain unchanged; (ii) any such Participant shall be entitled to the benefits and cost protections provided for in Section 4.03 hereof on the same basis as if it were a Participating Bank hereunder; (iii) the Account Party, the Agent and the Issuing Bank shall continue to deal solely and directly with such Participating Bank in connection with such Participating Bank's rights and obligations under this Agreement; and (iv) no such Participant, other than an Affiliate of such Participating Bank, shall be entitled to require such Participating Bank to take or omit to take any action hereunder, unless such action or omission would have an effect of the type described in subsections (c), (d) or (h) of Section 10.01 hereof. (d) Notwithstanding anything contained in this Section 10.06 to the contrary, the Issuing Bank and any Participating Bank may assign and pledge all or any portion of the Advances (or participating interests therein) owing to the Issuing Bank or such Participating Bank to any Federal Reserve Bank (and its transferees) as collateral security pursuant to Regulation A of the Board of Governors of the Federal Reserve System and any Operating Circular issued by such Federal Reserve Bank. No such assignment shall release the Issuing Bank or such Participating Bank from its obligations hereunder. SECTION 10.07 Relation of the Parties; No Beneficiary. No term, provision or requirement, whether express or implied, of any Loan Document, or actions taken or to be taken by any party thereunder, shall be construed to create a partnership, association, or joint venture between such parties or any of them. No term or provision of the Loan Documents shall be construed to confer a benefit upon, or grant a right or privilege to, any Person other than the parties hereto. SECTION 10.08 Issuing Bank Not Liable. As between the Agent, the Issuing Bank and the Participating Banks on the one hand, and the Account Party on the other, the Account Party assumes all risks of the acts or omissions of the Paying Agent, the Trustee and any other beneficiary or transferee of the Letter of Credit with respect to its use of the Letter of Credit. Neither the Agent, the Issuing Bank, any Participating Bank, nor any of their respective officers or directors shall be liable or responsible for: (a) the use which may be made of the Letter of Credit or any acts or omissions of the Paying Agent, the Trustee and any other beneficiary or transferee in connection therewith; (b) the validity, sufficiency or genuineness of documents, or of any endorsement thereon, even if such documents should prove to be in any or all respects invalid, insufficient, fraudulent or forged; (c) payment by the Issuing Bank against presentation of documents which do not comply with the terms of the Letter of Credit, including failure of any documents to bear any reference or adequate reference to the Letter of Credit; or (d) any other circumstances whatsoever in making or failing to make payment under the Letter of Credit, except that the Account Party shall have a claim against the Issuing Bank, and the Issuing Bank shall be liable to the Account Party, to the extent of any direct, as opposed to consequential, damages suffered by the Account Party which the Account Party proves were caused by (i) the Issuing Bank's willful misconduct or gross negligence, as determined by a court of competent jurisdiction, in determining whether documents presented under the Letter of Credit are genuine or comply with the terms of the Letter of Credit or (ii) the Issuing Bank's willful or grossly negligent failure, as determined by a court of competent jurisdiction, to make lawful payment under the Letter of Credit after the presentation to it by the Paying Agent of a draft and certificate strictly complying with the terms and conditions of the Letter of Credit. In furtherance and not in limitation of the foregoing, the Issuing Bank may accept original or facsimile (including telecopy) sight drafts and accompanying certificates presented under the Letter of Credit that appear on their face to be in order, without responsibility for further investigation, regardless of any notice or information to the contrary. SECTION 10.09 Confidentiality. In connection with the negotiation and administration of this Agreement and the other Loan Documents, the Account Party has furnished and will from time to time furnish to the Agent, the Issuing Bank and the Participating Banks (each, a "Recipient") written information which is identified to the Recipient when delivered as confidential (such information, other than any such information which (i) was publicly available, or otherwise known to the Recipient, at the time of disclosure, (ii) subsequently becomes publicly available other than through any act or omission by the Recipient or (iii) otherwise subsequently becomes known to the Recipient other than through a Person whom the Recipient knows to be acting in violation of his or its obligations to the Account Party, being hereinafter referred to as "Confidential Information"). The Recipient will not knowingly disclose any such Confidential Information to any third party (other than to those persons who have a confidential relationship with the Recipient), and will take all reasonable steps to restrict access to such information in a manner designed to maintain the confidential nature of such information, in each case until such time as the same ceases to be Confidential Information or as the Account Party may otherwise instruct. It is understood, however, that the foregoing will not restrict the Recipient's ability to freely exchange such Confidential Information with prospective assignees of or participants in the Recipient's position herein, but the Recipient's ability to so exchange Confidential Information shall be conditioned upon any such prospective assignee's or participant's entering into an understanding as to confidentiality similar to this provision. It is further understood that the foregoing will not prohibit the disclosure of any or all Confidential Information if and to the extent that such disclosure may be required (i) by a regulatory agency or otherwise in connection with an examination of the Recipient's records by appropriate authorities, (ii) pursuant to court order, subpoena or other legal process or (iii) otherwise, as required by law; in the event of any required disclosure under clause (ii) or (iii), above, the Recipient agrees to use reasonable efforts to inform the Account Party as promptly as practicable unless the Recipient is prohibited from doing so by court order, subpoena or other legal process. SECTION 10.10 Waiver of Jury Trial. The Account Party, the Agent, the Issuing Bank, and the Participating Banks each hereby irrevocably waives all right to trial by jury in any action, proceeding or counterclaim arising out of or relating to this Agreement or any other Loan Document, or any other instrument or document delivered hereunder or thereunder. SECTION 10.11 Governing Law. This Agreement and the Pledge Agreement shall be governed by, and construed in accordance with, the laws of the State of New York. The Account Party, the Agent, the Issuing Bank and each Participating Bank each (i) irrevocably submits to the jurisdiction of any New York State court or Federal court sitting in New York City in any action arising out of any Loan Document, (ii) agrees that all claims in such action may be decided in such court, (iii) waives, to the fullest extent it may effectively do so, the defense of an inconvenient forum and (iv) consents to the service of process by mail. A final judgment in any such action shall be conclusive and may be enforced in other jurisdictions. Nothing herein shall affect the right of any party to serve legal process in any manner permitted by law or affect its right to bring any action in any other court. SECTION 10.12 Execution in Counterparts. This Agreement may be executed in any number of counterparts and by different parties hereto in separate counterparts, each of which when so executed shall be deemed to be an original and all of which taken together shall constitute one and the same agreement. IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be executed by their respective officers thereunto duly authorized, as of the date first above written. THE ACCOUNT PARTY: THE CONNECTICUT LIGHT AND POWER COMPANY By /s/ Eugene Vertfeuille Title: Assistant Treasurer THE AGENT AND ISSUING BANK: CANADIAN IMPERIAL BANK OF COMMERCE, NEW YORK AGENCY, as Agent and as Issuing Bank By /s/Kris A. Grosshans Vice President CIBC Inc. and Agent THE PARTICIPATING BANKS: CANADIAN IMPERIAL BANK OF COMMERCE, NEW YORK AGENCY By /s/Kris A. Grosshans Vice President CIBC Inc. and Agent Participation Percentage: 100% Address for Notices Canadian Imperial Bank of Commerce, New York Agency Two Paces West 2727 Paces Ferry Road Suite 1200 Atlanta, GA 30339 Attention: Clare Coyne Telephone: (404) 319-4836 Fax: (404) 319-4950 With a Copy To: Canadian Imperial Bank of Commerce 200 West Madison Street, Suite 2300 Chicago, IL 60606 Attention: Kris A. Grosshans Telephone: (312) 855-3212 Fax: (312) 750-0927 SCHEDULE I APPLICABLE LENDING OFFICES Name of Domestic Eurodollar Participating Bank Lending Office CD Lending Office Lending Office Canadian Imperial Two Paces West Same as Domestic Same as Domestic Bank of Commerce, 2727 Paces Ferry Lending Office Lending Office New York Agency Road Suite 1200 Atlanta, GA 30339 Attn: Clare Coyne Tel: (404) 319-4836 Fax: (404) 319-4950 SCHEDULE II PENDING ACTIONS EXHIBIT 1.01A to Reimbursement Agreement IRREVOCABLE LETTER OF CREDIT NO. December 17, 1992 BayBank 7 New England Executive Park Burlington, Massachusetts 01803 Attention: Corporate Trust Department Dear Sir or Madam: We hereby establish, at the request and for the account of The Connecticut Light and Power Company (the "Account Party"), in your favor, as Paying Agent (the "Paying Agent") under that certain Loan and Trust Agreement, dated as of December 1, 1992 (the "Indenture"), by and among the Business Finance Authority of the State of New Hampshire (the "Issuer"), the Account Party and BayBank, as trustee (the "Trustee"), pursuant to which $21,000,000 in aggregate principal amount of the Issuer's Pollution Control Refunding Revenue Bonds (The Connecticut Light and Power Company Project - 1992 Series A) (the "Bonds"), are being issued, our Irrevocable Letter of Credit No. , in the amount of US$21,311,000.00 (TWENTY-ONE MILLION THREE HUNDRED ELEVEN THOUSAND AND NO ONE-HUNDREDTHS UNITED STATES DOLLARS) (subject to reduction and reinstatement as provided below). (1) Credit Termination Date. This Letter of Credit shall expire on the earliest to occur of (i) December 17, 1995 (the "Stated Termination Date"), (ii) the date upon which we honor a draft accompanying a written and completed certificate signed by you in substantially the form of Exhibit 2 attached hereto, and stating therein that such draft is the final draft to be drawn under this Letter of Credit and that, upon the honoring of such draft, this Letter of Credit will expire in accordance with its terms, (iii) the date upon which we receive a written certificate signed by you and stating therein that no Bonds entitled to the benefits of this Letter of Credit (as determined in accordance with the Indenture) ("Eligible Bonds") are "outstanding" under the Indenture, (iv) the fifth business day following receipt by you and the Trustee of written notice from us that an Event of Default (as defined below) has occurred under the Reimbursement Agreement (as defined below) and of our determination to terminate this Letter of Credit on such fifth business day and (v) the date upon which we receive a written certificate signed by you and stating therein that a substitute or replacement Credit Facility (as defined in the Indenture) has been provided pursuant to Section 317 of the Indenture (such earliest date being the "Credit Termination Date"). As used herein, the term "business day" shall mean any day of the year (i) that is not a Sunday or legal holiday, (ii) that is a day on which banks are not required or authorized to close in New York City and (iii) that is a day on which banking institutions in all of the cities in which the principal offices of the Trustee, the Paying Agent and the Remarketing Agent (as defined in the Indenture) are located are not required or authorized to remain closed and (iv) that is a day on which the New York Stock Exchange is not closed. As used herein "Reimbursement Agreement" shall mean the Letter of Credit and Reimbursement Agreement, dated as of December 1, 1992, between the Account Party, us and certain Participating Banks referred to therein, and the term "Event of Default" shall mean an "Event of Default" as that term is defined in the Reimbursement Agreement. (2) Principal, Interest and Premium Components. The aggregate amount which may be drawn under this Letter of Credit, subject to reductions in amount and reinstatement as provided below, is US$21,311,000.00 (TWENTY-ONE MILLION THREE HUNDRED ELEVEN THOUSAND AND NO ONE-HUNDREDTHS UNITED STATES DOLLARS), of which the aggregate amounts set forth below may be drawn as indicated. (i) An aggregate amount not exceeding US$21,000,000.00 (TWENTY-ONE MILLION AND NO ONE-HUNDREDTHS UNITED STATES DOLLARS), as such amount may be reduced and reinstated as provided below, may be drawn in respect of payment of principal (whether upon scheduled or accelerated maturity, or upon redemption) of Eligible Bonds or the portion of the purchase price of Eligible Bonds corresponding to principal (the "Principal Component"). (ii) An aggregate amount not exceeding US$311,000.00 (THREE HUNDRED ELEVEN THOUSAND AND NO ONE-HUNDREDTHS UNITED STATES DOLLARS), as such amount may be reduced and reinstated as provided below, may be drawn in respect of payment of (A) accrued and unpaid interest on Eligible Bonds not in the Flexible Mode (as defined in the Indenture) or that portion of the redemption price or purchase price of such Eligible Bonds corresponding to accrued and unpaid interest, but not more than an amount equal to accrued and unpaid interest on such Eligible Bonds for up to a maximum of 45 days immediately preceding the date of such drawing and (B) unpaid interest (whether accrued or to accrue) on Eligible Bonds in the Flexible Mode or that portion of the redemption price or purchase price of such Eligible Bonds corresponding to such interest, but not more than an amount equal to such interest on such Eligible Bonds for up to a maximum of 45 days immediately preceding the next Purchase Date (as defined in the Indenture) for each such Eligible Bond (or, if interest on any such Eligible Bond was not paid on the most recent Purchase Date for such Bond, for up to a maximum of 45 days immediately preceding the date of such drawing), calculated, in each case referred to in the foregoing clause (A) or clause (B) at a maximum rate of twelve percent (12%) per annum, or such lesser rate of interest as shall equal the Maximum Interest Rate (as defined in the Indenture) in effect under the Indenture with respect to such Eligible Bonds, and in any case calculated on the basis of a year of 365 or 366 days (as applicable) for the actual days elapsed (the "Interest Component"). (iii) An aggregate amount not exceeding US$0.00 (ZERO UNITED STATES DOLLARS) may be drawn in respect of premium on Eligible Bonds (the "Premium Component"). If, subsequent to the date hereof, the Premium Component shall be increased by us at the request of the Account Party, the Premium Component shall be subject to reduction as provided below, and amounts drawn in respect thereof shall not be subject to reinstatement. (3) Drawings. Funds under this Letter of Credit are available to you against (i) your draft, stating on its face: "Drawn under Irrevocable Letter of Credit No. , dated December 17, 1992", and (ii) the appropriate certificate specified below, purportedly executed by you and appropriately completed. Exhibit Setting Forth Type of Drawing Form of Certificate Required Tender Drawing Exhibit 1 (as hereinafter defined) Redemption/Mandatory Exhibit 2 Purchase Drawing (as hereinafter defined) Interest Drawing Exhibit 3 (as hereinafter defined) Drafts and certificates hereunder shall be dated the date of presentation and shall be presented at our office located at Two Paces West, 2727 Paces Ferry Road, Suite 1200, Atlanta, Georgia 30339, Attention: Clare Coyne (telephone: (404) 319-4836) (or at such other office as we may designate by written notice to you). Presentation of such drafts and certificates may be made (a) by physical presentation of such drafts and certificates or (b) by facsimile transmission of such drafts and certificates received by us at (404) 319-4950 (or at such other number as we may designate by written notice to you) with prior telephone notice to us at (404) 319- 4836, Attention: Clare Coyne, (or at such other number as we may designate by written notice to you) that such presentation is to be made by facsimile transmission and with the original executed drafts and certificates to be received by us not later than our close of business on the next business day, it being understood that payments hereunder shall be made upon receipt by us of such facsimile transmission; provided, however, that presentations of drafts and certificates relating to Tender Drawings in respect of Eligible Bonds in the Flexible Mode shall in all instances be made in accordance with the foregoing clause (b). Drafts drawn under and in strict compliance with the terms of this Letter of Credit will be duly honored by us upon presentation thereof in accordance with this Paragraph 3 if presented on or prior to 4:00 P.M. (New York City time) on the Credit Termination Date as follows: (i) Tender Drawings; Flexible Mode. In the case of drafts and certificates relating to Tender Drawings in respect of Eligible Bonds in the Flexible Mode presented in accordance with the foregoing clause (b): (A) if such drafts and certificates are presented as aforesaid at or prior to 1:30 P.M. (New York City time) on a business day, and provided that such drafts and certificates strictly conform to the requirements of this Letter of Credit, we will initiate a wire transfer of the amount so drawn to your account indicated below at or prior to 3:30 P.M. (New York City time) on the same business day; (B) if such drafts and certificates are presented as aforesaid after 1:30 P.M. but at or prior to 4:00 P.M. (New York City time) on a business day, and provided that such drafts and certificates strictly conform to the requirements of this Letter of Credit, we will initiate a wire transfer of the amount so drawn to your account indicated below at or prior to 10:00 A.M. on the business day next succeeding the business day on which such drafts and certificates were presented (notwithstanding that such day of presentation may have been the Credit Termination Date); and (C) if such drafts and certificates are presented as aforesaid after 4:00 P.M. (New York City time) on a business day, and provided that such drafts and certificates strictly conform to the requirements of this Letter of Credit, we will initiate a wire transfer of the amount so drawn to your account indicated below at or prior to 1:00 P.M. (New York City time) on the business day next succeeding the business day on which such drafts and certificates were presented (notwithstanding that such day of presentation may have been the Credit Termination Date); and (ii) All Other Drawings: In the case of any other drafts and certificates: (A) if such drafts and certificates are presented as aforesaid at or prior to 4:00 P.M. (New York City time) on a business day, and provided that such drafts strictly conform to the requirements of this Letter of Credit, we will initiate a wire transfer of the amount so drawn to your account indicated below at or prior to 10:00 A.M. (New York City time) on the business day next succeeding the business day on which such drafts and certificates were presented (notwithstanding that such day of presentation may have been the Credit Termination Date); and (B) if such drafts and certificates are presented as aforesaid after 4:00 P.M. (New York City time) on a business day, and provided that such drafts and certificates strictly conform to the requirements of this Letter of Credit, we will initiate a wire transfer of the amount so drawn to your account indicated below at or prior to 1:00 P.M. (New York City time) on the business day next succeeding the business day on which such drafts and certificates were presented (notwithstanding that such day of presentation may have been the Credit Termination Date). Wire transfers of funds paid in respect of any drawing hereunder shall be made to you at BayBank Boston, ABA # 011001742, credit Account No. 002-298-5, Attention: Corporate Trust, or to such other account as you may from time to time specify to us in writing. All payments made by us under this Letter of Credit will be made with our own funds and not with any funds of the Account Party or the Issuer. (4) Reductions. The Interest Component shall be reduced immediately following our honoring any draft drawn hereunder to pay unpaid interest on Eligible Bonds or to pay that portion of the purchase price or redemption price corresponding to unpaid interest on Eligible Bonds, in each case by an amount equal to the amount of such draft (any such drawing being an "Interest Drawing"). The Principal Component shall be reduced immediately following our honoring any draft drawn hereunder: (i) pursuant to Section 308(c)(ii) of the Indenture to pay that portion of purchase price corresponding to principal of Eligible Bonds that are (A) subject to mandatory tender for purchase pursuant to Section 301(d)(iii), 301(e)(iv)(B) or 301(f)(iii) of the Indenture or (B) tendered for purchase by the holders thereof pursuant to Section 301(e)(iii) of the Indenture (any such drawing in respect of the circumstances referred to in this clause (i) being a "Tender Drawing"), (ii) pursuant to Section 308(c)(i) of the Indenture to pay the principal of Eligible Bonds or that portion of the redemption price of Eligible Bonds corresponding to principal, whether at stated maturity, upon acceleration or upon redemption, or (iii) pursuant to Section 308(c)(ii) of the Indenture to pay that portion of the purchase price corresponding to principal of Eligible Bonds that are subject to mandatory tender for purchase pursuant to Section 301(e)(iv)(A) of the Indenture (any such drawing in respect of the circumstances referred to in the foregoing clause (ii) or in this clause (iii) being a "Redemption/Mandatory Purchase Drawing"), in each such case by an amount equal to the amount of such draft. The Premium Component shall be reduced immediately following our honoring any draft drawn hereunder to pay premium on Eligible Bonds in connection with a Redemption/Mandatory Purchase Drawing, by an amount equal to the amount of such draft. Additionally, upon receipt of a Notice of Reduction in the form of Exhibit 4 to this Letter of Credit purportedly executed by you, we will reduce the Principal Component, Interest Component and Premium Component to the amounts therein stated. (5) Reinstatement. The Interest Component and the Principal Component shall, from time to time, be reinstated by us in accordance with, and only to the extent provided in, the following subparagraphs (i) and (ii). In no event shall reductions in the Premium Component be reinstated. (i) Interest Component. Reductions in the Interest Component resulting from Interest Drawings shall be reinstated as follows: (A) Immediately following each drawing hereunder to pay unpaid interest on Eligible Bonds in the Flexible Mode or to pay that portion of purchase price, but not redemption price, corresponding to unpaid interest on Eligible Bonds in the Flexible Mode, the amount so drawn shall be automatically reinstated to the Interest Component unless, not later than the business day preceding such drawing you shall have received written notice from us that we will not reinstate the Interest Component in the amount of such drawing. On the fifth day following each drawing hereunder to pay accrued and unpaid interest on Eligible Bonds that are not in the Flexible Mode, or to pay that portion of purchase price, but not redemption price, corresponding to accrued and unpaid interest on Eligible Bonds that are not in the Flexible Mode, the amount so drawn shall be automatically reinstated to the Interest Component, unless you shall have theretofore received written notice from us that we will not reinstate the Interest Component in the amount of such drawing. Any notice of non-reinstatement delivered pursuant to this subparagraph (i)(A) shall be in writing and shall be delivered to you by hand delivery or facsimile transmission. (B) If, subsequent to any such delivery of a notice of non- reinstatement as aforesaid, we shall deliver to you, by hand delivery or facsimile transmission, a Notice of Reinstatement in the form of Exhibit 5 hereto, then, upon such delivery to you, the Interest Component shall be immediately reinstated to the extent specified in such Notice of Reinstatement. (C) In no event shall the Interest Component be reinstated to an amount in excess of 45 days' interest on Eligible Bonds, computed at the rate of 12% per annum on the basis of a year of 365 or 366 days (as applicable) for the actual days elapsed, or such lesser rate of interest as shall equal the Maximum Interest Rate (as defined in the Indenture) in effect under the Indenture with respect to such Eligible Bonds. (ii) Principal Component. Reductions in the Principal Component resulting from Redemption/Mandatory Purchase Drawings shall in no event be reinstated. Reductions in the Principal Component resulting from Tender Drawings shall be reinstated as follows: (A) Immediately upon receipt by us of proceeds from the remarketing of Pledged Bonds (as defined in the Indenture), or of written notice from you that you have received such proceeds (or a window receipt guaranteeing same day payment in immediately available funds of such proceeds as contemplated by Section 312(a) of the Indenture), the Principal Component shall be reinstated automatically by the amount of such proceeds. (B) Immediately upon your receipt from us, by hand delivery or facsimile transmission, of a Notice of Reinstatement in the form of Exhibit 5 hereto, the Principal Component shall be immediately reinstated to the extent specified in such Notice of Reinstatement. (C) In no event shall the Principal Component be reinstated to an amount in excess of the aggregate principal amount of Eligible Bonds then outstanding under the Indenture. Any Notice of Reinstatement delivered to you in the form set forth in Exhibit 5 hereto, whether delivered pursuant to subparagraph (i) or subparagraph (ii), above, may be combined, in a single such Notice, with any other Notice of Reinstatement delivered pursuant to the other such subparagraph. (6) Notices. Communications (other than drawings) with respect to this Letter of Credit shall be in writing and shall be addressed to us at Two Paces West, 2727 Paces Ferry Road, Suite 1200, Atlanta, Georgia 30339, Attention: Clare Coyne (telephone: (404) 319-4836, telecopy: (404) 319-4950, with a copy to: Canadian Imperial Bank of Commerce, Utilities Group, 200 West Madison Street, Suite 2300, Chicago, Illinois 60606 (telephone: (312) 855-3212, telecopy: (312) 750-0927) (or at such other office as we may designate by written notice to you), specifically referring to the number of this Letter of Credit. (7) Transfer. This Letter of Credit is transferable in its entirety (but not in part) to any transferee who has succeeded you as Paying Agent under the Indenture and may be successively so transferred. Transfer of the available balance under this Letter of Credit to such transferee shall be effected by the presentation to us of this Letter of Credit accompanied by a certificate substantially in form set forth in Exhibit 6. (8) Governing Law, Etc. Except as otherwise provided herein, this Letter of Credit shall be governed by and construed in accordance with the Uniform Customs and Practices for Documentary Credits (1983 Revision) Publication No. 400 of the International Chamber of Commerce ("UCP") and, to the extent not inconsistent with the UCP, the laws of the State of New York, including the Uniform Commercial Code as in effect in the State of New York. This Letter of Credit sets forth in full our undertaking, and, except as expressly set forth herein, such undertaking shall not in any way be modified, amended, amplified or limited by reference to any document, instrument or agreement referred to herein (including, without limitation, the Bonds, the Indenture and the Reimbursement Agreement), except only the certificates and the drafts referred to herein; and any such reference shall not be deemed to incorporate herein by reference any document, instrument or agreement except for such certificates and such drafts. Whenever and wherever the terms of this Letter of Credit shall refer to the purpose of a draft hereunder, or the provisions of any agreement or document pursuant to which such draft may be presented hereunder, such purpose or provisions shall be conclusively determined by reference to the certificate accompanying such draft; in furtherance of this sentence, whether any drawing is in respect of payment of regularly scheduled interest on the Bonds or of principal of or interest on the Bonds upon scheduled or accelerated maturity or is a Tender Drawing or a Redemption/Mandatory Purchase Drawing shall be conclusively determined by reference to the certificate accompanying such drawing. Very truly yours, CANADIAN IMPERIAL BANK OF COMMERCE, NEW YORK AGENCY By Title: By Title: EXHIBIT 1 TO THE LETTER OF CREDIT CERTIFICATE FOR TENDER DRAWING The undersigned, a duly authorized officer of , (the "Paying Agent"), hereby certifies as follows to Canadian Imperial Bank of Commerce, New York Agency (the "Bank"), with reference to Irrevocable Letter of Credit No. (the "Letter of Credit") issued by the Bank in favor of the Paying Agent. Terms defined in the Letter of Credit and used but not defined herein shall have the meanings given them in the Letter of Credit. (1) The Paying Agent is the Paying Agent under the Indenture for the holders of the Bonds. (2) The Paying Agent is making a Tender Drawing under the Letter of Credit in the amount of $ pursuant to Section 308(c)(ii) of the Indenture to pay that portion of the purchase price corresponding to principal of Eligible Bonds that are [subject to mandatory tender for purchase pursuant to Section [301(d)(iii)] [301(e)(iv)(B)] [301(f)(iii)] of the Indenture.] [tendered for purchase by the holders thereof pursuant to Section 301(e)(iii) of the Indenture.] (3) The amount of purchase price corresponding to principal of Eligible Bonds and with respect to the payment of which the Paying Agent, pursuant to the foregoing Sections of the Indenture, is drawing under the Letter of Credit, is as follows, and the amount of the draft accompanying this Certificate does not exceed such amount: Principal: $ (4) The amount of the draft accompanying this Certificate being drawn in respect of purchase price corresponding to principal of Eligible Bonds, as indicated in paragraph (3), above, does not exceed the Principal Component of the Letter of Credit. The amount of the draft accompanying this Certificate in respect of purchase price corresponding to principal of such Bonds has been computed in accordance with the terms and conditions of such Eligible Bonds and the Indenture. (5) No proceeds of this drawing will be applied to the payment of purchase price of any Bonds that are not Eligible Bonds, including any Pledged Bonds (as defined in the Indenture), any Company Bonds (as defined in the Indenture) and any Bonds in the Fixed Rate Mode (as defined in the Indenture). [(6) The Eligible Bonds in respect of which this drawing is being made are Eligible Bonds in the Flexible Mode, and payment of this drawing shall be made in accordance with Paragraph 3(i) of the Letter of Credit.] [(6) The Eligible Bonds in respect of which this drawing is being made are not Eligible Bonds in the Flexible Mode, and payment of this drawing shall be made in accordance with Paragraph 3(ii) of the Letter of Credit]. IN WITNESS WHEREOF, the Paying Agent has executed and delivered this Certificate as of the day of , 19 . [NAME OF PAYING AGENT], as Paying Agent By Title: EXHIBIT 2 TO THE LETTER OF CREDIT CERTIFICATE FOR REDEMPTION/ MANDATORY PURCHASE DRAWING The undersigned, a duly authorized officer of , (the "Paying Agent"), hereby certifies as follows to Canadian Imperial Bank of Commerce, New York Agency (the "Bank"), with reference to Irrevocable Letter of Credit No. (the "Letter of Credit") issued by the Bank in favor of the Paying Agent. Terms defined in the Letter of Credit and used but not defined herein shall have the meanings given them in the Letter of Credit. (1) The Paying Agent is the Paying Agent under the Indenture for the holders of the Bonds. (2) The Paying Agent is making a Redemption/Mandatory Purchase Drawing under the Letter of Credit in the amount of $ [pursuant to Section 308(c)(i) and Section 605 of the Indenture to pay the principal of Eligible Bonds due pursuant to the Indenture upon maturity or as a result of acceleration of such Eligible Bonds in accordance with the Indenture and the terms of such Eligible Bonds.] [pursuant to Section 308(c)(i) of the Indenture to pay that portion of the redemption price corresponding to principal of [and premium on] Eligible Bonds due pursuant to the Indenture upon redemption of such Eligible Bonds in accordance with the Indenture and the terms of such Eligible Bonds.] [pursuant to Section 308(c)(ii) of the Indenture to pay that portion of the purchase price of Eligible Bonds corresponding to principal that are subject to mandatory tender for purchase pursuant to Section 301(e)(iv)(A) of the Indenture.] (3) The amount of [principal of] [redemption price corresponding to principal of] [and premium on] [purchase price corresponding to principal of] Eligible Bonds which is due and payable and with respect to the payment of which the Paying Agent, pursuant to the foregoing Section[s] of the Indenture, is to draw under the Letter of Credit is as follows, and the amount of the draft accompanying this Certificate does not exceed such amount: Principal: $ [Premium: $ ] (4) The amount of the draft accompanying this Certificate being drawn in respect of payment of [principal] [redemption price corresponding to principal] [purchase price corresponding to principal] of Eligible Bonds, as indicated in paragraph (3), above, does not exceed the Principal Component of the Letter of Credit. [The amount of the draft accompanying this Certificate being drawn in respect of that portion of the redemption price of Eligible Bonds corresponding to premium, as indicated in paragraph (3), above, does not exceed the Premium Component of the Letter of Credit.] The amount of the draft accompanying this Certificate in respect of payment of [principal] [redemption price corresponding to principal] [and premium] [purchase price corresponding to principal] of such Eligible Bonds has been computed in accordance with the terms and conditions of such Eligible Bonds and the Indenture. (5) No proceeds of this drawing will be applied to the payment of principal, redemption price (including premium, if any) or purchase price of any Bonds that are not Eligible Bonds, including any Pledged Bonds (as defined in the Indenture), any Company Bonds (as defined in the Indenture), and any Bonds in the Fixed Rate Mode (as defined in the Indenture). (6) Payment of this drawing shall be made in accordance with Paragraph 3(ii) of the Letter of Credit. [(7) The draft accompanying this Certificate is the final draft to be drawn under the Letter of Credit, and, upon the honoring of such draft, the Letter of Credit will expire in accordance with its terms.] IN WITNESS WHEREOF, the Paying Agent has executed and delivered this Certificate as of the day of , 19 . [NAME OF PAYING AGENT], as Paying Agent By Title: EXHIBIT 3 TO THE LETTER OF CREDIT CERTIFICATE FOR INTEREST DRAWING The undersigned, a duly authorized officer of , (the "Paying Agent"), hereby certifies as follows to Canadian Imperial Bank of Commerce, New York Agency (the "Bank"), with reference to Irrevocable Letter of Credit No. (the "Letter of Credit") issued by the Bank in favor of the Paying Agent. Terms defined in the Letter of Credit and used but not defined herein shall have the meanings given them in the Letter of Credit. (1) The Paying Agent is the Paying Agent under the Indenture for the holders of the Bonds. (2) The Paying Agent is making a drawing under the Letter of Credit in the amount of $ with respect to [the payment of interest] [the payment of the portion of redemption price corresponding to interest] [the payment of the portion of purchase price corresponding to interest] on Eligible Bonds in accordance with the Indenture. (3) The amount of [interest] [redemption price corresponding to interest] [purchase price corresponding to interest] on Eligible Bonds that is due and owing is as follows, and the amount of the draft accompanying this Certificate does not exceed such amount: Interest: (4) The amount of the draft accompanying this Certificate being drawn in respect of payment of [interest] [redemption price corresponding to interest] [purchase price corresponding to interest] on Eligible Bonds, as indicated in paragraph (3), above, does not exceed the Interest Component of the Letter of Credit. The amount of the draft accompanying this Certificate in respect of payment of [interest] [redemption price corresponding to interest] [purchase price corresponding to interest] on Eligible Bonds has been computed in accordance with the terms and conditions of such Eligible Bonds and the Indenture. (5) Payment of this drawing shall be made in accordance with Paragraph 3(ii) of the Letter of Credit. IN WITNESS WHEREOF, the Paying Agent has executed and delivered this Certificate as of the day of , 19 . [NAME OF PAYING AGENT], as Paying Agent By Title: EXHIBIT 4 TO THE LETTER OF CREDIT NOTICE OF REDUCTION The undersigned, a duly authorized officer of , (the "Paying Agent"), hereby certifies as follows to Canadian Imperial Bank of Commerce, New York Agency (the "Bank"), with reference to Irrevocable Letter of Credit No. (the "Letter of Credit") issued by the Bank in favor of the Paying Agent. Terms defined in the Letter of Credit and used but not defined herein shall have the meanings given them in the Letter of Credit. (1) The Paying Agent is the Paying Agent under the Indenture for the holders of the Bonds. (2) As of the date hereof, the aggregate principal amount of Eligible Bonds (including for this purpose all Pledged Bonds and all Company Bonds) outstanding is Principal: $ (3) You are hereby directed to reduce the [Principal] [Premium] [and] [Interest] Components of the Letter of Credit as follows: [The Principal Component of the Letter of Credit is reduced to $ .] [The Premium Component of the Letter of Credit is reduced to $ .] [The Interest Component of the Letter of Credit is reduced to $ .] IN WITNESS WHEREOF, the Paying Agent has executed and delivered this Certificate as of the day of , 19 . [NAME OF PAYING AGENT], as Paying Agent By Title: EXHIBIT 5 TO THE LETTER OF CREDIT NOTICE OF REINSTATEMENT The undersigned, a duly authorized officer of Canadian Imperial Bank of Commerce, New York Agency (the "Bank"), hereby gives the following notice to , as paying agent (the "Paying Agent"), with reference to Irrevocable Letter of Credit No. (the "Letter of Credit") issued by the Bank in favor of the Paying Agent. Terms defined in the Letter of Credit and used but not defined herein have the meanings given them in the Letter of Credit. The Bank hereby notifies you that: [1.] [Pursuant to Paragraph 5(i)(B) of the Letter of Credit and Section 2.04(b)(ii) of the Reimbursement Agreement, the Interest Component has been reinstated by $ .] [2.] [Pursuant to Paragraph 5(ii)(B) of the Letter of Credit and Section 2.04(c) of the Reimbursement Agreement, the Principal Component has been reinstated by $ .] IN WITNESS WHEREOF, the Bank has executed and delivered this Notice of Reinstatement as of the day of , 19 CANADIAN IMPERIAL BANK OF COMMERCE, NEW YORK AGENCY By Title: EXHIBIT 6 TO THE LETTER OF CREDIT INSTRUCTIONS TO TRANSFER , 19 Re: Irrevocable Letter of Credit No. Gentlemen: The undersigned, as Paying Agent under that certain Loan and Trust Agreement, dated as of December 1, 1992 (the "Indenture"), by and among the Business Finance Authority of the State of New Hampshire (the "Issuer"), The Connecticut Light and Power Company and BayBank, as Trustee, is named as beneficiary in the Letter of Credit referred to above (the "Letter of Credit"). The Transferee named below has succeeded the undersigned as Paying Agent under such Indenture. (Name of Transferee) (Address) Therefore, for value received, the undersigned hereby irrevocably instructs you to transfer to such Transferee all rights of the undersigned to draw under the Letter of Credit. Such Transferee shall hereafter have the sole rights as beneficiary under the Letter of Credit; provided, however, that no rights shall be deemed to have been transferred to such Transferee until such transfer complies with the requirements of the Letter of Credit pertaining to transfers. IN WITNESS WHEREOF, the undersigned has executed and delivered this Certificate as of the day of , 19 . [NAME OF RETIRING PAYING AGENT], as Paying Agent By Title: The undersigned, [Name of Transferee], hereby accepts the foregoing transfer of rights under the Letter of Credit. [Name of Transferee] By Title: Address of Principal Corporate Trust Office: [insert address] EXHIBIT 1.01B PARTICIPATION ASSIGNMENT Dated , 19 Reference is made to the Letter of Credit and Reimbursement Agreement, dated as of December 1, 1992 (said Agreement, as it may hereafter be amended or otherwise modified from time to time, being the "Agreement"; unless otherwise defined herein terms defined in the Agreement are used herein with the same meaning), among The Connecticut Light and Power Company (the "Account Party"), Canadian Imperial Bank of Commerce, New York Agency ("CIBC"), as Issuing Bank, the Participating Banks named therein and from time to time parties thereto, and CIBC, as Agent. Pursuant to the Agreement, (the "Assignor") has purchased a participation from the Issuing Bank in and to the Letter of Credit and each payment thereunder and demand loan made by the Issuing Bank and has committed to make Advances to the Account Party. The Assignor and (the "Assignee") agree as follows: 1. The Assignor hereby sells and assigns, without recourse, to the Assignee, and the Assignee hereby purchases and assumes from the Assignor, without recourse to the Assignor that portion set forth in Section 1(c) of Schedule 1 hereto (the "Assigned Interest") of the Assignor's rights and obligations under the Agreement and the Pledge Agreement, including, without limitation, the participation purchased by the Assignor pursuant to Section 3.07 of the Agreement in respect of unreimbursed amounts and demand loans owing from time to time to the Issuing Bank, the Commitment of the Assignor to make Advances and the Advances outstanding on the Effective Date (as hereinafter defined). Such Assigned Interest represents the percentage interest specified in Section 2(b) of Schedule 1 of all outstanding rights and obligations of the Participating Banks under the Agreement, and, after giving effect to such sale and assignment, the Assignee's and Assignor's Participation Percentages will be as set forth in Sections 2(b) and 2(c), respectively, of Schedule 1. The effective date of this sale and assignment shall be the date specified in Section 3 of Schedule 1 (the "Effective Date"). 2. On the Effective Date, the Assignee will pay to the Assignor, in same day funds, at such address and account as the Assignor shall advise the Assignee, an amount equal to (1) the aggregate amount of unreimbursed letter of credit payments, demand loans and Advances outstanding (as set forth in Section 1 of Schedule 1) times (2) the Assigned Interest. From and after the Effective Date, the Assignor agrees that the Assignee shall be entitled to all rights, powers and privileges of the Assignor under the Agreement and the Pledge Agreement to the extent of the Assigned Interest, including without limitation (i) the right to receive all payments in respect of the Assigned Interest for the period from and after the Effective Date, whether on account of reimbursements, principal, interest, fees, indemnities in respect of claims arising after the Effective Date, increased costs, additional amounts or otherwise; (ii) the right to vote and to instruct the Agent and the Issuing Bank under the Agreement based on the Assigned Interest; (iii) the right to set-off and to appropriate and apply deposits of the Account Party as set forth in the Agreement; and (iv) the right to receive notices, requests, demands and other communications. The Assignor agrees that it will promptly remit to the Assignee any amount received by it in respect of the Assigned Interest (whether from the Account Party, the Agent or otherwise) in the same funds in which such amount is received by the Assignor. 3. The Assignor (i) represents and warrants that it is the legal and beneficial owner of the interest being assigned by it hereunder and that such interest is free and clear of any adverse claim; (ii) makes no representation or warranty and assumes no responsibility with respect to any statements, warranties or representations made in or in connection with the Agreement or the Related Documents or the execution, legality, validity, enforceability, genuineness, sufficiency or value of the Agreement, the Related Documents or any other instrument or document furnished pursuant thereto; and (iii) makes no representation or warranty and assumes no responsibility with respect to the financial condition of the Account Party or the performance or observance by the Account Party of any of its obligations under the Agreement, the Related Documents or any other instrument or document furnished pursuant thereto. 4. The Assignee (i) confirms that it has received a copy of the Agreement, together with copies of the financial statements referred to in Section 6.01(f) thereof and such other documents and information as it has deemed appropriate to make its own credit analysis and decision to enter into this Assignment; (ii) agrees that it will, independently and without reliance upon the Agent, the Issuing Bank, the Assignor or any other Participating Bank and based on such documents and information as it shall deem appropriate at the time, continue to make its own credit decisions in taking or not taking action under the Agreement and the Related Documents; (iii) appoints and authorizes the Agent to take such action as agent on its behalf and to exercise such powers under the Agreement and the Pledge Agreement as are delegated to the Agent by the terms thereof, together with such powers as are reasonably incidental thereto; (iv) agrees that it will perform in accordance with its terms all of the obligations which by the terms of the Agreement are required to be performed by it as a Participating Bank and (v) confirms that it has paid the processing fee referred to in subsection 10.06(b) of the Agreement. 5. Following the execution of this Assignment, it will be delivered to the Agent for acceptance and recording by the Agent. Upon such acceptance and recording and receipt of the consent of the Issuing Bank required pursuant to Section 10.06(b) of the Agreement (which shall be evidenced by the Issuing Bank's execution of this Assignment on the appropriate space on Schedule 1), as of the Effective Date, (i) the Assignee shall be a party to the Agreement and, to the extent provided in this Assignment, have the rights and obligations of a Participating Bank thereunder and under the Pledge Agreement and (ii) the Assignor shall, to the extent provided in this Assignment, relinquish its rights and be released from its obligations under the Agreement and the Pledge Agreement. 6. Upon such acceptance, recording and consent, from and after the Effective Date, the Agent shall make all payments under the Agreement in respect of the interest assigned hereby (including, without limitation, all payments of principal, interest and fees with respect thereto) to the Assignee at its address set forth on Schedule 1 hereto. The Assignor and Assignee shall make all appropriate adjustments in payments under the Agreement for periods prior to the Effective Date directly between themselves. 7. This Assignment shall be governed by, and construed in accordance with, the laws of the State of New York. 8. This Assignment may be executed in counterparts by the parties hereto, each of which counterpart when so executed shall be deemed to be an original and all of which when taken together shall constitute one and the same agreement. IN WITNESS WHEREOF, the parties hereto have caused this Assignment to be executed by their respective officers thereunto duly authorized, as of the date first above written, such execution being made on Schedule 1 hereto. Schedule 1 to Participation Assignment Dated , 19 Section 1 a. Total Unreimbursed Payments and demand loans $ b. Total Advances: $ c. Assigned Interest:* % Section 2 a. Assignor's Participation Percentage (immediately prior to the effectiveness of this Assignment) % b. Assignee's Participation Percentage** (upon the effectiveness of this Assignment) % c. Assignor's Participation Percentage** (upon the effectiveness of this Assignment) % Section 3 Effective Date***: ,19 [NAME OF ASSIGNOR] By Title: [NAME OF ASSIGNEE] By Title: [Address] Telecopier No. Attention: Consented to this day of , CANADIAN IMPERIAL BANK OF COMMERCE, NEW YORK AGENCY as Issuing Bank By Title: Accepted this day**** of , CANADIAN IMPERIAL BANK OF COMMERCE, NEW YORK AGENCY, as Agent By Title: *Specify percentage to no more than 8 decimal points. **The sum of the percentages set forth in Section 2(b) and (c) shall equal the percentage set forth in Section 2(a). ***Such date shall be at least 5 Business Days after the execution of this Assignment. ****Not to be accepted without proof of Account Party's consent pursuant to Section 10.06(b) of the Reimbursement Agreement. APPLICABLE LENDING OFFICES The Assignee's Applicable Lending Offices are as follows: Domestic Lending Office: CD Lending Office: Eurodollar Lending Office: EXHIBIT 1.01C PLEDGE AGREEMENT Dated as of December 1, 1992 THIS PLEDGE AGREEMENT ("this Agreement") is made by and between: (i) The Connecticut Light and Power Company, a corporation duly organized and validly existing under the laws of the State of Connecticut (the "Account Party"); and (ii) Canadian Imperial Bank of Commerce, New York Agency ("CIBC"), as issuer of the Letter of Credit (the "Issuing Bank"); for the benefit of the Issuing Bank and (iii) The Agent (as defined therein) and the Participating Banks (as defined therein) from time to time party to the Reimbursement Agreement hereinafter referred to. PRELIMINARY STATEMENT The Business Finance Authority of the State of New Hampshire (the "Issuer") proposes to issue, pursuant to a Loan and Trust Agreement, dated as of December 1, 1992 (as supplemented or amended from time to time with the written consent of the Issuing Bank, the "Indenture"), by and among the Issuer, the Account Party and BayBank, as trustee (such entity, or its successor as trustee, being the "Trustee"), $21,000,000 aggregate principal amount of Business Finance Authority of the State of New Hampshire Pollution Control Refunding Revenue Bonds (The Connecticut Light and Power Company Project - 1992 Series A) (the "Bonds") and, pursuant to the Indenture, the Account Party has requested the Issuing Bank to issue the letter of credit referred to therein in favor of the Paying Agent described therein. The Issuing Bank has agreed to issue such letter of credit subject to the terms and conditions set forth in that certain Letter of Credit and Reimbursement Agreement, of even date herewith, among the Account Party, the Issuing Bank, the Agent and the Participating Banks referred to therein and relating to the Bonds (said Letter of Credit and Reimbursement Agreement, as it may hereafter be amended, modified or supplemented from time to time, being hereinafter referred to as the "Reimbursement Agreement"). It is a condition precedent to the obligation of the Issuing Bank to issue such letter of credit and of the Participating Banks to make the Advances described in the Reimbursement Agreement that the Account Party shall have made the pledge described in this Agreement. NOW THEREFORE, in consideration of the premises and to induce the Issuing Bank to issue such letter of credit and to induce the Participating Banks to make such Advances, the Account Party hereby agrees as follows (capitalized terms used herein and not otherwise defined herein having the meanings assigned them in the Reimbursement Agreement): SECTION 1. Pledge. The Account Party hereby pledges to the Issuing Bank for the benefit of the Agent and the Participating Banks, and grants to the Issuing Bank for the benefit of the Agent and the Participating Banks a security interest in, the following (the "Pledged Collateral"): (i) the Pledged Bonds (as defined in the Indenture) and the instruments, if any, evidencing the Pledged Bonds, and all interest, cash, instruments and other property from time to time received, receivable or otherwise distributed in respect of or in exchange for any or all of the Pledged Bonds; and (ii) all proceeds (other than the proceeds of the initial sale upon issuance of the Pledged Bonds) of any and all of the foregoing collateral (including, without limitation, proceeds that constitute property of the types described above). SECTION 2. Security for Obligations. This Agreement secures the payment of all obligations of the Account Party now or hereafter existing under the Reimbursement Agreement, whether for reimbursement, principal, interest, fees, expenses or otherwise, and all obligations of the Account Party now or hereafter existing under this Agreement (all such obligations of the Account Party being the "Obligations"). Without limiting the generality of the foregoing, this Agreement secures the payment of all amounts which constitute part of the Obligations and would be owed by the Account Party to the Issuing Bank, the Agent or any Participating Bank under the Reimbursement Agreement but for the fact that they are unenforceable or not allowable due to the existence of a bankruptcy, reorganization or similar proceeding involving the Account Party. SECTION 3. Delivery of Pledged Collateral. (a) All certificates or instruments representing or evidencing the Pledged Collateral shall be delivered to the Paying Agent and held by the Paying Agent on behalf of the Issuing Bank pursuant hereto and shall be in suitable form for transfer by delivery, or shall be accompanied by duly executed instruments of transfer or assignment in blank, all in form and substance satisfactory to the Issuing Bank. For the better perfection of the Issuing Bank's, the Agent's and the Participating Banks' rights in and to the Pledged Collateral, the Account Party shall forthwith, upon the pledge of any Pledged Collateral hereunder, cause such Pledged Collateral to be registered in the name of such nominee or nominees of the Issuing Bank as the Issuing Bank shall direct. (b) If, prior to the payment in full of the Obligations and the termination of the Letter of Credit, the Account Party shall become entitled to receive or shall receive any payment in respect of the Pledged Collateral, the Account Party agrees to accept the same as the agent of the Issuing Bank, the Agent and the Participating Banks, to hold the same in trust for the Issuing Bank, the Agent and the Participating Banks and to deliver the same to the Issuing Bank. All such sums so received by the Issuing Bank shall be credited against the Obligations in such order as the Agent shall, in its sole discretion, elect. (c) Notwithstanding the foregoing subsection (a), if and for so long as the Bonds are to be held in the Book-Entry Only System (as defined in the Indenture), the Account Party's obligations under such subsection shall be deemed satisfied if such Pledged Bonds are (i) registered in the name of DTC (as defined in the Indenture) in accordance with the Book-Entry Only System, (ii) credited on the books of DTC to the account of the Paying Agent (or its nominee) and (iii) further credited on the books of the Paying Agent (or such nominee) to the account of the Issuing Bank (or its nominee). SECTION 4. Representations and Warranties. The Account Party represents and warrants as follows: (a) The pledge of the Pledged Collateral pursuant to this Agreement creates, upon the Paying Agent's taking possession of the Pledged Bonds pursuant to Section 3 hereof (whether by physical possession or by means of registration to DTC and book-entry credit as described in subsection (c) thereof), a valid and perfected first priority security interest in the Pledged Collateral, securing the payment of the Obligations. (b) No consent of any other person or entity and no authorization, approval, or other action by, and no notice to or filing with, any governmental authority or regulatory body is required (i) for the pledge by the Account Party of the Pledged Collateral pursuant to this Agreement or for the execution, delivery or performance of this Agreement by the Account Party, (ii) for the perfection or maintenance of the security interest created hereby (including the first priority nature of such security interest), other than any filings of Uniform Commercial Code financing statements that may be required for such perfection with respect to any "proceeds" of the Pledged Bonds, or (iii) for the exercise by the Issuing Bank of the voting or other rights provided for in this Agreement or the remedies in respect of the Pledged Collateral pursuant to this Agreement (except as may be required in connection with any disposition of any portion of the Pledged Collateral by laws affecting the offering and sale of securities generally and except for such as have already been obtained and are in full force and effect). SECTION 5. Further Assurances. The Account Party agrees that at any time and from time to time, at the expense of the Account Party, the Account Party will promptly execute and deliver all further instruments and documents, and take all further action, that may be necessary or desirable, or that the Issuing Bank may reasonably request, in order to perfect and protect any security interest granted or purported to be granted hereby or to enable the Issuing Bank to exercise and enforce its rights and remedies hereunder with respect to any Pledged Collateral. SECTION 6. Release. In the event that any Pledged Bonds are subsequently remarketed by the Remarketing Agent and the proceeds thereof, when added to any amounts paid to the Issuing Bank and/or the Agent by the Account Party, are sufficient to (a) reimburse the Issuing Bank and the Participating Banks in full for the drawing under the Letter of Credit pursuant to which such Pledged Bonds became Pledged Bonds, (b) repay or prepay any demand loan or Advance made in respect thereof and (c) pay all interest, fees and other amounts accrued in respect thereof pursuant to the Reimbursement Agreement, the lien of this Agreement shall be released as to such Pledged Bonds (but not as to any other Pledged Bonds). SECTION 7. Transfers and Other Liens. The Account Party agrees that it will not (i) sell, assign or otherwise dispose of, or grant any option with respect to, any of the Pledged Collateral, or (ii) create or permit to exist any lien, security interest, option or other charge or encumbrance upon or with respect to any of the Pledged Collateral, except for the security interest under this Agreement. SECTION 8. Bank Appointed Attorney-in-Fact. The Account Party hereby appoints the Issuing Bank the Account Party's attorney-in-fact, with full authority in the place and stead of the Account Party and in the name of the Account Party or otherwise, from time to time in the Issuing Bank's discretion to take any action and to execute any instrument which the Issuing Bank may deem necessary or advisable to accomplish the purposes of this Agreement, including, without limitation, to receive, indorse and collect all instruments made payable to the Account Party representing any interest payment or other distribution in respect of the Pledged Collateral or any part thereof and to give full discharge for the same. SECTION 9. Bank May Perform. If the Account Party fails to perform any agreement contained herein, the Issuing Bank may itself perform, or cause performance of, such agreement, and the expenses of the Issuing Bank incurred in connection therewith shall be payable by the Account Party under Section 10.04 of the Reimbursement Agreement. SECTION 10. The Issuing Bank's Duties. The powers conferred on the Issuing Bank hereunder are solely to protect its interest in the Pledged Collateral and shall not impose any duty upon it to exercise any such powers. Except for the safe custody of any Pledged Collateral in its actual possession and the accounting for moneys actually received by it hereunder, the Issuing Bank shall have no duty as to any Pledged Collateral, as to ascertaining or taking action with respect to calls, conversions, exchanges, maturities, tenders or other matters relative to any Pledged Collateral, whether or not the Issuing Bank has or is deemed to have knowledge of such matters, or as to the taking of any necessary steps to preserve rights against any parties or any other rights pertaining to any Pledged Collateral. The Issuing Bank shall be deemed to have exercised reasonable care in the custody and preservation of any Pledged Collateral in its actual possession if such Pledged Collateral is accorded treatment substantially equal to that which the Issuing Bank accords its own property. SECTION 11. Remedies upon Default. If any Event of Default shall have occurred and be continuing: (a) The Issuing Bank may exercise in respect of the Pledged Collateral, in addition to other rights and remedies provided for herein or otherwise available to it, all the rights and remedies of a secured party on default under the Uniform Commercial Code in effect in the State of New York at that time (the "Code") (whether or not the Code applies to the affected Pledged Collateral), and may also, without notice except as specified below, sell the Pledged Collateral or any part thereof in one or more parcels at public or private sale, at any exchange, broker's board or at any of the Issuing Bank's offices or elsewhere, for cash, on credit or for future delivery, and upon such other terms as the Issuing Bank may deem commercially reasonable. The Account Party agrees that, to the extent notice of sale shall be required by law, at least ten days' notice to the Account Party of the time and place of any public sale or the time after which any private sale is to be made shall constitute reasonable notification. The Issuing Bank shall not be obligated to make any sale of Pledged Collateral regardless of notice of sale having been given. The Issuing Bank may adjourn any public or private sale from time to time by announcement at the time and place fixed therefor, and such sale may, without further notice, be made at the time and place to which it was so adjourned. (b) Any cash held by the Issuing Bank as Pledged Collateral and all cash proceeds received by the Issuing Bank in respect of any sale of, collection from, or other realization upon all or any part of the Pledged Collateral may, in the discretion of the Issuing Bank, be held by the Issuing Bank as collateral for, and/or then or at any time thereafter be applied (after payment of any amounts payable to the Issuing Bank pursuant to Section 9 hereof and/or Section 10.04 of the Reimbursement Agreement) in whole or in part by the Issuing Bank against, all or any part of the Obligations in such order as the Issuing Bank shall elect. Any surplus of such cash or cash proceeds held by the Issuing Bank and remaining after payment in full of all the Obligations shall be paid over to the Account Party or to whomsoever may be lawfully entitled to receive such surplus. SECTION 12. Continuing Security Interest; Assignments. This Agreement shall create a continuing security interest in the Pledged Collateral and shall (i) remain in full force and effect until the later of (x) the payment in full of the Obligations and all other amounts payable under this Agreement and (y) the expiration or termination of the Commitments, (ii) be binding upon the Account Party, its successors and assigns, and (iii) inure to the benefit of, and be enforceable by, the Issuing Bank, the Agent, the Participating Banks and their respective successors, transferees and assigns. Without limiting the generality of the foregoing clause (iii), any Participating Bank may, subject to Section 10.06 of the Reimbursement Agreement, assign or otherwise transfer all or any portion of its rights and obligations under the Reimbursement Agreement (including, without limitation, all or any portion of its Commitment and the Advances owing to it) to any other person or entity, and such other person or entity shall thereupon become vested with all the benefits in respect thereof granted to such Participating Bank herein or otherwise. Upon the later of the payment in full of the Obligations and all other amounts payable under this Agreement and the expiration or termination of the Commitments, the security interest granted hereby shall terminate and all rights to the Pledged Collateral shall revert to the Account Party. Upon any such termination, the Issuing Bank will, at the Account Party's expense, return to the Account Party such of the Pledged Collateral as shall not have been sold or otherwise applied pursuant to the terms hereof and execute and deliver to the Account Party such documents as the Account Party shall reasonably request to evidence such termination. IN WITNESS WHEREOF, the Account Party has caused this Agreement to be duly executed and delivered by its officer thereunto duly authorized as of the date first above written. THE CONNECTICUT LIGHT AND POWER COMPANY, as Account Party and pledgor By Title: CANADIAN IMPERIAL BANK OF COMMERCE, NEW YORK AGENCY, as Issuing Bank and pledgee By Title: EX-4.4 5 NAEC TERM CREDIT AGREEMENT EXHIBIT 4.5.2 [EXECUTION COPY] U.S. $225,000,000 TERM CREDIT AGREEMENT Dated as of November 9, 1995 Among NORTH ATLANTIC ENERGY CORPORATION as Borrower THE BANKS NAMED HEREIN as Banks THE FIRST NATIONAL BANK OF CHICAGO BARCLAYS BANK PLC THE FIRST NATIONAL BANK OF BOSTON UNION BANK as Arrangers THE FIRST NATIONAL BANK OF CHICAGO as Administrative Agent TERM CREDIT AGREEMENT Dated as of November 9, 1995 THIS TERM CREDIT AGREEMENT (the "Agreement") is made by and among: (i) NORTH ATLANTIC ENERGY CORPORATION, a corporation duly organized and validly existing under the laws of the State of New Hampshire (the "Borrower"); (ii) The financial institutions (the "Banks") listed on the signature pages hereof and the other Lenders (as hereinafter defined) from time to time party hereto; (iii) THE FIRST NATIONAL BANK OF CHICAGO ("First Chicago"), BARCLAYS BANK PLC ("Barclays"), THE FIRST NATIONAL BANK OF BOSTON ("Bank of Boston") and UNION BANK ("Union"), as the Arrangers hereof; and (iv) First Chicago as administrative agent (the "Administrative Agent") for the Lenders hereunder. PRELIMINARY STATEMENT The Borrower wishes to redeem its outstanding 15.23% Notes Due July, 2000 (the Existing Notes). Subject to the conditions and upon the terms of this Agreement and the Notes referred to herein, the Borrower wishes to borrow, and the Banks have agreed, severally and not jointly, to lend, an aggregate amount of up to $225,000,000 to finance all or a portion of the redemption price of the Existing Notes. Based upon the foregoing and subject to the conditions and upon the terms set forth in this Agreement, the parties agree as follows: ARTICLE I DEFINITIONS AND ACCOUNTING TERMS SECTION 1.01 Certain Defined Terms. As used in this Agreement, the following terms shall have the following meanings (such meanings to be applicable to the singular and plural forms of the terms defined): "Adjusted Net Income" of the Borrower, for any period, means the Borrower's net income for such period, determined in accordance with general- ly accepted accounting principles on a basis consistent with the standards referred to in Section 1.03 hereof, and: (i) increased by the amount of current and deferred federal and state income taxes for such period (calculated on a basis consistent with footnote 5 to the Borrower's financial statements included in its 1994 Annual Report); (ii) decreased by the amount of Income Taxes-credit (as included under "Other Income") for such period; and (iii) increased by the Borrower's Interest Expense for such period. "Advance" means an Advance by a Lender to the Borrower pursuant to Section 3.01 hereof, and refers to a Base Rate Advance or a Eurodollar Rate Advance (each of which shall be a "Type" of Advance). The Type of an Advance may change from time to time as and when such Advance is Converted. For purposes of this Agreement, all Advances of a Lender (or portions thereof) made of, or Converted into, the same Type and Interest Period on the same day shall be deemed to be a single Advance by such Lender until repaid or next Converted. "Affiliate" means, with respect to any Person, any other Person directly or indirectly controlling (including, but not limited to all directors and officers of such Person), controlled by, or under direct or indirect common control with such Person. A Person shall be deemed to control another entity if such Person possesses, directly or indirectly, the power to direct or cause the direction of the management and policies of such entity, whether through the ownership of voting securities, by contract or otherwise. "Alternate Base Rate" means, for any Interest Period or any other period, a fluctuating interest rate per annum equal at all times to the highest from time to time of: (a) the rate of interest announced publicly by First Chicago, Chicago, Illinois, from time to time, as First Chicago's corporate base rate; and (b) 1/2 of one percent per annum above the Federal Funds Rate from time to time. Each change in the Alternate Base Rate shall take effect concurrently with any change in such base rate or Federal Funds Rate. "Applicable Lending Office" means, with respect to each Lender, (1)(A) such Lender's "Domestic Lending Office" in the case of a Base Rate Advance, and (B) such Lender's "Eurodollar Lending Office" in the case of a Eurodollar Rate Advance, in each case as specified opposite such Lender's name on Schedule I hereto or in the Lender Assignment pursuant to which it became a Lender, or (ii) such other office or affiliate of such Lender as such Lender may from time to time specify to the Borrower and the Administrative Agent. "Applicable Margin" means, on any date for any Eurodollar Rate Advance, the applicable percentage per annum set forth below, based on the then Applicable Rating Level. Level 1 Level 2 Level 3 Level 4 0.80% 1.00% 1.375% 1.75% Any change in the Applicable Margin caused by a change in the Applicable Rating Level shall take effect immediately upon such change in the Applicable Rating Level. "Applicable Rate" means: (i) in the case of each Base Rate Advance, a rate per annum equal at all times to the Alternate Base Rate in effect from time to time; and (ii) in the case of each Eurodollar Rate Advance comprising part of the same Borrowing, a rate per annum during each Interest Period equal at all times to the sum of the Eurodollar Rate for such Interest Period plus the Applicable Margin in effect from time to time during such Interest Period. "Applicable Rating Level" on any date for any Eurodollar Rate Advance, shall be determined in accordance with the following table on the basis of the ratings of Moody's and S&P, respectively, then applicable to the First Mortgage Bonds of PSNH: Level 1 Level 2 Level 3 Level 4 Baa3 and BBB- Ba1/BB+ Ba2/BB Below Ba2 or or higher Below BB In the event of a "split" rating, the Applicable Rating Level shall be determined on the basis of the lower of the two ratings (and, if applicable, the higher Applicable Rating Level and Applicable Margin). The Applicable Rating Level shall be redetermined as and when any change in the ratings used in the determination thereof shall be announced by either Moody's or S&P. "Authorized Replacement First Mortgage Bonds" shall have the meaning assigned to that term in Section 7.02(c). "Base Rate Advance" means an Advance in respect of which the Borrower has selected in accordance with Article III hereof, or this Agreement otherwise provides for, interest to be computed on the basis of the Alternate Base Rate. "Borrowing" means a borrowing consisting of Advances of the same Type and Interest Period made on the same day by the Lenders, ratably in accor- dance with their respective Commitments. For purposes of this Agreement: (i) each Borrowing shall be deemed to be of the same "Type" as the Advances comprising such Borrowing, and (ii) all Advances made of, or Converted into, the same Type and Interest Period on the same day shall be deemed a single Borrowing hereunder until repaid or next Converted. "Business Day" means a day of the year on which banks are not required or authorized to close in New York City, or Chicago, Illinois and, if the applicable Business Day relates to any Eurodollar Rate Advance, on which dealings are carried on in the London interbank market. "Closing Date" means the day upon which each of the conditions precedent enumerated in Section 5.01 hereof shall be fulfilled to the satisfaction of the Lenders, the Administrative Agent and the Borrower. All transactions contemplated to occur on the Closing Date shall take place on or prior to December 31, 1995, at the offices of King & Spalding, 120 West 45th Street, New York, New York 10036, at 10:00 A.M. (New York City time), or such other place and time as the parties hereto may mutually agree. "Commitment" means, for each Lender, the amount set forth opposite such Lender's name on Schedule IV hereto, or, if such Lender has entered into one or more Lender Assignments, set forth for such Lender in the Register maintained by the Administrative Agent pursuant to Section 10.07(c), in each such case as such amount may be reduced from time to time pursuant to Section 2.03 hereof. "Commitments" shall refer to the aggregate of the Lenders' Commitments hereunder. "Common Equity" means, as of any day, the aggregate of all amounts that would, in accordance with generally accepted accounting principles applied on a basis consistent with the standards referred to in Section 1.03 hereof, appear on the balance sheet of the Borrower as of such day as the sum of (i) the aggregate of the par value of, or stated capital represented by, the outstanding shares of common stock of the Borrower and the surplus, paid-in, earned and other, if any, of the Borrower. "Common Equity Ratio" means, as of any day, the ratio of (i) Common Equity as of such day to (ii) Total Capitalization as of such day. "Confidential Information" has the meaning assigned to that term in Section 10.08. "Conversion", "Convert" or "Converted" each refers to a conversion of Advances pursuant to Section 3.02, including, but not limited to any selec- tion of a longer or shorter Interest Period to be applicable to such Advances or any conversion of an Advance as described in Section 3.02(c). "Debt" means, for any Person, without duplication (including, for example, Debt evidenced by notes or securities that are supported by letters of credit and reimbursement obligations in respect of such letters of credit), (i) indebtedness of such Person for borrowed money, (ii) obligations of such Person evidenced by bonds, debentures, notes or other similar instruments, (iii) obligations of such Person to pay the deferred purchase price of property or services, (iv) obligations of such Person as lessee under leases which shall have been or should be, in accordance with generally accepted accounting principles, recorded as capital leases, (v) obligations (contingent or otherwise) of such Person under reimbursement or similar agreements with respect to the issuance of letters of credit, (vi) net obligations (contingent or otherwise) of such Person under interest rate swap, "cap", "collar" or other hedging agreements, (vii) obligations under direct or indirect guaranties in respect of, and obligations (contingent or otherwise) to purchase or otherwise acquire, or otherwise to assure a creditor against loss in respect of, indebtedness or obligations of others of the kinds referred to in clauses (i) through (vi), above, and (viii) liabili- ties in respect of unfunded vested benefits under ERISA Plans. "Disclosure Documents" means the Information Memorandum, the Borrower's 1994 Annual Report, the Borrower's Annual Report on Form 10-K for the year ended December 31, 1994, the Borrower's Quarterly Reports on Form 10-Q for the quarters ended March 31 and June 30, 1995, any Current Report on Form 8-K of the Borrower filed by the Borrower with the Securities and Exchange Commission after June 30, 1995 and furnished to the Banks prior to the execution and delivery of this Agreement, and the Disclosure Letter. "Disclosure Letter" means that certain Memorandum, dated November 7, 1995, prepared by Robert A. Bersak, Assistant Secretary and Assistant General Counsel of PSNH and transmitted to the Arrangers and the Banks by letter, dated November 7, 1995, from David McHale, Assistant Treasurer, of NUSCO. "ERISA" means the Employee Retirement Income Security Act of 1974, as amended from time to time. "ERISA Affiliate" means, with respect to any Person, any trade or business (whether or not incorporated) which is a "commonly controlled entity" of the Borrower within the meaning of the regulations under Section 414 of the Internal Revenue Code of 1986, as amended from time to time. "ERISA Multiemployer Plan" means a "multiemployer plan" subject to Title IV of ERISA. "ERISA Plan" means an employee benefit plan (other than an ERISA Multiemployer Plan) maintained for employees of the Borrower or any ERISA Affiliate and covered by Title IV of ERISA. "ERISA Plan Termination Event" means (i) a Reportable Event described in Section 4043 of ERISA and the regulations issued thereunder (other than a Reportable Event not subject to the provision for 30-day notice to the PBGC under such regulations) with respect to an ERISA Plan or an ERISA Multiemployer Plan, or (ii) the withdrawal of the Borrower or any of its ERISA Affiliates from an ERISA Plan or an ERISA Multiemployer Plan during a plan year in which it was a "substantial employer" as defined in Section 4001(a)(2) of ERISA, or (iii) the filing of a notice of intent to terminate an ERISA Plan or an ERISA Multiemployer Plan or the treatment of an ERISA Plan or an ERISA Multiemployer Plan under Section 4041 of ERISA, or (iv) the institution of proceedings to terminate an ERISA Plan or an ERISA Multiemployer Plan by the PBGC, or (v) any other event or condition which might constitute grounds under Section 4042 of ERISA for the termination of, or the appointment of a trustee to administer, any ERISA Plan or ERISA Multiemployer Plan. "Eurocurrency Liabilities" has the meaning assigned to that term in Regulation D of the Board of Governors of the Federal Reserve System, as in effect from time to time. "Eurodollar Rate" means, for each Interest Period for each Eurodollar Rate Advance comprising part of the same Borrowing, an interest rate per annum equal to the average (rounded upward to the nearest 1/100 of 1% per annum) of the rate per annum at which deposits in U.S. Dollars are offered by the principal office of each of the Reference Banks in London, England in the amount of such Reference Bank's Eurodollar Rate Advance to prime banks in the London interbank market at 11:00 A.M. (London time) two Business Days before the first day of such Interest Period and for a period equal to such Interest Period. The Eurodollar Rate for the Interest Period for each Eurodollar Rate Advance comprising part of the same Borrowing shall be determined by the Administrative Agent on the basis of the applicable rates (averaged as set forth above) furnished to and received by the Administrative Agent from the Reference Banks two Business Days before the first day of such Interest Period, subject, however, to the provisions of Sections 3.05(d) and 4.03(g). "Eurodollar Rate Advance" means an Advance in respect of which the Borrower has selected in accordance with Article III hereof, and this Agreement provides for, interest to be computed on the basis of the Eurodol- lar Rate. "Eurodollar Reserve Percentage" of any Lender for each Interest Period for each Eurodollar Rate Advance means the reserve percentage applicable during such Interest Period (or if more than one such percentage shall be so applicable, the daily average of such percentages for those days in such Interest Period during which any such percentage shall be so applicable) under Regulation D or other regulations issued from time to time by the Board of Governors of the Federal Reserve System (or any successor) for determining the maximum reserve requirement (including, without limitation, any emergen- cy, supplemental or other marginal reserve requirement, without benefit of or credit for proration, exemptions or offsets) for such Lender with respect to liabilities or assets consisting of or including Eurocurrency Liabilities having a term equal to such Interest Period. "Event of Default" has the meaning specified in Section 8.01. "Existing Notes" has the meaning assigned to that term in the Prelimi- nary Statement. "Federal Funds Rate" means, for any period, a fluctuating interest rate per annum equal for each day during such period to the weighted average of the rates on overnight Federal funds transactions with members of the Federal Reserve System arranged by Federal funds brokers, as published on the next succeeding Business Day by the Federal Reserve Bank of New York, or, if such rate is not so published on the next succeeding Business Day the average of the quotations for such day on such transactions received by the Administra- tive Agent from three Federal funds brokers of recognized standing selected by it. "First Mortgage Bonds" means first mortgage bonds of the Borrower issued or to be issued pursuant to that certain First Mortgage Indenture and Deed of Trust, dated as of June 1, 1992, between the Borrower and United States Trust Company of New York, as trustee (together with any successor, the "First Mortgage Trustee"), as the same may be amended, modified and supplemented from time to time (the "First Mortgage Indenture"). "Funding Date" means the date for the initial borrowing of the Advances and the payment of the redemption price of the Existing Notes, as notified by the Borrower to the Administrative Agent at least five Business Days prior to such date in accordance with Sections 3.01 and 5.02; provided, however, that the Funding Date shall in any event occur: (i) on or after the Closing Date, (ii) not later than 35 days following the Closing Date and (iii) not later than December 31, 1995. "Governmental Approval" means any authorization, consent, approval, license, permit, certificate, exemption of, or filing or registration with, any governmental authority or other legal or regulatory body, including any renewal thereof. For purposes of this Agreement, Chapter 362-C of the Revised Statutes Annotated of New Hampshire, in effect on the date hereof, shall be deemed to be a Governmental Approval. "Hazardous Substance" means any waste, substance or material identified as hazardous or toxic by any office, agency, department, commission, board, bureau or instrumentality of the United States of America or of the State or locality in which the same is located having or exercising jurisdiction over such waste, substance or material. "Indemnified Person" has the meaning assigned to that term in Section 10.04(b) hereof. "Information Memorandum" means the Confidential Information Memorandum, dated August 28, 1995, regarding the Borrower, as distributed to the Adminis- trative Agent, the Arrangers and the Lenders. "Interest Coverage Ratio" means, for any period, the ratio of (i) Adjusted Net Income for such period to (ii) Interest Expense for such period. "Interest Expense" means, for any period, the aggregate interest expense of the Borrower for such period, determined in accordance with generally accepted accounting principles on a basis consistent with the standards referred to in Section 1.03 hereof. "Interest Period" has the meaning assigned to that term in Section 3.05(a) hereof. "Joint Ownership Agreement" means the Agreement for Joint Ownership, Construction and Operation of New Hampshire Nuclear Units, among PSNH and the other parties named therein, dated as of May 1, 1973, as amended from time to time. "Lender Assignment" means an assignment and agreement entered into by a Lender and an assignee, and accepted by the Administrative Agent, in substan- tially the form of Exhibit 10.07 hereto. "Lenders" means the financial institutions listed on the signature pages hereof, and each assignee that shall become a party hereto pursuant to Section 10.07(a). "Lien" has the meaning assigned to that term in Section 7.02(a) hereof. "Loan Documents" means this Agreement and the Notes. "Majority Lenders" means on any date of determination, Lenders who, collectively, on such date (i) hold at least 66-2/3% of the then aggregate unpaid principal amount of the Advances owing to the Lenders or (ii) if no Advances are then outstanding, represent at least 66-2/3% of the Commitments. Determination of those Lenders satisfying the criteria specified above for action by the Majority Lenders shall be made by the Administrative Agent and shall be conclusive and binding on all parties absent manifest error. "Moody's" means Moody's Investors Service, Inc., or any successor thereto. "1994 Annual Report" means the 1994 Annual Report of the Borrower included in the Borrower's Annual Report on Form 10-K for the year ended December 31, 1994. "Note" means a promissory note of the Borrower payable to the order of a Lender, in substantially the form of Exhibit 1.01A hereto, evidencing the aggregate indebtedness of the Borrower to such Lender resulting from the Advances made by such Lender. "NU" means Northeast Utilities, an unincorporated voluntary business association organized under the laws of the Commonwealth of Massachusetts. "NUSCO" means Northeast Utilities Service Company, a Connecticut corporation and a wholly-owned subsidiary of NU. "PBGC" means the Pension Benefit Guaranty Corporation (or any successor entity) established under ERISA. "Permitted Investments" means each and any of the following; provided that no such Permitted Investment shall have a final maturity not later than 12 months from the date of investment therein. (i) direct obligations of the United States of America, or obligations guaranteed as to principal and interest by the United States of America; (ii) certificates of deposit, eurodollar certificates of deposit or bankers' acceptances issued, or time deposits held, or investment contracts guaranteed, by (A) any Bank; or (B) any other commercial bank, trust company, savings and loan association or savings bank organized under the laws of the United States of America, or any State thereof, or of any other country which is a member of the Organization for Economic Cooperation and Development (or a political subdivision of any such country) having outstanding unsecured indebtedness that is rated (on the date of acquisition thereof) AA- or better by S&P or Aa3 or better by Moody's (or an equivalent rating by another nationally recognized credit rating agency of similar standing if neither of such corporations is then in the business of rating unsecured bank indebted- ness); (iii) obligations with any Arranger or any other bank or trust company described in clause (ii), above, in respect of the repurchase of obligations of the type described in clause (i), above, provided that such repurchase obligations shall be fully secured by obligations of the type described in said clause (i) and the possession of such obligations shall be transferred to, and segregated from other obligations owned by, such Arranger or such other bank or trust company; (iv) commercial paper rated (on the date of acquisition thereof) A-1 or P-1 or better by S&P or Moody's, respectively (or an equivalent rating by another nationally recognized credit rating agency of similar standing if neither of such corporations is then in the business of rating commercial paper). (v) deposits with or loans to the NU System Money Pool on the terms and conditions from time to time applicable to other participants therein, but in no event on terms less favorable to the Borrower than are applicable to such other participants. (vi) investments in securities of industrial and other nonutility local enterprises described in Rule 40(a)(5) under PUHCA; provided, however, that the total amount invested shall not exceed (i) $1,000,000 in any calendar year and (ii) $5,000,000 at any one time outstanding. "Permitted Liens" has the meaning ascribed to that term in Section 7.02(a). "Person" means an individual, partnership, corporation (including a business trust), joint stock company, trust, estate, unincorporated associa- tion, joint venture or other entity, or a government or any political subdivision or agency thereof. "Pre-Funding Exposure Fee" has the meaning assigned that term in Section 2.02(b). "PSNH" means Public Service Company of New Hampshire, a corporation organized under the laws of the State of New Hampshire. "PUHCA" means the Public Utility Holding Company Act of 1935, as amended. "Rate Agreement" means the Agreement dated as of November 22, 1989, as amended by the First Amendatory Agreement dated as of December 5, 1989, the Second Amendatory Agreement dated as of December 12, 1989, the Third Amend- ment to Rate Agreement dated as of December 28, 1993, the Fourth Amendment to Rate Agreement dated as of September 21, 1994 and the Fifth Amendment to Rate Agreement dated as of September 9, 1994, among NUSCO, the Governor and Attorney General of the State of New Hampshire and adopted by PSNH as of July 10, 1990 (but excluding the Unit Contract appended as Exhibit A thereto). "Recipient" has the meaning assigned to that term in Section 10.08 hereof. "Reference Banks" means, initially, First Chicago, Barclays, Bank of Boston and Union, and shall include any other or different Lender(s) as may from time to time agree to act as Reference Banks hereunder with the consent of the Borrower. "Register" has the meaning specified in Section 10.07(c). "S&P" means Standard & Poor's Rating Group or any successor thereto. "Seabrook" means the nuclear-fueled, steam-electric generating plant at a site located in Seabrook, New Hampshire, and all real property interests, fixtures, and other assets related thereto. "Seabrook Interests" means all of the Borrower's right, title and interest in and to Seabrook, presently constituting 35.98201% of Seabrook. "Significant Contracts" means the Unit Contract and the Tax Allocation Agreement. "Tax Allocation Agreement" means the Tax Allocation Agreement dated as of January 1, 1990 among NU and the members of the consolidated group of which NU is the common parent, including the Borrower, as amended and as the same may be further amended, modified or supplemented in accordance with the terms hereof and thereof. "Termination Date" means the earliest to occur of November 9, 2000, (ii) December 31, 1995, if the Funding Date shall not have occurred on or prior to such date, (iii) the date of termination in whole of the Commitments pursuant to Section 8.02 or (iv) the date of acceleration of all amounts payable hereunder and under the Notes pursuant to Section 8.02. "Total Capitalization" means, as of any day, the aggregate of all amounts that would, in accordance with generally accepted accounting princi- ples applied on a basis consistent with the standards referred to in Section 1.03 hereof, appear on the balance sheet of the Borrower as of such day as the sum of (i) the principal amount of all long-term Debt of the Borrower on such day (including the current portion thereof), (ii) the par value of, or stated capital represented by, the outstanding shares of all classes of common and preferred shares of the Borrower on such day and (iii) the surplus of the Borrower, paid-in, earned and other, if any, on such day. "Type" has the meaning assigned to such term (i) in the definition of "Advance" when used in such context and (ii) in the definition of "Borrowing" when used in such context. "Unit Contract" means the Unit Contract, dated as of June 1, 1992, between the Borrower and PSNH, as the same may from time to time be amended, modified or supplemented in accordance with the terms hereof and thereof. "Unmatured Default" means the occurrence and continuance of an event which, with the giving of notice or lapse of time or both, would constitute an Event of Default. SECTION 1.02 Computation of Time Periods. In the computation of periods of time under this Agreement any period of a specified number of days or months shall be computed by including the first day or month occurring during such period and excluding the last such day or month. In the case of a period of time "from" a specified date "to" or "until" a later specified date, the word "from" means "from and including" and the words "to" and "until" each means "to but excluding". SECTION 1.03 Accounting Terms. All accounting terms not specifically defined herein shall be construed in accordance with generally accepted accounting principles applied on a basis consistent with the financial statements included in the Borrower's 1994 Annual Report, except for such changes, if any, as are consistent with generally accepted accounting principles and are disclosed to the Lenders. Any such change that would affect the calculation of any figure or ratio contained in any covenant or agreement herein to be performed or observed by the Borrower shall be disregarded for such purpose unless and until the Borrower and the Majority Lenders shall have agreed upon a replacement figure or ratio that, after giving effect to such change, reflects the original intent of the parties. The parties agree to negotiate in good faith to reach any such agreement. SECTION 1.04 Computations of Outstandings. Whenever reference is made in this Agreement to the principal amount outstanding on any date under this Agreement, such reference shall refer to the sum of the aggregate principal amount of all Advances outstanding on such date, after giving effect to all Advances to be made on such date and the application of the proceeds thereof. ARTICLE II COMMITMENTS SECTION 2.01 The Commitments. Each Lender severally agrees, on the terms and conditions hereinafter set forth, to make Advances to the Borrower on the Funding Date in an aggregate amount not to exceed such Lender's Commitment. In no event may any Advance repaid or prepaid hereunder be reborrowed. SECTION 2.02 Fees. (a) The Borrower agrees to pay to the Administra- tive Agent for the account of the Lenders, on the Closing Date, certain fees as specified in the materials accompanying the distribution of the Informa- tion Memorandum. (b) The Borrower agrees to pay to the Administrative Agent for the account of each Lender a fee (the "Pre-Funding Exposure Fee") on each Lender's Commitment for the period from the Closing Date to the Funding Date (or, if earlier, the Termination Date), such Pre-Funding Exposure Fee to be computed at a rate per annum equal to 0.75% and to be payable on the Funding Date (or, if earlier, the Termination Date). (c) The Borrower agrees to pay to the Arrangers and the Administrative Agent, for their respective accounts, such other fees in such amounts and payable at such times, as agreed among them from time to time in writing. SECTION 2.03 Termination of the Commitments. (a) The Commitment of each Lender shall automatically terminate upon the first to occur of (i) the making of the Advances and (ii) 5:00 P.M. (New York City time) on December 31, 1995. ARTICLE III AMOUNTS AND TERMS OF THE ADVANCES SECTION 3.01 Initial Funding. (a) All Borrowings (other than Borrowings resulting solely from Conversions) shall be made simultaneously on the Funding Date and shall consist of Advances of the same Type and Interest Period made on such day by the Lenders ratably according to their respective Commitments. The Borrower may request that more than one Borrowing, but no more than six Borrowings, be made on the Funding Date, within the limits of the Commitments. All such Borrowings shall be made on notice, given not later than 10:00 A.M. (New York City time) three Business Days prior to the date of the proposed Funding Date, by the Borrower to the Administrative Agent, who shall give to each Lender prompt notice thereof on the same day such notice is received. Each such notice of a Borrowing (a "Notice of Borrowing") shall be in substantially the form of Exhibit 3.01A hereto, specifying therein the requested (i) Funding Date, (ii) Type of Advances comprising such Borrowing and (iii) Interest Period for each such Advance. Each requested Borrowing shall be subject to the provisions of Sections 3.03, 4.03 and 5.02 hereof. (b) Each Lender shall, before 12:00 noon (New York City time) on the Funding Date, make available for the account of its Applicable Lending Office to the Administrative Agent at the Administrative Agent's address referred to in Section 10.02, in same day funds, such Lender's ratable portion of each Borrowing to be made on such date. After the Administrative Agent's receipt of such funds and upon fulfillment of the applicable conditions set forth in Section 5.02, the Administrative Agent will make such funds available to the Borrower at the Administrative Agent's aforesaid address. (c) Unless the Administrative Agent shall have received notice from a Lender prior to the Funding Date that such Lender will not make available to the Administrative Agent such Lender's ratable portion of all or any Borrowings to be made on such date, the Administrative Agent may assume that such Lender has made such portion available to the Administrative Agent on such date in accordance with subsection (b) of this Section 3.01 and the Administrative Agent may, in reliance upon such assumption, make available to the Borrower on such date a corresponding amount. If and to the extent that any such Lender (a "non-performing Lender") shall not have so made such ratable portion available to the Administrative Agent, the non-performing Lender and the Borrower severally agree to repay (but without duplication) to the Administrative Agent forthwith on demand such corresponding amount together with interest thereon, for each day from the date such amount is made available to the Borrower until the date such amount is repaid to the Administrative Agent, at (i) in the case of the Borrower, the interest rate applicable at the time to Advances comprising such Borrowing and (ii) in the case of such Lender, the Federal Funds Rate. Nothing herein shall in any way limit, waive or otherwise reduce any claims that any party hereto may have against any non-performing Lender. (d) The failure of any Lender to make the Advance to be made by it as part of any Borrowing shall not relieve any other Lender of its obligation, if any, hereunder to make its Advance as a part of such Borrowing, but no Lender shall be responsible for the failure of any other Lender to make the Advance to be made by such other Lender. SECTION 3.02 Conversion of Advances. So long as no Event of Default shall have occurred and be continuing, the Borrower may from time to time after the Funding Date elect to Convert any one or more Advances of any Type to one or more Advances of the same or any other Type on the following terms and subject to the following conditions: (a) Each such Conversion shall be made as to all Advances comprising a single Borrowing, on notice given not later than 10:00 A.M. (New York City time) on the third Business Day prior to the date of the proposed Conversion by the Borrower to the Administrative Agent, who shall give to each Lender prompt notice thereof. Each such notice of Conversion (a "Notice of Conver- sion") shall be in substantially the form of Exhibit 3.02A hereto, specifying therein the requested (i) date of such Conversion, (ii) Type of, and Interest Period applicable to, the Advances proposed to be Converted, (iii) except in the case of a Conversion described in subsection (c) below, Type of Advances to which such Advances are proposed to be Converted, (iv) except in the case of a Conversion to Base Rate Advances, the initial Interest Period to be applicable to the Advances resulting from such Conversion and (v) aggregate amount of Advances proposed to be Converted. No Conversion may be requested by the Borrower hereunder (and no Notice of Conversion shall be effective) unless made in compliance with Section 3.03 hereof. (b) The Borrower may not select an Interest Period of greater than one month (in the case of Conversions to Eurodollar Rate Advances) during the continuance of an Unmatured Default or an Event of Default. (c) If no Notice of Conversion in respect of an Advance is received by the Administrative Agent as provided in subsection (a) above with respect to any Eurodollar Rate Advance, the Administrative Agent shall treat such absence of notice as a deemed Notice of Conversion providing for each such Advance to be Converted to a Base Rate Advance on the last day of the Interest Period then in effect for such Advance. SECTION 3.03 Other Terms Relating to the Making and Conversion of Advances. (a) Notwithstanding anything in Section 3.01 or 3.02 above to the contrary: (i) at no time shall more than six different Borrowings be outstanding hereunder; (ii) each Borrowing hereunder which is to be comprised of Base Rate Advances shall be in an aggregate principal amount of no less than $1,000,000; (iii) each Borrowing hereunder which is to be comprised of Eurodol- lar Rate Advances shall be in the aggregate principal amount of $10,000,000 or an integral multiple of $1,000,000 in excess thereof. (b) Each Notice of Borrowing and Notice of Conversion shall be irrevocable and binding on the Borrower. SECTION 3.04 Repayment of Advances. The Borrower shall repay the entire principal amount of all Advances together with all accrued and unpaid interest thereon on the Termination Date. SECTION 3.05 Interest. (a) Interest Periods. The period between the date of each Advance and the date of payment in full of such Advance shall be divided into successive periods of months or days ("Interest Periods") for purposes of computing interest applicable thereto. The initial Interest Period for each Advance shall begin on the day such Advance is made, and each subsequent Interest Period shall begin on the last day of the immediately preceding Interest Period for such Advance. All Advances comprising part of the same Borrowing shall have the same Interest Period, as selected by the Borrower in accordance with this Section 3.05(a). The duration of each Interest Period shall be (i) in the case of any Base Rate Advance, until the earlier of repayment of such Advance in full or the Termination Date, and (ii) in the case of any Eurodollar Rate Advance, 1, 2, 3, or 6 months, in each case as the Borrower may, upon notice received by the Administrative Agent in accordance with Sections 3.01(a) and 3.02, select; provided, however, that the Borrower may not select any Interest Period which ends after the Termination Date. (b) Interest Rates. The Borrower shall pay interest on the unpaid principal amount of each Advance owing to each Lender from the date of such Advance until such principal amount shall be paid in full, at the Applicable Rate for such Advance (except as otherwise provided in this subsection (b)), payable as follows: (i) Base Rate Advances. If such Advance is a Base Rate Advance, interest thereon shall be payable quarterly in arrears on the last day of November, February, May and August in each year, commencing February, 1996, on the date such Base Rate Advance shall be paid in full and on the Termina- tion Date; provided that during the continuation of any Event of Default, each Base Rate Advance shall bear interest at a rate per annum equal to 2% per annum above the Applicable Rate in effect from time to time for Base Rate Advances. (ii) Eurodollar Rate Advances. If such Advance is a Eurodollar Rate Advance, interest thereon shall be payable on the last day of each Interest Period thereof and, if any such Interest Period has a duration of more than three months, also on the day of the third month during such Interest Period which corresponds to the first day of such Interest Period (or, if any such month does not have a corresponding day, then on the last day of such month); provided that during the continuation of an Event of Default, each Eurodollar Rate Advance shall bear interest at a rate per annum equal to the greater of (A) 2% per annum above the Applicable Rate for such Advance and (B) 2% per annum above the Alternate Base Rate. (c) Other Amounts. Any other amounts payable hereunder that are not paid when due shall (to the fullest extent permitted by law) bear interest, from the date when due until paid in full, at a rate per annum equal at all times to 2% per annum above the Alternate Base Rate, payable on demand. (d) Interest Rate Determinations. The Administrative Agent shall give prompt notice to the Borrower and the Lenders of the Applicable Rate deter- mined from time to time by the Administrative Agent for each Advance. Each Reference Bank agrees to furnish to the Administrative Agent timely informa- tion for the purpose of determining the Eurodollar Rate for any Interest Period. If any one Reference Bank shall not furnish such timely information, the Administrative Agent shall determine such interest rate on the basis of the timely information furnished by the remaining Reference Banks. ARTICLE IV PAYMENTS SECTION 4.01 Payments and Computations. (a) The Borrower shall make each payment hereunder and under the other Loan Documents not later than 1:00 P.M. (New York City time) on the day when due in U.S. Dollars to the Administrative Agent at its address referred to in Section 10.02 in same day funds. The Administrative Agent will promptly thereafter cause to be distributed like funds relating to the payment of principal, interest, fees or other amounts payable to the Lenders, to the respective Lenders to whom the same are payable, for the account of their respective Applicable Lending Offices, in each case to be applied in accordance with the terms of this Agreement. Upon its acceptance of a Lender Assignment and recording of the information contained therein in the Register pursuant to Section 10.07, from and after the effective date specified in such Lender Assignment, the Administrative Agent shall make all payments hereunder and under the Notes in respect of the interest assigned thereby to the Lender assignee thereunder, and the parties to such Lender Assignment shall make all appropriate adjust- ments in such payments for periods prior to such effective date directly between themselves. (b) The Borrower hereby authorizes the Administrative Agent, and each Lender, if and to the extent payment owed to the Administrative Agent, or such Lender, as the case may be, is not made when due hereunder (or, in the case of a Lender, under the Note held by such Lender), to charge from time to time against any or all of the Borrower's accounts with the Administrative Agent, or such Lender, as the case may be, any amount so due. (c) All computations of interest and other amounts pursuant to Section 4.03 shall be made by the Lender claiming such interest or amount, on the basis of a year of 360 days. All other computations of interest and fees hereunder shall be made by the Administrative Agent on the basis of a year of 360 days. In each such case, such computation shall be made for the actual number of days (including the first day, but excluding the last day) occur- ring in the period for which such interest, fees or other amounts are payable. Each such determination by the Administrative Agent or a Lender shall be conclusive and binding for all purposes, absent manifest error. (d) Whenever any payment hereunder or under any other Loan Document shall be stated to be due, or the last day of an Interest Period hereunder shall be stated to occur, on a day other than a Business Day, such payment shall be made and the last day of such Interest Period shall occur on the next succeeding Business Day, and such extension of time shall in such case be included in the computation of payment of interest and fees hereunder; provided, however, that if such extension would cause payment of interest on, or principal of, Eurodollar Rate Advances to be made, or the last day of an Interest Period for a Eurodollar Rate Advance to occur, in the next following calendar month, such payment shall be made on the next preceding Business Day and such reduction of time shall in such case be included in the computation of payment of interest hereunder. (e) Unless the Administrative Agent shall have received notice from the Borrower prior to the date on which any payment is due to the Lenders hereunder that the Borrower will not make such payment in full, the Adminis- trative Agent may assume that the Borrower has made such payment in full to the Administrative Agent on such date and the Administrative Agent may, in reliance upon such assumption, cause to be distributed to each Lender on such due date an amount equal to the amount then due such Lender. If and to the extent the Borrower shall not have so made such payment in full to the Administrative Agent, each such Lender shall repay to the Administrative Agent forthwith on demand such amount distributed to such Lender, together with interest thereon, for each day from the date such amount is distributed to such Lender until the date such Lender repays such amount to the Adminis- trative Agent, at the Federal Funds Rate. SECTION 4.02 Prepayments. (a) Generally. The Borrower shall have no right to prepay any principal amount of any Advances except in accordance with subsections (b) and (c) below. (b) Optional. The Borrower may, upon at least three Business Days' notice to the Administrative Agent stating the proposed date and aggregate principal amount of the prepayment, and if such notice is given the Borrower shall, prepay the outstanding principal amounts of Advances comprising part of the same Borrowing, in whole or ratably in part, together with accrued interest to the date of such prepayment on the principal amount prepaid and all other amounts, if any, payable in connection therewith pursuant to Section 4.03(d); provided, however, that each partial prepayment shall be in an aggregate principal amount not less than $10,000,000. (c) Mandatory. If, without the prior written consent of the Majority Lenders, either of the Unit Contract or the Tax Allocation Agreement is terminated or invalidated or if the terms thereof are amended or modified (except, in the case of the Tax Allocation Agreement, for such amendments and modifications as may be required by applicable law) and the Majority Lenders in their reasonable discretion determine that such amendment or modification is adverse to the interests of the Lenders, the entire aggregate principal amount of all Advances then outstanding, together with all unpaid interest and other accrued and unpaid amounts in respect thereof, shall become immediately due and payable, and the Borrower shall immediately prepay all such Advances, interest, fees and other amounts. SECTION 4.03 Yield Protection. (a) Change in Circumstances. Notwithstanding any other provision herein, if after the date hereof, the adoption of or any change in applicable law or regulation or in the interpretation or administration thereof by any governmental authority charged with the interpretation or administration thereof (whether or not having the force of law) shall (i) change the basis of taxation of payments to any Lender of the principal of or interest on any Eurodollar Rate Advance made by such Lender or any fees or other amounts payable hereunder (other than changes in respect of taxes imposed on the overall net income of such Lender or its Applicable Lending Office by the jurisdiction in which such Lender has its principal office or in which such Applicable Lending Office is located or by any political subdivision or taxing authority therein), or (ii) shall impose, modify or deem applicable any reserve, special deposit or similar requirement against commitments or assets of, deposits with or for the account of, or credit extended by, such Lender, or (iii) shall impose on such Lender or the London interbank market any other condition affecting this Agreement or Eurodollar Rate Advances made by such Lender, and the result of any of the foregoing shall be to increase the cost to such Lender of agreeing to make, making or maintaining any Advance or to reduce the amount of any sum received or receivable by such Lender hereunder or under the Notes (whether of principal, interest or otherwise), then the Borrower will pay to such Lender upon demand such additional amount or amounts as will compensate such Lender for such addi- tional costs incurred or reduction suffered. (b) Capital. If any Lender shall have determined that any change after the date hereof in any law, rule, regulation or guideline adopted pursuant to or arising out of the July 1988 report of the Basle Committee on Banking Regulations and Supervisory Practices entitled "International Convergence of Capital Measurement and Capital Standards", or the adoption after the date hereof of any other law, rule, regulation or guideline regarding capital adequacy, or any change in any of the foregoing or in the interpretation or administration of any of the foregoing by any governmental authority, central bank or comparable agency charged with the interpretation or administration thereof, or compliance by any Lender (or any Applicable Lending Office of such Lender) or any Lender's holding company with any request or directive regarding capital adequacy (whether or not having the force of law) of any such authority, central bank or comparable agency, has or would have the effect (i) of reducing the rate of return on such Lender's capital or on the capital of such Lender's holding company, if any, as a consequence of this Agreement, the Commitment of such Lender hereunder or the Advances made by such Lender pursuant hereto to a level below that which such Lender or such Lender's holding company could have achieved, but for such applicability, adoption, change or compliance (taking into consideration such Lender's policies and the policies of such Lender's holding company with respect to capital adequacy), or (ii) of increasing or otherwise determining the amount of capital required or expected to be maintained by such Lender or such Lender's holding company based upon the existence of this Agreement, the Commitment of such Lender hereunder, the Advances made by such Lender pursuant hereto and other similar such commitments, agreements or assets, then from time to time the Borrower shall pay to such Lender upon demand such additional amount or amounts as will compensate such Lender or such Lender's holding company for any such reduction or allocable capital cost suffered. (c) Eurodollar Reserves. The Borrower shall pay to each Lender upon demand, so long as such Lender shall be required under regulations of the Board of Governors of the Federal Reserve System to maintain reserves with respect to liabilities or assets consisting of or including Eurocurrency Liabilities, additional interest on the unpaid principal amount of each Eurodollar Rate Advance of such Lender, from the date of such Advance until such principal amount is paid in full, at an interest rate per annum equal at all times to the remainder obtained by subtracting (i) the Eurodollar Rate for the Interest Period for such Advance from (ii) the rate obtained by dividing such Eurodollar Rate by a percentage equal to 100% minus the Eurodollar Reserve Percentage of such Lender for such Interest Period. Such additional interest shall be determined by such Lender and notified to the Borrower and the Administrative Agent. (d) Breakage Indemnity. The Borrower shall indemnify each Lender against any loss, cost or reasonable expense which such Lender may sustain or incur as a consequence of (i) any failure by the Borrower to borrow or Convert any Advance hereunder after irrevocable Notice of Borrowing or Notice of Conversion has been given pursuant to Section 3.01 or 3.02, (ii) any payment, prepayment or Conversion of a Eurodollar Rate Advance required or permitted by any other provision of this Agreement or otherwise made or deemed made on a date other than the last day of the Interest Period applica- ble thereto, (iii) any default in payment or prepayment of the principal amount of any Advance or any part thereof or interest accrued thereon, as and when due and payable (at the due date thereof, by irrevocable notice of prepayment or otherwise) or (iv) the occurrence of any Event of Default, including, in each such case, any loss or reasonable expense sustained or incurred or to be sustained or incurred in liquidating or employing deposits from third parties acquired to effect or maintain such Advance or any part thereof as a Eurodollar Rate Advance. Such loss, cost or reasonable expense shall include an amount equal to the excess, if any, as reasonably determined by such Lender, of (A) its cost of obtaining the funds for the Advance being paid, prepaid, Converted or not borrowed (based on the Eurodollar Rate) for the period from the date of such payment, prepayment, Conversion or failure to borrow to the last day of the Interest Period for such Advance (or, in the case of a failure to borrow, the Interest Period for such Advance which would have commenced on the date of such failure) over (B) the amount of interest (as reasonably determined by such Lender) that would be realized by such Lender in reemploying the funds so paid, prepaid, Converted or not borrowed for such period or Interest Period, as the case may be. For purposes of this subsection (d), it shall be presumed that each Lender shall have funded each such Advance with a fixed-rate instrument bearing the rates and maturities designated in the determination of the Applicable Rate for such Advance. (e) Notices. A certificate of each Lender setting forth such Lender's claim for compensation hereunder and the amount necessary to compensate such Lender or its holding company pursuant to subsections (a) through (d) of this Section 4.03 shall be submitted in writing to the Borrower and the Adminis- trative Agent and shall be conclusive and binding for all purposes, absent manifest error. The Borrower shall pay each Lender directly the amount shown as due on any such certificate within 10 days after its receipt of the same. The failure of any Lender to provide such notice or to make demand for payment under this Section 4.03 shall not constitute a waiver of such Lender's rights hereunder; provided that such Lender shall not be entitled to demand payment pursuant to subsections (a) through (d) of this Section 4.03 in respect of any loss, cost, expense, reduction or reserve if such demand is made more than three years following such Lender's incurrence or sufferance thereof or more than one year following such Lender's actual knowledge of the event giving rise to such Lender's rights pursuant to such subsections. Each Lender shall use reasonable efforts to ensure the accuracy and validity of any claim made by it hereunder, but the foregoing shall not obligate any Lender to assert any possible invalidity or inapplicability of the law, rule, regulation, guideline or other change or condition which shall have occurred or been imposed. (f) Change in Legality. Notwithstanding any other provision herein, if the adoption of or any change in any law or regulation or in the interpre- tation or administration thereof by any governmental authority charged with the administration or interpretation thereof shall make it unlawful for any Lender to make or maintain any Eurodollar Rate Advance or to give effect to its obligations as contemplated hereby with respect to any Eurodollar Rate Advance, then, by written notice to the Borrower and the Administrative Agent, such Lender may: (i) declare that Eurodollar Rate Advances will not thereafter be made by such Lender hereunder, whereupon the right of the Borrower to select Eurodollar Rate Advances for any Borrowing or Conversion shall be forthwith suspended until such Lender shall withdraw such notice as provided hereinbe- low or shall cease to be a Lender hereunder pursuant to Section 10.07(g) hereof; and (ii) require that all outstanding Eurodollar Rate Advances made by it be Converted to Base Rate Advances, in which event all such Eurodollar Rate Advances by all Lenders shall be automatically Converted to Base Rate Advances as of the effective date of such notice as provided herein below. Upon receipt of any such notice, the Administrative Agent shall promptly notify the other Lenders. Promptly upon becoming aware that the circumstanc- es that caused such Lender to deliver such notice no longer exist, such Lender shall deliver notice thereof to the Borrower and the Administrative Agent withdrawing such prior notice (but the failure to do so shall impose no liability upon such Lender). Promptly upon receipt of such withdrawing notice from such Lender (or upon such Lender assigning all of its Commit- ments, Advances, participation and other rights and obligations hereunder in accordance with Section 10.07(g)), the Administrative Agent shall deliver notice thereof to the Borrower and the Lenders and such suspension shall terminate. Prior to any Lender giving notice to the Borrower under this subsection (f), such Lender shall use reasonable efforts to change the jurisdiction of its Applicable Lending Office, if such change would avoid such unlawfulness and would not, in the sole determination of such Lender, be otherwise disadvantageous to such Lender. Any notice to the Borrower by any Lender shall be effective as to each Eurodollar Rate Advance on the last day of the Interest Period currently applicable to such Eurodollar Rate Advance; provided that if such notice shall state that the maintenance of such Advance until such last day would be unlawful, such notice shall be effective on the date of receipt by the Borrower and the Administrative Agent. (g) Market Rate Disruptions. If (i) less than two Reference Banks furnish timely information to the Administrative Agent for determining the Eurodollar Rate for Eurodollar Rate Advances in connection with any proposed Borrowing or Conversion or (ii) if the Majority Lenders shall notify the Administrative Agent that the Eurodollar Rate will not adequately reflect the cost to such Majority Lenders of making, funding or maintaining their respective Eurodollar Rate Advances, the right of the Borrower to select or receive such Eurodollar Rate Advances for any Borrowing or Conversion shall be forthwith suspended until the Administrative Agent shall notify the Borrower and the Lenders that the circumstances causing such suspension no longer exist, and until such notification from the Administrative Agent each requested Borrowing or Conversion into Eurodollar Rate Advances hereunder shall be deemed to be a request for Base Rate Advances. SECTION 4.04 Sharing of Payments, Etc. If any Lender shall obtain any payment (whether voluntary, involuntary, through the exercise of any right of set-off, or otherwise, but excluding any proceeds received by assignments or sales of participations in accordance with Section 10.07 hereof to a Person that is not an Affiliate of the Borrower) on account of the Advances owing to it (other than pursuant to Section 4.03 hereof) in excess of its ratable share of payments on account of the Advances obtained by all the Lenders, such Lender shall forthwith purchase from the other Lenders such participation in the Advances owing to them as shall be necessary to cause such purchasing Lender to share the excess payment ratably with each of them; provided, however, that if all or any portion of such excess payment is thereafter recovered from such purchasing Lender, such purchase from each Lender shall be rescinded and such Lender shall repay to the purchasing Lender the purchase price to the extent of such recovery together with an amount equal to such Lender's ratable share (according to the proportion of (i) the amount of such Lender's required repayment to (ii) the total amount so recovered from the purchasing Lender) of any interest or other amount paid or payable by the purchasing Lender in respect of the total amount so recovered. The Borrower agrees that any Lender so purchasing a participation from another Lender pursuant to this Section 4.04 may, to the fullest extent permitted by law, exercise all its rights of payment (including the right of set-off) with respect to such participation as fully as if such Lender were the direct creditor of the Borrower in the amount of such participation. Notwithstanding the foregoing, if any Lender shall obtain any such excess payment involuntarily, such Lender may, in lieu of purchasing participation from the other Lenders in accordance with this Section 4.04, on the date of receipt of such excess payment, return such excess payment to the Administrative Agent for distribution in accordance with Section 4.01(a). SECTION 4.05 Taxes. (a) All payments by the Borrower hereunder and under the other Loan Documents shall be made in accordance with Section 4.01, free and clear of and without deduction for all present or future taxes, levies, imposts, deductions, charges or withholdings, and all liabilities with respect thereto, excluding, in the case of each Lender and the Adminis- trative Agent, taxes imposed on its overall net income, and franchise taxes imposed on it, by the jurisdiction under the laws of which such Lender or the Administrative Agent (as the case may be) is organized or any political subdivision thereof and, in the case of each Lender, taxes imposed on its overall net income, and franchise taxes imposed on it, by the jurisdiction of such Lender's Applicable Lending Office or any political subdivision thereof (all such non-excluded taxes, levies, imposts, deductions, charges, withhold- ings and liabilities being hereinafter referred to as "Taxes"). If the Borrower shall be required by law to deduct any Taxes from or in respect of any sum payable hereunder or under any other Loan Document to any Lender or the Administrative Agent, (i) the sum payable shall be increased as may be necessary so that after making all required deductions (including deductions applicable to additional sums payable under this Section 4.05) such Lender or the Administrative Agent (as the case may be) receives an amount equal to the sum it would have received had no such deductions been made, (ii) the Borrower shall make such deductions and (iii) the Borrower shall pay the full amount deducted to the relevant taxation authority or other authority in accordance with applicable law. (b) In addition, the Borrower agrees to pay any present or future stamp or documentary taxes or any other excise or property taxes, charges or similar levies that arise from any payment made hereunder or under any other Loan Document or from the execution, delivery or registration of, or other- wise with respect to, this Agreement or any other Loan Document (hereinafter referred to as "Other Taxes"). (c) The Borrower will indemnify each Lender and the Administrative Agent for the full amount of Taxes and Other Taxes (including, without limitation, any Taxes and any Other Taxes imposed by any jurisdiction on amounts payable under this Section 4.05) paid by such Lender or the Adminis- trative Agent (as the case may be) and any liability (including penalties, interest and expenses) arising therefrom or with respect thereto, whether or not such Taxes or Other Taxes were correctly or legally asserted. Any Lender's claim for such indemnification shall be set forth in a certificate of such Lender setting forth in reasonable detail the amount necessary to indemnify such Lender pursuant to this subsection (c) and shall be submitted to the Borrower and the Administrative Agent and shall be conclusive and binding for all purposes, absent manifest error. The Borrower shall pay each Lender directly the amount shown as due on any such certificate within 30 days after its receipt of the same. If any Taxes or Other Taxes for which a Lender or the Administrative Agent has received payments from the Borrower hereunder shall be finally determined to have been incorrectly or illegally asserted and are refunded to such Lender or the Administrative Agent, such Lender or the Administrative Agent, as the case may be, shall promptly forward to the Borrower any such refunded amount. The Borrower's, the Administrative Agent's and each Lender's obligations under this Section 4.05 shall survive the payment in full of the Advances. (d) Within 30 days after the date of any payment of Taxes, the Borrower will furnish to the Administrative Agent, at its address referred to in Section 10.02, the original or a certified copy of a receipt evidencing payment thereof. (e) Each Lender shall, on or prior to the date it becomes a Lender hereunder, deliver to the Borrower and the Administrative Agent such certifi- cates, documents or other evidence, as required by the Internal Revenue Code of 1986, as amended from time to time (the "Code"), or treasury regulations issued pursuant thereto, including Internal Revenue Service Form 4224 and any other certificate or statement of exemption required by Treasury Regulation Section 1.1441-1(a) or Section 1.1441-6(c) or any subsequent version thereof, properly completed and duly executed by such Lender establishing that it is (i) not subject to withholding under the Code or (ii) totally exempt from United States of America tax under a provision of an applicable tax treaty. Each Lender shall promptly notify the Borrower and the Administrative Agent of any change in its Applicable Lending Office and shall deliver to the Borrower and the Administrative Agent together with such notice such certifi- cates, documents or other evidence referred to in the immediately preceding sentence. Each Lender will use good faith efforts to apprise the Borrower as promptly as practicable of any impending change in its tax status that would give rise to an obligation by the Borrower to pay any additional amounts pursuant to this Section 4.05. Unless the Borrower and the Administrative Agent have received forms or other documents satisfactory to them indicating that payments hereunder or under the Notes are not subject to United States of America withholding tax or are subject to such tax at a rate reduced by an applicable tax treaty, the Borrower or the Administrative Agent shall withhold taxes from such payments at the applicable statutory rate in the case of payments to or for any Lender organized under the laws of a jurisdic- tion outside the United States of America. Each Lender represents and warrants that each such form supplied by it to the Administrative Agent and the Borrower pursuant to this Section 4.05, and not superseded by another form supplied by it, is or will be, as the case may be, complete and accu- rate. (f) Any Lender claiming any additional amounts payable pursuant to this Section 4.05 shall use reasonable efforts (consistent with legal and regulatory restrictions) to file any certificate or document requested by the Borrower or to change the jurisdiction of its Applicable Lending Office if the making of such a filing or change would avoid the need for or reduce the amount of any such additional amounts which may thereafter accrue and would not, in the sole determination of such Lender, be otherwise disadvantageous to such Lender. ARTICLE V CONDITIONS PRECEDENT SECTION 5.01 Conditions Precedent to the Closing Date. The commit- ments of the Lenders to make Advances under and in accordance with this Agreement shall not become effective until the following conditions precedent shall have been fulfilled: (a) The Administrative Agent shall have received the following, each dated the date of delivery thereof (unless otherwise specified below), in form and substance satisfactory to each Lender and (except for the Notes) in sufficient copies for each Lender: (i) Counterparts of this Agreement, duly executed by each party hereto. (ii) The Notes to the order of the respective Lenders, duly executed by the Borrower. (iii) True and complete photocopies of the Significant Contracts in effect on the Closing Date and all amendments, modifications and supplements thereto, in each case duly executed by the respective parties thereto. (iv) A certificate of the Secretary of the Borrower certifying (A) the names and true signatures of the officers of the Borrower authorized to sign this Agreement and the Notes and the other documents to be delivered hereunder and thereunder and (B) that attached thereto are true and correct copies of the Articles of Incorporation of the Borrower, and all amendments thereto, and the By-laws of the Borrower, in each case as in effect on such date and (C) that attached thereto are true and correct copies of the resolutions of the Board of Directors of the Borrower approving this Agree- ment and the Notes and the other documents to be delivered by the Borrower hereunder and thereunder, and of all documents evidencing other necessary corporate action, if any, with respect to the execution, delivery and performance by the Borrower of this Agreement and the Notes. (v) A certificate of a duly authorized officer of the Borrower certifying that, except as set forth in the Disclosure Documents, there is no pending or known threatened action or proceeding (including, without limita- tion, any action or proceeding relating to any environmental protection laws or regulations) affecting the Borrower or its properties before any court, governmental agency or arbitrator, which may: (A) purport to affect the legality, validity or enforceability of the Existing Notes, any Loan Document or any Significant Contract or (B) materially adversely affect the financial condition, properties, prospects or operations of the Borrower as a whole. (vi) A certificate of a duly authorized officer of the Borrower stating that (i) the representations and warranties contained in Section 6.01 are correct, in all material respects, on and as of the Closing Date before and after giving effect to the initial Advances and the application of the proceeds thereof, as though made on and as of such date and (ii) no event has occurred and is continuing which constitutes an Event of Default or Unmatured Default, or would result from such initial Advances or the application of the proceeds thereof. (vii) A certificate signed by the Treasurer or Assistant Treasurer of the Borrower, certifying as to the absence of any material adverse change in the financial condition, operations, properties or prospects of the Borrower since December 31, 1994, except as disclosed in the Disclosure Documents. (viii) Copies, certified by the Borrower, of all Governmental Approv- als listed in Schedule II hereof. (ix) Favorable opinions of: (A) Rath, Young and Pignatelli, P.A., special New Hampshire counsel to the Borrower, in substantially the form of Exhibit 5.01A hereto; (B) Jeffrey C. Miller, Esq., Assistant General Counsel of NUSCO, in substantially the form of Exhibit 5.01B hereto; and (C) C.E. Shively, Esq., Senior Counsel of PSNH, in substantially the form of Exhibit 5.01C hereto; (x) A certificate of PSNH, signed by a duly authorized officer of PSNH, certifying as to the absence of any material adverse change in the financial condition, operations, properties or prospects of PSNH since December 31, 1994, except as disclosed in the disclosure documents referred to in such certificate. (xi) Such other approvals, opinions and documents as any Lender, through the Administrative Agent, may reasonably request as to the legality, validity, binding effect or enforceability of this Agreement and the Notes. (b) There shall exist no injunction or temporary restraining order which, in the judgment of the Administrative Agent or the Arrangers would prohibit the making of the Advances or the consummation of the redemption of the Existing Notes; except as set forth in the Disclosure Documents, there shall be no pending or known threatened action or proceeding (including, without limitation, any action or proceeding relating to any environmental protection laws or regulations) affecting the Borrower or its properties before any court, governmental agency or arbitrator, which may: (i) purport to affect the legality, validity or enforceability of the Existing Notes, any Loan Document or any Significant Contract or (ii) materially adversely affect the financial condition, properties, prospects or operations of the Borrower as a whole. (c) All other legal and regulatory matters relating to this Agreement, the Notes, the Advances and the redemption of the Existing Notes shall be satisfactory to the Arrangers and the Lenders. (d) No Default or Event of Default shall have occurred and be continu- ing. (e) The Borrower shall have paid all fees under or referenced in Section 2.02 hereof, to the extent then due and payable. (f) The Closing Date shall have occurred on or prior to December 31, 1995. SECTION 5.02 Conditions Precedent to Funding Date. The obligation of each Lender to make its Advances on the Funding Date is subject to the fulfillment of the conditions precedent that: (a) The Closing Date shall have occurred. (b) The Borrower shall have delivered to the Administrative Agent a Notice of Borrowing in respect of the Advances, specifying the Funding Date, at least three Business Days prior to the Funding Date. (c) The Funding Date shall occur (i) on or not more than 35 days following the Closing Date and (ii) on or before December 31, 1995. (d) The Existing Notes shall have been called for redemption in whole, and upon application of the proceeds of the Advances in accordance with Section 6.01(l) (together with such other funds of the Borrower as may be required) the redemption price of all of the Existing Notes will be paid, and the Existing Notes shall be redeemed in whole, on the Funding Date. (e) All Pre-Funding Exposure Fees shall have been paid in accordance with Section 2.02. The acceptance by or on behalf of the Borrower of the proceeds of the Advances shall constitute a representation and warranty by the Borrower that the foregoing conditions have been satisfied. SECTION 5.03 Reliance on Certificates. The Lenders and the Adminis- trative Agent shall be entitled to rely conclusively upon the certificates delivered from time to time by officers of the Borrower and the other parties to the Significant Contracts as to the names, incumbency, authority and signatures of the respective persons named therein until such time as the Administrative Agent may receive a replacement certificate, in form accept- able to the Administrative Agent, from an officer of such Person identified to the Administrative Agent as having authority to deliver such certificate, setting forth the names and true signatures of the officers and other representatives of such Person thereafter authorized to act on behalf of such Person. ARTICLE VI REPRESENTATIONS AND WARRANTIES SECTION 6.01 Representations and Warranties of the Borrower. The Borrower represents and warrants as follows: (a) The Borrower is a corporation duly organized and validly existing under the laws of the State of New Hampshire. The Borrower is duly qualified to do business in, and is in good standing in, all other jurisdictions where the nature of its business or the nature of property owned or used by it makes such qualifications necessary. (b) The execution, delivery and performance by the Borrower of each Loan Document are within the Borrower's corporate powers, have been duly authorized by all necessary corporate action, and do not and will not contravene (i) the Borrower's charter or by-laws or (ii) any law or legal or contractual restriction binding on or affecting the Borrower; and such execution, delivery and performance do not or will not result in or require the creation of any Lien upon or with respect to any of its properties. Each Significant Contract was duly authorized, executed and delivered by the Borrower and is in full force and effect. (c) No Governmental Approval is required for the execution, delivery or performance by the Borrower of the Loan Documents, except for those Governmental Approvals set forth on Schedule II, each of which has been duly obtained or made and is in full force and effect and in respect of which all applicable periods of time for review, rehearing or appeal have expired. No Governmental Approval is required (i) for the performance by the Borrower of the Significant Contracts or (ii) in connection with the nature of the Borrower's business, except in each case for such as have been duly obtained or made and are in full force and effect and in respect of which all applica- ble periods of time for review, rehearing or appeal have expired, or, in the case of Governmental Approvals referred to in clause (ii), such as can reasonably be expected to be obtained in the ordinary course of the Borrower's business without undue burden or expense. (d) This Agreement, the Notes and each Significant Contract are legal, valid and binding obligations of the Borrower enforceable against the Borrower in accordance with their respective terms; subject to the qualifica- tion, however, that the enforcement of the rights and remedies herein and therein is subject to bankruptcy and other similar laws of general applica- tion affecting rights and remedies of creditors and that the remedy of specific performance or of injunctive relief is subject to the discretion of the court before which any proceedings therefor may be brought. (e) The audited balance sheet of the Borrower as of December 31, 1994, and the related statements of the Borrower setting forth the results of operations and cash flows of the Borrower for the fiscal year then ended, and the unaudited balance sheet of the Borrower as of June 30, 1995, and the related statements of the Borrower setting forth the results of operations and cash flows of the Borrower for the fiscal quarter then ended, copies of which have been furnished to each Bank, fairly present in all material respects the financial condition, results of operations and cash flows of the Borrower at and for the periods ended on such dates, and have been prepared in accordance with generally accepted accounting principles consistently applied. Except as reflected in such financial statements and in the Disclosure Documents, the Borrower has no material non-contingent liabili- ties, and all contingent liabilities have been appropriately reserved. The financial projections contained in the Information Memorandum were prepared in good faith and on the basis of reasonable assumptions, and, as of the date of this Agreement, nothing has come to the attention of the Borrower's senior management to indicate that such assumptions are no longer reasonable. Since December 31, 1994, there has been no material adverse change in the Borrower's financial condition, operations, properties or prospects, except as disclosed in the Disclosure Documents. (f) Except as set forth in the Disclosure Documents, there is no pending or known threatened action or proceeding (including, without limita- tion, any action or proceeding relating to any environmental protection laws or regulations) affecting the Borrower or its properties before any court, governmental agency or arbitrator, which may: (i) purport to affect the legality, validity or enforceability of the Existing Notes, any Loan Document or any Significant Contract or (ii) materially adversely affect the financial condition, properties, prospects or operations of the Borrower as a whole. (g) The Borrower has title to its assets sufficient for the operation of its business, subject only to Permitted Liens. All insurance required by Section 7.01(c) hereof is in full force and effect. (h) No ERISA Plan Termination Event has occurred nor is reasonably expected to occur with respect to any ERISA Plan which would materially adversely affect the financial condition, properties, prospects or operations of the Borrower, except as disclosed to and consented by the Majority Lenders in writing. Since the date of the most recent Schedule B (Actuarial Informa- tion) to the Annual Report of the Borrower (Form 5500 Series), if any, there has been no material adverse change in the funding status of the ERISA Plans referred to therein and no "prohibited transaction" (other than such as may be exempted under Section 408 of ERISA and applicable regulations thereunder) has occurred with respect thereto, except as described in the Disclosure Documents. Neither the Borrower nor any of its ERISA Affiliates has incurred nor reasonably expects to incur any material withdrawal liability under ERISA to any ERISA Multiemployer Plan, except as disclosed to and consented by the Majority Lenders in writing. (i) The Borrower has filed all tax returns (federal, state and local) required to be filed and paid taxes shown thereon to be due, including interest and penalties, or, to the extent the Borrower is contesting in good faith an assertion of liability based on such returns, has provided adequate reserves in accordance with generally accepted accounting principles for payment thereof. (j) No exhibit, schedule, report or other written information provided by the Borrower or its agents to the Lenders in connection with the negotia- tion, execution and closing of this Agreement (including, without limitation, the Information Memorandum) knowingly contained when made any material misstatement of fact or knowingly omitted to state any material fact neces- sary to make the statements contained therein not misleading in light of the circumstances under which they were made. (k) No event has occurred and is continuing which constitutes a material default under the Rate Agreement or any Significant Contract. (l) All proceeds of the Advances will be irrevocably deposited with the trustee for the Existing Notes for the payment of the redemption price of the Existing Notes, and upon such application (together with such other funds of the Borrower as may be required) the redemption price of all of the Existing Notes will be deemed to have been paid under the terms of the indenture governing the Existing Notes, and the Existing Notes will be deemed "paid" thereunder, on the Funding Date. (m) No proceeds of any Advance will be used (i) to acquire any equity security of a class which is registered pursuant to Section 12 of the Securities Exchange Act of 1934 or (ii) to buy or carry any margin stock (within the meaning of Regulation U issued by the Board of Governors of the Federal Reserve System) or to extend credit to others for such purpose. The Borrower (i) is not an "investment company" within the meaning ascribed to that term in the Investment Company Act of 1940 and (ii) is not engaged in the business of extending credit for the purpose of buying or carrying margin stock. (n) The Borrower is in compliance in all material respects with the requirements of all applicable laws, rules, regulations and orders of any governmental authority, including without limitation any such laws, rules, regulations and orders relating to utilities, zoning, environmental protec- tion, use and disposal of Hazardous Substances, land use, construction and building restrictions, and employee safety and health matters relating to business operations and without limiting the foregoing all "financial protection" and other requirements of the Price-Anderson Act, as amended from time to time and all other laws relating to nuclear plant owners and opera- tors, except to the extent (i) that the Borrower is contesting the same in good faith by appropriate proceedings or (ii) that any such non-compliance, and the enforcement or correction thereof, would not materially adversely affect the financial condition, properties, prospects or operations of the Borrower as a whole or (iii) disclosed in the Disclosure Documents. (o) No Default or Event of Default has occurred and is continuing. (p) No "Default" or "Event of Default" (as those terms are defined in the First Mortgage Indenture) has occurred and is continuing. As of the date of this Agreement, the aggregate principal amount of all First Mortgage Bonds outstanding is $335,000,000. ARTICLE VII COVENANTS OF THE BORROWER SECTION 7.01 Affirmative Covenants. So long as any Note shall remain unpaid or any Lender shall have any Commitment hereunder, the Borrower will, unless the Majority Lenders shall otherwise consent in writing: (a) Use of Proceeds. Apply all proceeds of each Advance solely as specified in Section 6.01(l) hereof. (b) Payment of Taxes, Etc. Pay and discharge before the same shall become delinquent, all taxes, assessments and governmental charges, royalties or levies imposed upon it or upon its property except to the extent the Borrower is contesting the same in good faith by appropriate proceedings and has set aside adequate reserves for the payment thereof. (c) Maintenance of Insurance. Maintain, or cause to be maintained, insurance (including appropriate plans of self-insurance) covering the Borrower and its properties in effect at all times in such amounts and covering such risks as may be required by law and in addition as is usually carried by companies engaged in similar businesses and owning similar properties. Such insurance shall in any event include all "financial protection" required by the Price-Anderson Act, as amended from time to time. (d) Preservation of Existence, Etc. Preserve and maintain its corporate existence, material rights (statutory and otherwise) and franchis- es. (e) Compliance with Laws, Etc. Comply in all material respects with the requirements of all applicable laws, rules, regulations and orders of any governmental authority, including without limitation any such laws, rules, regulations and orders relating to utilities, zoning, environmental protec- tion, use and disposal of Hazardous Substances, land use, construction and building restrictions, and employee safety and health matters relating to business operations and without limiting the foregoing all "financial protection" and other requirements of the Price-Anderson Act, as amended from time to time and all other laws relating to nuclear plant owners and opera- tors, except to the extent (i) that the Borrower is contesting the same in good faith by appropriate proceedings or (ii) that any such non-compliance, and the enforcement or correction thereof, would not materially adversely affect the financial condition, properties, prospects or operations of the Borrower as a whole. (f) Inspection Rights. At any time and from time to time upon reasonable notice and subject to reasonable coordination measures agreed upon by the Administrative Agent and the Borrower, permit the Lenders and their respective agents and representatives to examine and make copies of and abstracts from the records and books of account of, and the properties of, the Borrower and to discuss the affairs, finances and accounts of the Borrower with the Borrower and with its officers, directors and accountants. (g) Keeping of Books. Keep proper records and books of account, in which full and correct entries shall be made of all financial transactions of the Borrower and the assets and business of the Borrower, in accordance with good accounting practices consistently applied. (h) Performance of Related Agreements. Perform and observe all material terms and provisions of each Significant Contract and take all reasonable steps to enforce each Significant Contract substantially in accordance with its terms and to preserve the rights of the Borrower thereun- der; provided, that the foregoing provisions of this Section 7.01(h) shall not preclude the Borrower from any waiver, amendment, modification, consent or termination permitted under Section 7.02(h) hereof. (i) Collection of Accounts Receivable. Promptly bill, and diligently pursue collection of, in accordance with customary utility practices, all accounts receivable owing to the Borrower and all other amounts that may from time to time be owing to the Borrower for services rendered or goods sold. (j) Maintenance of Financial Covenants. (i) Common Equity Ratio. Maintain at all times a Common Equity Ratio of not less than 0.25:1.00. (ii) Interest Coverage Ratio. Maintain at all times during each period indicated in the table below, an Interest Coverage Ratio not less than the ratio specified for such period in such table: Period Ratio Through December 31, 1997 1.35:1.00 Thereafter 1.50:1.00 (k) Maintenance of Properties, Etc. Maintain, develop, and operate in substantial conformity with all laws, material contractual obligations and prudent practices prevailing in the industry, all of its properties which are used or useful in the conduct of its business in good working order and condition, ordinary wear and tear excepted, except to the extent such non- conformity would not materially adversely affect the financial condition, properties, prospects or operations of the Borrower as a whole. (l) Governmental Approvals. Duly obtain on or prior to such date as the same may become legally required, and thereafter maintain in effect at all times, all Governmental Approvals required (i) for the execution, delivery and performance by the Borrower of the Loan Documents, (ii) for the performance by the Borrower of the Significant Contracts and (iii) in connection with the nature of the Borrower's business, except, in the case of clause (iii) only, those the absence of which would not materially adversely affect the financial condition, properties, prospects or operations of the Borrower as a whole. SECTION 7.02 Negative Covenants. So long as any Note shall remain unpaid or any Lender shall have any Commitment hereunder, the Borrower will not, without the written consent of the Majority Lenders: (a) Liens, Etc. Create, incur, assume or suffer to exist any lien, security interest, or other charge or encumbrance (including the lien or retained security title of a conditional vendor) of any kind, or any other type of preferential arrangement the intent or effect of which is to assure a creditor against loss or to prefer one creditor over another creditor (other than any preferential arrangement under the Joint Ownership Agreement with respect to any party thereto) upon or with respect to any of its properties of any character (any of the foregoing being referred to herein as a "Lien") whether now owned or hereafter acquired, or sign or file under the Uniform Commercial Code of any jurisdiction a financing statement which names the Borrower as debtor, sign any security agreement authorizing any secured party thereunder to file such financing statement, or assign accounts, excluding, however, from the operation of the foregoing restrictions the following, whether now existing or hereafter created or perfected (Permitted Liens): (i) Liens for taxes, assessments or governmental charges or levies thereon if the same shall not at the time be delinquent or thereafter can be paid without penalty, or are being contested in good faith and by appropriate proceedings and for which adequate reserves in accordance with generally accepted accounting principles shall have been set aside on the Borrower's books. (ii) Liens imposed by law (other than ERISA), such as carriers; warehousemen's and mechanics' liens and other similar liens arising in the ordinary course of business which secure payment of obligations not more than 60 days past due. (iii) Liens arising out of pledges or deposits under worker's compensation laws, unemployment insurance, old age pensions, or other social security or retirement benefits, or similar legislation (other than ERISA). (iv) Utility easements, building restrictions and such other encum- brances or charges against real property as are of a nature generally existing with respect to properties of a similar character and which do not in any material way affect the marketability of the same or interfere with the use thereof in the business of the Borrower. (v) Liens in existence on the Closing Date none of which materially adversely affects or will affect the ongoing conduct of the Borrower's business and none of which (except as described in clause (vi) below) extends to the Unit Contract. (vi) The Lien of the First Mortgage Indenture to the extent of the First Mortgage Bonds outstanding on the Funding Date, together with any other First Mortgage Bonds permitted to be issued hereunder. (vii) Attachment, judgment and other similar Liens arising in connection with court proceedings, provided, the execution or other enforce- ment thereof is effectively stayed, the claims secured thereby are being contested at the time in good faith and no Event of Default shall have occurred and be continuing; (viii) any rights of the Nuclear Regulatory Commission with respect to Seabrook; and (ix) Liens against the interest of some other Person (other than the Borrower) with respect to obligations which have not been assumed or guaran- teed by the Borrower and on which the Borrower does not customarily pay interest charges, existing on Seabrook or other property which the Borrower jointly holds with such other Person (or such Person and others) or upon property in which the Borrower is a tenant in common with such other Person (or such Person and others). (b) Debt, Create, incur, assume or suffer to exist any Debt, except for: (i) First Mortgage Bonds presently outstanding; (ii) Until the redemption thereof on the Funding Date, Debt in respect of the Existing Notes; (iii) Debt arising under the Loan Documents; (iv) Debt in respect of interest rate swaps, caps and similar arrange- ments entered into for purposes of hedging interest rate risk arising under the Loan Documents; (v) Debt consisting of maintenance and similar obligations arising under the Joint Ownership Agreement; and (vi) other unsecured Debt not to exceed: (A) during the period from the Closing Date through December 31, 1996, $50,000,000 at any time outstanding; and (B) thereafter, $75,000,000 at any time outstanding less, for purposes of this clause (B), the principal amount of any Authorized Replacement First Mortgage Bonds; and then only to the extent that the creation, incurrence, assumption or existence of such Debt would not result in a violation of Section 7.01(j). (c) First Mortgage Bonds. Create or issue, or incur or suffer to exist any Debt in respect of, First Mortgage Bonds, except for: (i) First Mortgage Bonds outstanding on the date hereof; and (ii) On or after June 1, 1999, up to $50,000,000 of First Mortgage Bonds issued on or after such date to finance or re-finance the repayment, redemption or other retirement of a like principal amount of First Mortgage Bonds outstanding on the Funding Date (such newly-issued First Mortgage Bonds being herein referred to as "Authorized Replacement First Mortgage Bonds"); provided, however, that at no time shall the aggregate principal amount of Authorized Replacement First Mortgage Bonds then outstanding, together with the aggregate principal amount of Debt outstanding pursuant to Section 7.02(b)(vi)(B), exceed $75,000,000; and then only to the extent that the creation, issuance, incurrence or existence of such First Mortgage Bonds or Debt in respect of First Mortgage Bonds would not result in a violation of Section 7.01(j). (d) Mergers, Etc. Merge with or into or consolidate with or into, or acquire all or substantially all of the assets of, any Person. (e) Sales, Etc., of Assets. Sell, lease, transfer or otherwise dispose of all or any part of its assets other than dispositions of assets no longer required in the ordinary course of the Borrower's business. Without limitation of the foregoing, the Borrower shall not (i) sell, lease, transfer or otherwise dispose of any of its receivables to any unaffiliated third party, except for collection in the ordinary course of the Borrower's business of delinquent accounts, or (ii) enter into any sale-leaseback transaction. (f) Investments in Other Persons. Make any loan or advance to any Person or purchase or otherwise acquire any capital stock, obligations or other securities of, make any capital contribution to, or otherwise invest in, any Person other than Permitted Investments and loans, advances, purchas- es and investments listed on Schedule III hereto. (g) Compliance with ERISA. (i) Terminate, or permit any ERISA Affiliate to terminate, any ERISA Plan so as to result in any material (in the opinion of the Majority Lenders) liability of the Borrower to the PBGC, or (ii) permit to exist any occurrence of any Reportable Event (as defined in Title IV of ERISA), other than a Reportable Event not subject to the provi- sion for 30-day notice to the PBGC under applicable regulations, or any other event or condition, which presents a material (in the opinion of the Majority Lenders) risk of such a termination by the PBGC of any ERISA Plan and such a material liability to the Borrower. (h) Significant Contracts. (i) Amendments. Amend, modify or supplement or give any consent, acceptance or approval to any amendment, modification or supplement or deviation by any party from the terms of any Significant Contract, except any amendment, modification or supplement to any Significant Contract that would not reduce the rights or entitlements of the Borrower thereunder in any material way or, in the case of the Tax Allocation Agreement, such changes as may be required by applicable law. (ii) Termination. Cancel or terminate (or consent to any cancellation or termination of) any Significant Contract prior to the expiration of its stated term. (i) Change in Nature of Business. Engage in any material business activity other than the generation and sale of electricity. (j) Ownership in Seabrook and Nuclear Plants. (i) acquire, directly or indirectly, any additional ownership interest in Seabrook, or any ownership interest or any additional ownership interest of any kind in any other nuclear-powered electric generating plant, except as the Borrower may be required to acquire pursuant to the terms of the Joint Ownership Agreement, provided, however, that, prior to acquiring any such additional ownership interest in Seabrook, the Borrower shall deliver to the Administrative Agent a written opinion of counsel (in form and substance satisfactory to the Majority Lenders) to the effect that any such additional ownership interest will be included in the "Ownership Share" (as defined in the Unit Contract) and that any payments to the Borrower from PSNH of the type referred to in Section B.(E)(1) and (2) of Exhibit C to the Rate Agreement would reflect the Ownership Share as increased by such additional ownership interest; or (ii) amend, modify or supplement, or give any consent, acceptance or approval to any amendment, modification or supplementation to, the Joint Ownership Agreement which would cause (A) the Borrower to acquire any additional ownership interest in Seabrook, except as permitted under clause (i) above, or (B) increase the obligations of the Borrower thereunder without increasing ratably the obligations of the other parties thereto. (k) Subsidiaries. Create or suffer to exist any subsidiaries. SECTION 7.03 Reporting Obligations. So long as any Note shall remain unpaid or any Lender shall have any Commitment hereunder, the Borrower will, unless the Majority Lenders shall otherwise consent in writing, furnish to the Administrative Agent in sufficient copies for each Lender, the following: (i) as soon as possible and in any event within five (5) days after the occurrence of each Event of Default or Unmatured Default continuing on the date of such statement, a statement of the Chief Financial Officer, Treasurer or Assistant Treasurer of the Borrower setting forth details of such Event of Default or Unmatured Default and the action which the Borrower proposes to take with respect thereto; (ii) as soon as available and in any event within fifty (50) days after the end of each of the first three quarters of each fiscal year of the Borrower, (A) if and so long as the Borrower is required to submit to the Securities and Exchange Commission a report on Form 10-Q, a copy of the Borrower's report on Form 10-Q submitted to the Securities and Exchange Commission with respect to such quarter and (B) if the Borrower ceases to be required to submit such report, a balance sheet of the Borrower as of the end of such quarter and statements of income and retained earnings and of cash flows of the Borrower for the period commencing at the end of the previous fiscal year and ending with the end of such quarter, all in reasonable detail and duly certified (subject to year-end audit adjustments) by the Chief Financial Officer, Treasurer or Assistant Treasurer of the Borrower as having been prepared in accordance with generally accepted accounting principles, in each such case, delivered together with a certificate of said officer (X) stating that no Event of Default or Unmatured Default has occurred and is continuing or, if an Event of Default or Unmatured Default has occurred and is continuing, a statement as to the nature thereof and the action which the Borrower proposes to take with respect thereto and (Y) demonstrating compliance with Section 7.01(j) for and as of the end of such fiscal quarter and compliance with Sections 7.02(b) and (c), as of the dates on which any Debt was created, issued, incurred or assumed (using the Borrower's most recent annual actuarial determinations in the computation of Debt referred to in clause (ix) in the definition of "Debt") during such quarter and as of the end of such fiscal quarter, such demonstration to be in a schedule (in form satisfactory to the Majority Lenders) which sets forth the computations used by the Borrower in determining such compliance; (iii) as soon as available and in any event within 105 days after the end of each fiscal year of the Borrower, (A) if and so long as the Borrower is required to submit to the Securities and Exchange Commission a report on Form 10-K, a copy of the Borrower's report on Form 10-K submitted to the Securities and Exchange Commission with respect to such year and (B) in any case, a copy of the annual report for such year for the Borrower including therein an audited balance sheet of the Borrower as of the end of such fiscal year and audited statements of income and retained earnings and of cash flows of the Borrower for such fiscal year, in each case certified by a nationally-recognized independent public accountant and delivered with a certificate of the Chief Financial Officer, Treasurer or Assistant Treasurer (X) stating that no Event of Default or Unmatured Default has occurred and is continuing, or if an Event of Default or Unmatured Default has occurred and is continuing, a statement as to the nature thereof and the action which the Borrower proposes to take with respect thereto and (Y) demonstrating compli- ance with Section 7.01(j) for and as of the end of such fiscal year and compliance with Sections 7.02(b) and (c) as of the dates on which any Debt was created, issued, incurred or assumed (using the Borrower's most recent annual actuarial determinations in the computation of Debt referred to in clause (viii) of the definition of "Debt") during the last fiscal quarter of such fiscal year and as of the end of such fiscal year, such demonstration to be in a schedule (in form satisfactory to the Majority Lenders) which sets forth the computations used by the Borrower in determining such compliance; (iv) as soon as available and in any event within 60 days prior to March 31 of each fiscal year, a copy of an operating budget/forecast of operations of the Borrower as approved by the Board of Directors of the Borrower in form satisfactory to the Lenders for the next fiscal year of the Borrower, together with a certificate of the Chief Financial Officer, Treasurer or Assistant Treasurer of the Borrower stating that such budget/forecast was prepared in good faith and on reasonable assumptions; (v) as soon as possible and in any event (A) within 30 days after the Borrower knows or has reason to know that any ERISA Plan Termination Event described in clause (i) of the definition of ERISA Plan Termination Event with respect to any ERISA Plan or ERISA Multiemployer Plan has occurred and (B) within 10 days after the Borrower knows or has reason to know that any other ERISA Plan Termination Event with respect to any ERISA Plan or ERISA Multiemployer Plan has occurred, a statement of the Chief Financial Officer, Treasurer or Assistant Treasurer of the Borrower describing such ERISA Plan Termination Event and the action, if any, which the Borrower proposes to take with respect thereto; (vi) promptly after receipt thereof by the Borrower or any of its ERISA Affiliates from the PBGC, copies of each notice received by the Borrower or any such ERISA Affiliate of the PBGC's intention to terminate any ERISA Plan or ERISA Multiemployer Plan or to have a trustee appointed to administer any ERISA Plan or ERISA Multiemployer Plan; (vii) promptly and in any event within 30 days after the filing thereof with the Internal Revenue Service, copies of each Schedule B (Actuar- ial Information) to the Annual Report of the Borrower (Form 5500 Series) with respect to each ERISA Plan (if any) to which the Borrower is a contributing employer; (viii) promptly after receipt thereof by the Borrower or any of its ERISA Affiliates from an ERISA Multiemployer Plan sponsor, a copy of each notice received by the Borrower or any of its ERISA Affiliates concerning the imposition or amount of withdrawal liability in an aggregate principal amount of at least $10,000,000 pursuant to Section 4202 of ERISA in respect of which the Borrower may be liable; (ix) promptly after the Borrower becomes aware of the occurrence thereof, notice of all actions, suits, proceedings or other events (A) of the type described in Section 6.01(f), or (B) which purport to affect the legality, validity or enforceability of any of the Loan Documents or Signifi- cant Contracts; (x) promptly after the sending or filing thereof, copies of all such proxy statements, financial statements, and reports which the Borrower sends to its public security holders (if any) or files with, and copies of all regular, periodic and special reports and all registration statements, if any, which the Borrower files with, the Securities and Exchange Commission or any governmental authority which may be substituted therefor, or with any national securities exchange; (xi) promptly after the sending or filing thereof, copies of all such proxy statements, financial statements, and reports which PSNH sends to its public security holders (if any) or files with, and copies of all regular, periodic and special reports and all registration statements, if any, which PSNH files with, the Securities and Exchange Commission or any governmental authority which may be substituted therefor, or with any national securities exchange; (xii) promptly after receipt thereof, any assertion of the character described in Section 8.01(i) hereof and the action the Borrower proposes to take with respect thereto; (xiii) promptly after knowledge of any material default under any Significant Contract or the Rate Agreement, notice of such default and the action the Borrower proposes to take with respect thereto; (xiv) promptly after knowledge of any amendment, modification or other change to any Significant Contract or the Rate Agreement or to any Governmental Approval affecting any Significant Contract or the Rate Agree- ment, notice of such amendment, modification or other change; and (xv) promptly after requested, such other information respecting the financial condition, operations, properties, prospects or otherwise, of the Borrower or PSNH as the Administrative Agent or Majority Lenders may from time to time reasonably request in writing. ARTICLE VIII DEFAULTS SECTION 8.01 Events of Default. The following events shall each constitute an "Event of Default" if the same shall occur and be continuing after the grace period and notice requirement (if any) applicable thereto: (a) The Borrower shall fail to pay any principal of any Note when due or shall fail to pay any interest on any Note or any Pre-Funding Exposure Fees or any other amount due hereunder within two days after the same becomes due; (b) Any representation or warranty made by the Borrower (or any of its officers or agents) in this Agreement, any other Loan Document, certificate or other writing delivered pursuant hereto or thereto shall prove to have been incorrect in any material respect when made or deemed made; or (c) The Borrower shall fail to perform or observe any term or covenant on its part to be performed or observed contained in Sections 7.01(a), (d) or (j), Section 7.02 or Section 7.03(i) hereof; provided, however, that in the case of the Borrower's failure to perform or observe the covenant set forth in Section 7.02(h), no Event of Default or Unmatured Default shall be deemed to have occurred if the Borrower shall have prepaid the entire aggregate principal amount of all Advances then outstanding, together with all unpaid interest and other accrued and unpaid amounts in respect thereof as provided in Section 4.02(c); or (d) The Borrower shall fail to perform or observe any other term or covenant on its part to be performed or observed contained in this Agreement or any Loan Document and any such failure shall remain unremedied, after written notice thereof shall have been given to the Borrower by the Adminis- trative Agent or any Lender, for a period of 30 days; or (e) The Borrower shall fail to pay any of its Debt when due (including any interest or premium thereon but excluding Debt evidenced by the Notes and excluding other Debt aggregating in no event more than $10,000,000 in principal amount at any one time) whether by scheduled maturity, required prepayment, acceleration, demand or otherwise, and such failure shall continue after the applicable grace period, if any, specified in any agree- ment or instrument relating to such Debt; or any other default under any agreement or instrument relating to any such Debt, or any other event, shall occur and shall continue after the applicable grace period, if any, specified in such agreement or instrument, if the effect of such default or event is to accelerate, or to permit the acceleration of, the maturity of such Debt; or any such Debt shall be declared to be due and payable, or required to be prepaid (other than by a regularly scheduled required prepayment or as a result of the Borrower's exercise of a prepayment option) prior to the stated maturity thereof; unless in each such case the obligee under or holder of such Debt or the trustee with respect to such Debt shall have waived in writing such circumstance without consideration having been paid by the Borrower so that such circumstance is no longer continuing; or (f) PSNH shall fail to pay any of its Debt when due (including any interest or premium thereon but excluding Debt aggregating less than $10,000,000 in principal amount at any one time) whether by scheduled maturity, required prepayment, acceleration, demand or otherwise, and such failure shall continue after the applicable grace period, if any, specified in any agreement or instrument relating to such Debt; or any other default under any agreement or instrument relating to any such Debt, or any other event, shall occur and shall continue after the applicable grace period, if any, specified in such agreement or instrument, if the effect of such default or event is to accelerate, or to permit the acceleration of, the maturity of such Debt; or any such Debt shall be declared to be due and payable, or required to be prepaid (other than by a regularly scheduled required prepay- ment or as a result of PSNH's exercise of a prepayment option) prior to the stated maturity thereof; unless in each such case the obligee under or holder of such Debt or the trustee with respect to such Debt shall have waived in writing such circumstance without consideration having been paid by PSNH so that such circumstance is no longer continuing; or (g) The Borrower or PSNH shall generally not pay its debts as such debts become due, or shall admit in writing its inability to pay its debts generally, or shall make an assignment for the benefit of creditors; or any proceeding shall be instituted by or against the Borrower or PSNH seeking to adjudicate it a bankrupt or insolvent, or seeking liquidation, winding up, reorganization, arrangement, adjustment, protection, relief, or composition of its debts under any law relating to bankruptcy, insolvency, or reorganiza- tion or relief of debtors, or seeking the entry of an order for relief or the appointment of a receiver, trustee, or other similar official for it or for any substantial part of its property and, in the case of a proceeding instituted against the Borrower or PSNH, as the case may be, the Borrower or PSNH, as the case may be, shall consent thereto or such proceeding shall remain undismissed or unstayed for a period of 90 days or any of the actions sought in such proceeding (including without limitation the entry of an order for relief against the Borrower or PSNH, as the case may be, or the appoint- ment of a receiver, trustee, custodian or other similar official for the Borrower or PSNH, as the case may be, or any of their respective properties) shall occur; or the Borrower or PSNH shall take any corporate or other action to authorize any of the actions set forth above in this subsection (g); or (h) Any judgment or order for the payment of money in excess of $10,000,000 shall be rendered against the Borrower or its properties, or any judgment or order for the payment of money in excess of $10,000,000 shall be rendered against PSNH or its properties, and, in either case, either (i) enforcement proceedings shall have been commenced by any creditor upon such judgment or order and shall not have been stayed or (ii) there shall be any period of 15 consecutive days during which a stay of enforcement of such judgment or order, by reason of a pending appeal or otherwise, shall not be in effect; or (i) Any material provision of any Loan Document, the Rate Agreement or any Significant Contract shall for any reason other than the express terms thereof or the exercise of any right or option expressly contained therein cease to be valid and binding on any party thereto except as otherwise expressly permitted by the exception contained in Section 7.02(h)(i) hereof; or any party thereto other than the Lenders shall so assert in writing, provided that in the case of any party other than the Borrower making such assertion in respect of any Significant Contract (or PSNH in the case of the Rate Agreement), such assertion shall not in and of itself constitute an Event of Default hereunder until (i) such asserting party shall cease to perform under and in compliance with the Rate Agreement or such Significant Contract, (ii) the Borrower (or PSNH, in the case of the Rate Agreement) shall fail to diligently prosecute, by appropriate action or proceedings, a rescission of such assertion or a binding determination as to the merits thereof or (iii) such a binding determination shall have been made in favor of such asserting party's position; or (j) The Borrower shall not have in full force and effect any or all insurance required under Section 7.01(c) hereof or there shall be incurred any uninsured damage, loss or destruction of or to the Borrower's properties in an amount not covered by insurance (including fully-funded self-insurance programs) which the Majority Lenders consider to be material; or (k) A default by the Borrower shall have occurred under the Unit Contract and shall not have been effectively cured within the time period specified therein for such cure (or, if no such time period is specified therein, 10 days); or a default by any party shall have occurred under any Significant Contract or by PSNH shall have occurred under the Rate Agreement and, in either such case, such default shall not have been effectively cured within 30 days after notice from the Administrative Agent to the Borrower stating that, in the opinion of the Majority Lenders, such default may have a material adverse effect upon the financial condition, operations, properties or prospects of the Borrower as a whole; or (l) Any Governmental Approval (whether federal, state or local) required to give effect to the Unit Contract or the Rate Agreement (includ- ing, without limitation, Chapter 362-C of the New Hampshire Revised Statutes and the enabling order of The New Hampshire Public Utilities Commission issued pursuant thereto) shall be amended, modified or supplemented, or any other regulatory or legislative action or change (whether federal, state or local) having the effect, directly or indirectly, of modifying the benefits or entitlements of the Borrower under the Unit Contract or of PSNH under the Rate Agreement shall occur, and in any such case such amendment, modifica- tion, supplement, action or change may have, in the opinion of the Majority Lenders, a material adverse effect upon the financial condition, operations, properties or prospects of the Borrower as a whole; or (m) NU shall cease to own all of the outstanding common stock of the Borrower and PSNH, in each case free and clear of any Liens. SECTION 8.02 Remedies Upon Events of Default. Upon the occurrence and during the continuance of any Event of Default, then, and in any such event, the Administrative Agent shall at the request, or may with the consent, of the Majority Lenders, upon notice to the Borrower (i) declare the Commitments and the obligation of each Lender to make Advances to be terminated, whereupon the same shall forthwith terminate, and (ii) declare the Notes, all interest thereon and all other amounts payable under this Agreement to be forthwith due and payable, whereupon the Notes, all such interest and all such amounts shall become and be forthwith due and payable, without presentment, demand, protest or further notice of any kind, all of which are hereby expressly waived by the Borrower; provided, however, that in the event of an actual or deemed entry of an order for relief with respect to the Borrower under the Federal Bankruptcy Code, (A) the Commitments and the obligation of each Lender to make Advances shall automatically be terminated and (B) the Notes, all such interest and all such amounts shall automatically become and be due and payable, without presentment, demand, protest or any notice of any kind, all of which are hereby expressly waived by the Borrower. ARTICLE IX THE ADMINISTRATIVE AGENT SECTION 9.01 Authorization and Action. Each Lender hereby (i) appoints and authorizes the Administrative Agent to take such action as agent on its behalf and to exercise such powers under this Agreement as are delegated to the Administrative Agent by the terms hereof, together with such powers as are reasonably incidental thereto and (ii) agrees that the Arrang- ers, in their capacities as such, shall have no duties or obligations hereunder. As to any matters not expressly provided for by any Loan Document (including, without limitation, enforcement or collection thereof), the Administrative Agent shall not be required to exercise any discretion or take any action, but shall be required to act or to refrain from acting (and shall be fully protected in so acting or refraining from acting) upon the instructions of the Majority Lenders, and such instructions shall be binding upon all Lenders; provided, however, that the Administrative Agent shall not be required to take any action which exposes the Administrative Agent to personal liability or which is contrary to this Agreement or applicable law. The Administrative Agent agrees to deliver promptly to each Lender notice of each notice given to it by the Borrower pursuant to the terms of this Agreement. SECTION 9.02 Administrative Agent's Reliance, Etc. Neither the Administrative Agent nor any of its directors, officers, agents or employees shall be liable for any action taken or omitted to be taken by it or them under or in connection with any Loan Document, except for its or their own gross negligence or wilful misconduct. Without limitation of the generality of the foregoing, the Administrative Agent: (i) may treat the payee of any Note as the holder thereof until the Administrative Agent receives and accepts a Lender Assignment entered into by the Lender which is the payee of such Note, as assignor, and an assignee, as provided in Section 10.07; (ii) may consult with legal counsel (including counsel for the Borrower), independent public accountants and other experts selected by it and shall not be liable for any action taken or omitted to be taken in good faith by it in accordance with the advice of such counsel, accountants or experts; (iii) makes no warranty or representation to any Lender and shall not be (nor shall any Arranger be) responsible to any Lender for the Information Memorandum or any other statements, warranties or representations made in or in connection with any Loan Document; (iv) shall not have any duty to ascertain or to inquire as to the performance or observance of any of the terms, covenants or conditions of any Loan Document on the part of the Borrower to be performed or observed, or to inspect any property (including the books and records) of the Borrower; (v) shall not be responsible to any Lender for the due execu- tion, legality, validity, enforceability, genuineness, sufficiency or value of any Loan Document, Significant Contract or any other instrument or document furnished pursuant hereto; and (vi) shall incur no liability under or in respect of any Loan Document by acting upon any notice, consent, certificate or other instrument or writing (which may be by telegram, cable or telex) believed by it to be genuine and signed or sent by the proper party or parties. SECTION 9.03 First Chicago, Barclays, Bank of Boston and Union and Affiliates. With respect to its Commitment and the Note issued to it, each of First Chicago, Barclays, Bank of Boston and Union shall have the same rights and powers under this Agreement as any other Lender and may exercise the same as though it were not the Administrative Agent or an Arranger, as the case may be, and the term "Lender" or "Lenders" shall, unless otherwise expressly indicated, include First Chicago, Barclays, Bank of Boston and Union, each in its individual capacity. First Chicago, Barclays, Bank of Boston and Union and their respective Affiliates may accept deposits from, lend money to, act as trustee under indentures of, and generally engage in any kind of business with, the Borrower, any of its subsidiaries and any Person who may do business with or own securities of the Borrower or any such subsidiary, all as if First Chicago, Barclays, Bank of Boston and Union were not the Administrative Agent or an Arranger, and without any duty to account therefor to the Lenders. SECTION 9.04 Lender Credit Decision. Each Lender acknowledges that it has, independently and without reliance upon the Administrative Agent, the Arrangers or any other Lender and based on the Information Memorandum and other financial information referred to in Section 6.01(e) and such other documents and information as it has deemed appropriate, made its own credit analysis and decision to enter into this Agreement. Each Lender also acknowledges that it will, independently and without reliance upon the Administrative Agent, the Co-Agents or any other Lender and based on such documents and information as it shall deem appropriate at the time, continue to make its own credit decisions in taking or not taking action under this Agreement. SECTION 9.05 Indemnification. The Lenders agree to indemnify the Arrangers and the Administrative Agent, in their respective capacities as such and to the extent not reimbursed by the Borrower, ratably according to the respective principal amounts of the Notes then held by each such Lender (or if no Notes are at the time outstanding or if any Notes are held by Persons which are not Lenders, ratably according to the respective Commit- ments of the Lenders), from and against any and all liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements of any kind or nature whatsoever which may be imposed on, incurred by, or asserted against the Arrangers or the Administrative Agent in their respective capacities as such in any way relating to or arising out of this Agreement or any action taken or omitted by the Arrangers or the Administrative Agent in their respective capacities as such under this Agreement, provided that no Lender shall be liable for any portion of such liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements resulting from the Arrangers or the Administrative Agent's gross negligence or willful misconduct. Without limitation of the foregoing, each Lender agrees to reimburse the Administra- tive Agent and the Arrangers promptly upon demand for its ratable share of any out-of-pocket expenses (including counsel fees) incurred by the Adminis- trative Agent and the Arrangers in connection with the preparation, execu- tion, delivery, administration, modification, amendment or enforcement (whether through negotiations, legal proceedings or otherwise) of, or legal advice in respect of rights or responsibilities under, this Agreement to the extent that the Administrative Agent and the Arrangers are entitled to reimbursement for such expenses pursuant to Section 10.04 but are not reimbursed for such expenses by the Borrower. SECTION 9.06 Successor Administrative Agent. The Administrative Agent may resign at any time by giving written notice thereof to the Lenders and the Borrower, with any such resignation to become effective only upon the appointment of a successor Administrative Agent pursuant to this Section 9.06. Upon any such resignation, the Majority Lenders shall have the right to appoint a successor Administrative Agent, which shall be an Arranger (unless each Arranger shall decline such appointment, in which case such successor Administrative Agent shall be a Lender or another commercial bank or trust company reasonably acceptable to the Borrower organized or licensed under the laws of the United States, or of any State thereof). If no successor Administrative Agent shall have been so appointed by the Majority Lenders, and shall have accepted such appointment, within 30 days after the retiring Administrative Agent's giving of notice of resignation, then the retiring Administrative Agent may, on behalf of the Lenders, appoint a successor Administrative Agent, which shall be an Arranger (unless each Arranger shall decline such appointment, in which case such successor Administrative Agent shall be a Lender or shall be another commercial bank or trust company organized or licensed under the laws of the United States or of any State thereof reasonably acceptable to the Borrower). In addition to the foregoing right of the Administrative Agent to resign, the Majority Lenders may remove the Administrative Agent at any time, with or without cause, concurrently with the appointment by the Majority Lenders of an Arranger as the successor Administrative Agent. Upon the acceptance of any appointment as Administrative Agent hereunder by a successor Administrative Agent and the execution and delivery by the Borrower and the successor Administrative Agent of an agreement relating to the fees to be paid to the successor Administra- tive Agent under Section 2.02(c) hereof in connection with its acting as Administrative Agent hereunder, such successor Administrative Agent shall thereupon succeed to and become vested with all the rights, powers, privileg- es and duties of the retiring Administrative Agent, and the retiring Adminis- trative Agent shall be discharged from its duties and obligations under this Agreement. After any retiring Administrative Agent's resignation or removal hereunder as Administrative Agent, the provisions of this Article IX shall inure to its benefit as to any actions taken or omitted to be taken by it while it was Administrative Agent under this Agreement. ARTICLE X MISCELLANEOUS SECTION 10.01 Amendments, Etc. No amendment or waiver of any provision of this Agreement or any Note, nor consent to any departure by the Borrower therefrom, shall in any event be effective unless the same shall be in writing and signed by the Majority Lenders, and then such waiver or consent shall be effective only in the specific instance and for the specific purpose for which given; provided, however, that no amendment, waiver or consent shall, unless in writing and signed by all the Lenders, do any of the following: (a) waive, modify or eliminate any of the conditions specified in Article V (other than Section 5.02(c)(i), (b) increase the Commitments of the Lenders that may be maintained hereunder or subject the Lenders to any additional obligations, (c) reduce the principal of, or interest on, the Notes, any Applicable Margin or any fees or other amounts payable hereunder, (d) postpone any date fixed for any payment of principal of, or interest on, the Notes or any fees or other amounts payable hereunder (other than fees payable to the Administrative Agent pursuant to Section 2.02(c) hereof), (e) change the percentage of the Commitments or of the aggregate unpaid principal amount of the Notes, or the number of Lenders which shall be required for the Lenders or any of them to take any action hereunder, (f) amend this Agreement or any Note in a manner intended to prefer one or more Lenders over any other Lender or (g) amend this Section 10.01; and provided, further, that no amendment, waiver or consent shall, unless in writing and signed by the Administrative Agent in addition to the Lenders required above to take such action, affect the rights or duties of the Administrative Agent under this Agreement or any Note. SECTION 10.02 Notices, Etc. All notices and other communications provided for hereunder and under the other Loan Documents shall be in writing (including telegraphic, telex, telecopy or cable communication) and mailed, telegraphed, telexed, telecopied, cabled or delivered, (i) if to the Borrow- er, at its address at 1000 Elm Street, P.O. Box 330, Manchester, New Hamp- shire 03105 (telecopy no. 603.669.2438), Attention: Treasurer, with a copy to NUSCO at its address at 107 Selden Street, Berlin, Connecticut 06037 (telecopy no. 203.665.5457), Attention: Assistant Treasurer; (ii) if to any Bank, at its Domestic Lending Office specified opposite its name on Schedule I hereto; (iii) if to any Lender other than a Bank, at its Domestic Lending Office specified in the Lender Assignment pursuant to which it became a Lender; and (iv) if to the Administrative Agent, at its address at One First National Plaza, Suite 0363, Chicago, Illinois 60670, Attention: Electric, Gas and Telecommunications Department; or, as to each party, at such other address as shall be designated by such party in a written notice to the other parties. All such notices and communications shall, when mailed, tele- graphed, telexed, telecopied or cabled, be effective five days after when deposited in the mails, or when delivered to the telegraph company, confirmed by telex answerback, telecopied or delivered to the cable company, respec- tively, except that notices and communications to the Administrative Agent pursuant to Article II, III, IV or IX shall not be effective until received by the Administrative Agent. SECTION 10.03 No Waiver of Remedies. No failure on the part of any Lender or the Administrative Agent to exercise, and no delay in exercising, any right hereunder or under any Note shall operate as a waiver thereof; nor shall any single or partial exercise of any such right preclude any other or further exercise thereof or the exercise of any other right. The remedies herein provided are cumulative and not exclusive of any remedies provided by law. SECTION 10.04 Costs, Expenses and Indemnification. (a) The Borrower agrees to pay on demand all costs and expenses, if any (including, without limitation, reasonable counsel fees and expenses), of (i) the Administrative Agent and each Arranger in connection with the preparation, negotiation, execution and delivery of the Loan Documents, the administration of the Loan Documents, and any proposed modification, amendment, or consent relating thereto; and (ii) the Administrative Agent, each Arranger and each Lender in connection with the enforcement (whether through negotiations, legal proceed- ings or otherwise) of this Agreement or the Notes. (b) The Borrower hereby agrees to indemnify and hold each Lender, each Arranger, the Administrative Agent and their respective officers, directors, employees, professional advisors and affiliates (each, an "Indemnified Person") harmless from and against any and all claims, damages, losses, liabilities, costs or expenses (including reasonable attorney's fees and expenses, whether or not such Indemnified Person is named as a party to any proceeding or investigation or is otherwise subjected to judicial or legal process arising from any such proceeding or investigation) which any of them may incur or which may be claimed against any of them by any person or entity (except to the extent such claims, damages, losses, liabilities, costs or expenses arise from the gross negligence or willful misconduct of the Indemnified Person): (i) by reason of or in connection with the execution, delivery or performance of any of the Loan Documents or any transaction contemplated thereby, or the use by the Borrower of the proceeds of any Advance; (ii) in connection with or resulting from the utilization, storage, disposal, treatment, generation, transportation, release or ownership of any Hazardous Substance (A) at, upon or under any property of the Borrower or any of its Affiliates or (B) by or on behalf of the Borrower or any of its Affiliates at any time and in any place; or (iii) in connection with any documentary taxes, assessments or charges made by any governmental authority by reason of the execution and delivery of any of the Loan Documents. (c) The Borrower's obligations under this Section 10.04 shall survive the assignment by any Lender pursuant to Section 10.07 and shall survive as well the repayment of all amounts owing to the Lenders, the Arrangers and the Administrative Agent under the Loan Documents and the termination of the Commitments. If and to the extent that the obligations of the Borrower under this Section 10.04 are unenforceable for any reason, the Borrower agrees to make the maximum contribution to the payment and satisfaction thereof which is permissible under applicable law. SECTION 10.05 Right of Set-off. (a) Upon the occurrence and during the continuance of any Event of Default, each Lender is hereby authorized at any time and from time to time, to the fullest extent permitted by law, to set off and apply any and all deposits (general or special, time or demand, provisional or final) at any time held and other indebtedness at any time owing by such Lender to or for the credit or the account of the Borrower against any and all of the obligations of the Borrower now or hereafter existing under this Agreement and the Note held by such Lender, irrespective of whether or not such Lender shall have made any demand under this Agreement or such Note and although such obligations may be unmatured. Each Lender agrees promptly to notify the Borrower after any such set-off and application made by such Lender, provided that the failure to give such notice shall not affect the validity of such set-off and application. The rights of each Lender under this Section are in addition to other rights and remedies (including, without limitation, other rights of set-off) which such Lender may have. (b) The Borrower agrees that it shall have no right of off-set, deduction or counterclaim in respect of its obligations hereunder, and that the obligations of the Lenders hereunder are several and not joint. Nothing contained herein shall constitute a relinquishment or waiver of the Borrower's rights to any independent claim that the Borrower may have against the Administrative Agent or any Lender, but no Lender shall be liable for the conduct of the Administrative Agent or any other Lender, and the Administra- tive Agent shall not be liable for the conduct of any Lender. SECTION 10.06 Binding Effect. This Agreement shall become effective when it shall have been executed by the Borrower and the Administrative Agent and when the Administrative Agent shall have been notified by each Bank that such Bank has executed it and thereafter shall be binding upon and inure to the benefit of the Borrower, the Administrative Agent and each Lender and their respective successors and assigns, except that the Borrower shall not have the right to assign its rights hereunder or any interest herein without the prior written consent of the Lenders. SECTION 10.07 Assignments and Participation. (a) Each Lender may assign to one or more banks or other entities all or a portion of its rights and obligations under this Agreement, the Notes and the Security Documents (including, without limitation, all or a portion of its Commitment, the Advances owing to it and the Note or Notes held by it) with the prior written consent of the Borrower to the extent the assignee thereunder is not then a Lender or an Affiliate of a Lender (which consent shall not be unreasonably withheld); provided, however, that (i) each such assignment shall be of a constant, and not a varying, percentage of all of the assigning Lender's rights and obligations under this Agreement, (ii) to the extent the assignee thereunder is not then a Lender or an Affiliate of a Lender, the amount of the Commitment or Note(s) to be held by such assignee (after giving effect to such assignment and any other assignments being made concurrently therewith to the same assignee by one or more other Lenders) shall in no event be less than $5,000,000, unless such assignment is of the entire amount of the assigning Lender's Commitment, and (iii) the parties to each such assignment shall execute and deliver to the Administrative Agent, for its acceptance and recording in the Register, a Lender Assignment, together with any Note or Notes subject to such assignment and a processing and recordation fee of $2,500. Upon such execution, delivery, acceptance and recording, from and after the effective date specified in each Lender Assignment, which effective date shall be at least five Business Days after the execution thereof, (x) the assignee thereunder shall be a party hereto and, to the extent that rights and obligations hereunder have been assigned to it pursuant to such Lender Assignment, have the rights and obligations of a Lender hereunder and (y) the Lender assignor thereunder shall, to the extent that rights and obligations hereunder have been assigned by it to an assignee pursuant to such Lender Assignment, relinquish its rights and be released from its obligations under this Agreement (and, in the case of a Lender Assignment covering all or the remaining portion of an assigning Lender's rights and obligations under this Agreement, such Lender shall cease to be a party hereto); provided, however, if an Event of Default shall have occurred and be continuing and the Administrative Agent shall have declared all Advances to be immediately due and payable hereunder a Lender may assign all or a portion of its rights and obligations without the prior written consent of the Borrower but otherwise in accordance with this Section. (b) By executing and delivering a Lender Assignment, the Lender assignor thereunder and the assignee thereunder confirm to and agree with each other and the other parties hereto as follows: (i) other than as provided in such Lender Assignment, such assigning Lender makes no represen- tation or warranty and assumes no responsibility with respect to any state- ments, warranties or representations made in or in connection with any Loan Document or the execution, legality, validity, enforceability, genuineness, sufficiency or value of any Loan Document or any other instrument or document furnished pursuant thereto; (ii) such assigning Lender makes no representa- tion or warranty and assumes no responsibility with respect to the financial condition of the Borrower or the performance or observance by the Borrower of any of its obligations under any Loan Document or any other instrument or document furnished pursuant thereto; (iii) such assignee confirms that it has received a copy of each Loan Document, together with copies of the financial statements referred to in Section 6.01(e) and such other documents and information as it has deemed appropriate to make its own credit analysis and decision to enter into such Lender Assignment; (iv) such assignee will, independently and without reliance upon the Administrative Agent, the Arrangers, such assigning Lender or any other Lender and based on such documents and information as it shall deem appropriate at the time, continue to make its own credit decisions in taking or not taking action under this Agreement and the Notes; (v) such assignee appoints and authorizes the Administrative Agent to take such action as agent on its behalf and to exercise such powers under this Agreement and the Notes as are delegated to the Administrative Agent by the terms thereof, together with such powers as are reasonably incidental thereto; and (vi) such assignee agrees that it will perform in accordance with their terms all of the obligations which by the terms of this Agreement and the Notes are required to be performed by it as a Lender. (c) The Administrative Agent shall maintain at its address referred to in Section 10.02 a copy of each Lender Assignment delivered to and accepted by it and a register for the recordation of the names and addresses of the Lenders and the Commitment of, and principal amount of the Advances owing to, each Lender from time to time (the "Register"). The entries in the Register shall be conclusive and binding for all purposes, absent manifest error, and the Borrower, the Administrative Agent and the Lenders may treat each Person whose name is recorded in the Register as a Lender hereunder for all purposes of this Agreement. The Register shall be available for inspection by the Borrower or any Lender at any reasonable time and from time to time upon reasonable prior notice. (d) Upon its receipt of a Lender Assignment executed by an assigning Lender and an assignee, together with any Note or Notes subject to such assignment and any consent required by Section 10.07(a), the Administrative Agent shall, if such Lender Assignment has been completed and is in substan- tially the form of Exhibit 10.07 hereto, (i) accept such Lender Assignment, (ii) record the information contained therein in the Register and (iii) give prompt notice thereof to the Borrower. Within five Business Days after its receipt of such notice, the Borrower, at its own expense, shall execute and deliver to the Administrative Agent in exchange for the surrendered Note or Notes a new Note to the order of such assignee in an amount equal to the Commitment assumed by it pursuant to such Lender Assignment and, if the assigning Lender has retained a Commitment hereunder, a new Note to the order of the assigning Lender in an amount equal to the Commitment retained by it hereunder. Such new Note or Notes shall be in an aggregate principal amount equal to the aggregate principal amount of such surrendered Note or Notes, shall be dated the effective date of such Lender Assignment and shall otherwise be in substantially the form of Exhibit 1.01A hereto. (e) Each Lender may sell participations to one or more banks or other entities in or to all or a portion of its rights and obligations under the Loan Documents (including, without limitation, all or a portion of its Commitment, the Advances owing to it and the Note or Notes held by it); provided, however, that (i) such Lender's obligations under this Agreement (including, without limitation, its Commitment to the Borrower hereunder) shall remain unchanged, (ii) such Lender shall remain solely responsible to the other parties hereto for the performance of such obligations, (iii) such Lender shall remain the holder of any such Note for all purposes of this Agreement, (iv) the Borrower, the Administrative Agent and the other Lenders shall continue to deal solely and directly with such Lender in connection with such Lender's rights and obligations under this Agreement, and (v) unless the Borrower shall have previously consented to the sale of such participation, the holder of any such participation, other than an Affiliate of such Lender, shall not be entitled to require such Lender to take or omit to take any action hereunder, except action (A) extending the time for payment of interest on, or the maturity of the principal amount of, the Notes or (B) reducing the principal amount of or the rate or amount of interest payable on the Notes. (f) Any Lender may, in connection with any assignment or participation or proposed assignment or participation pursuant to this Section 10.07, disclose to the assignee or participant or proposed assignee or participant, any information relating to the Borrower furnished to such Lender by or on behalf of the Borrower; provided that, prior to any such disclosure, the assignee or participant or proposed assignee or participant shall agree, in accordance with the terms of Section 10.08, to preserve the confidentiality of any Confidential Information received by it from such Lender. (g) If any Lender shall have delivered a notice to the Administrative Agent described in Section 4.03 (a), (b), (c) or (f) hereof, or shall become a non-performing Lender under Section 3.01(c) hereof, and if and so long as such Lender shall not have withdrawn such notice or corrected such non- performance in accordance with Section 3.01(c), the Borrower or the Adminis- trative Agent may demand that such Lender assign in accordance with Section 10.07 hereof, to one or more assignees designated by either the Borrower or the Administrative Agent (and reasonably acceptable to the other), all (but not less than all) of such Lender's Commitment, Advances, participation and other rights and obligations hereunder; provided that any such demand by the Borrower during the continuance of an Event of Default or an Unmatured Default shall be ineffective without the consent of the Majority Lenders. If, within 30 days following any such demand by the Administrative Agent or the Borrower, any such assignee so designated shall fail to tender such assignment on terms reasonably satisfactory to the Lender, or the Borrower and the Administrative Agent shall have failed to designate any such assign- ee, then such demand by the Borrower or the Administrative Agent shall become ineffective, it being understood for purposes of this provision that such assignment shall be conclusively deemed to be on terms reasonably satisfacto- ry to such Lender, and such Lender shall be compelled to tender such assign- ment forthwith, if such assignee (1) shall agree to such assignment in substantially the form of the Lender Assignment and (2) shall tender payment to such Lender in an amount equal to the full outstanding dollar amount accrued in favor of such Lender hereunder (as computed in accordance with the records of the Administrative Agent.) (h) Anything in this Section 10.07 to the contrary notwithstanding, any Lender may assign and pledge all or any portion of its Commitment and the Advances owing to it to any Federal Reserve Bank (and its transferees) as collateral security pursuant to Regulation A of the Board of Governors of the Federal Reserve System and any Operating Circular issued by such Federal Reserve Bank. No such assignment shall release the assigning Lender from its obligations hereunder. SECTION 10.08 Confidentiality. In connection with the negotiation and administration of this Agreement and the other Loan Documents, the Borrower has furnished and will from time to time furnish to the Administrative Agent and the Lenders (each, a "Recipient") written information which is identified to the Recipient when delivered as confidential (such information, other than any such information which (i) was publicly available, or otherwise known to the Recipient, at the time of disclosure, (ii) subsequently becomes publicly available other than through any act or omission by the Recipient or (iii) otherwise subsequently becomes known to the Recipient other than through a Person whom the Recipient knows to be acting in violation of his or its obligations to the Borrower, being hereinafter referred to as "Confidential Information"). The Recipient will not knowingly disclose any such Confiden- tial Information to any third party (other than to those persons who have a confidential relationship with the Recipient), and will take all reasonable steps to restrict access to such information in a manner designed to maintain the confidential nature of such information, in each case until such time as the same ceases to be Confidential Information or as the Borrower may otherwise instruct. It is understood, however, that the foregoing will not restrict the Recipient's ability to freely exchange such Confidential Information with prospective participants in or assignees of the Recipient's position herein, but the Recipient's ability to so exchange Confidential Information shall be conditioned upon any such prospective participant's entering into an understanding as to confidentiality similar to this provi- sion. It is further understood that the foregoing will not prohibit the disclosure of any or all Confidential Information if and to the extent that such disclosure may be required (i) by a regulatory agency or otherwise in connection with an examination of the Recipient's records by appropriate authorities, (ii) pursuant to court order, subpoena or other legal process or (iii) otherwise, as required by law; in the event of any required disclosure under clause (ii) or (iii), above, the Recipient agrees to use reasonable efforts to inform the Borrower as promptly as practicable. SECTION 10.09 Waiver of Jury Trial. The Borrower, the Administrative Agent, and the Lenders each hereby irrevocably waives all right to trial by jury in any action, proceeding or counterclaim arising out of or relating to this Agreement or any other Loan Document, or any other instrument or document delivered hereunder or thereunder. SECTION 10.10 Governing Law. This Agreement and the Notes shall be governed by, and construed in accordance with, the laws of the State of New York. The Borrower, the Lenders and the Administrative Agent each (i) irrevocably submits to the jurisdiction of any New York State Court or Federal court sitting in New York City in any action arising out of any Loan Document, (ii) agrees that all claims in such action may be decided in such court, (iii) waives, to the fullest extent it may effectively do so, the defense of an inconvenient forum and (iv) consents to the service of process by mail. A final judgment in any such action shall be conclusive and may be enforced in other jurisdictions. Nothing herein shall affect the right of any party to serve legal process in any manner permitted by law or affect its right to bring any action in any other court. SECTION 10.11 Relation of the Parties; No Beneficiary. No term, provision or requirement, whether express or implied, of any Loan Document, or actions taken or to be taken by any party thereunder, shall be construed to create a partnership, association, or joint venture between such parties or any of them. No term or provision of the Loan Documents shall be con- strued to confer a benefit upon, or grant a right or privilege to, any Person other than the parties hereto. SECTION 10.12 Execution in Counterparts. This Agreement may be executed in any number of counterparts and by different parties hereto in separate counterparts, each of which when so executed shall be deemed to be an original and all of which taken together shall constitute one and the same agreement. IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be executed by their respective officers thereunto duly authorized, as of the date first above written. NORTH ATLANTIC ENERGY CORPORATION By /s/David R. McHale Assistant Treasurer THE FIRST NATIONAL BANK OF CHICAGO, as Administrative Agent, as Arranger and as Bank By /s/ Kenneth J. Barn Authorized Agent BARCLAYS BANK PLC, as Arranger and as Bank By /s/ Sydney G. Dennis Associate Director THE FIRST NATIONAL BANK OF BOSTON, as Arranger and as Bank By /s/ Richard A. Low Division Executive UNION BANK, as Arranger and as Bank By /s/ John M. Edmonston Vice President LTCB Trust Company, as Bank By /s/ John J. Sullivan Executive Vice President CREDIT LYONNAIS, as Bank CREDIT LYONNAIS, NEW YORK BRANCH By /s/ R. J. Ivosevich Senior Vice President CREDIT LYONNAIS, CAYMAN ISLAND BRANCH By /s/ R. J. Ivosevich Senior Vice President FLEET BANK, N.A., as Bank By /s/ Suresh V. Chivukula Vice President SCHEDULE I NORTH ATLANTIC ENERGY COMPANY U.S. $225,000,000 TERM CREDIT AGREEMENT APPLICABLE LENDING OFFICES Eurodollar Name of Bank Domestic Lending Office Lending Office Barclays Bank PLC 75 Wall Street Nassau Branch New York, NY 10265 c/o Barclays Bank Attn: Customer Service 75 Wall Street Team I New York, NY 10265 Attn: Customer Service Team 1 Telephone: 212-412-5028 Telecopy: 212-412-5002 with a copy to: 222 Broadway, 12th Floor Same as Domestic Lending New York, NY 10038 Office Attn: Customer Service Team 1 Telephone: 212-412-5028 Telecopy: 212-412-5002 Credit Lyonnais, Credit Lyonnais, Cayman Credit Lyonnais, Cayman New York Branch Island Branch Island Branch c/o Credit Lyonnais, c/o Credit Lyonnais, New New York Branch York Branch 1301 Avenue of the Americas 1301 Avenue of the Americas 18th Floor 18th Floor New York, NY 10019 New York, NY 10019 Attention: Robert Wiezcorek Attention: Robert Wiezcorek Telephone: 212-261-7320 Telephone: 212-261-7320 Telecopy: 212-459-3179 Telecopy: 212-459-3179 with a copy to: with a copy to: Credit Lyonnais-Boston Office Credit Lyonnais-Boston 53 State Street Office Boston, MA 02109 53 State Street Attention: Lisa Leahy Boston, MA 02109 Telephone: 617-723-2615 Attention: Lisa Leahy Telecopy: 617-723-4803 Telephone: 617-723-2615 Telecopy: 617-723-4803 The First Nat'l Commercial Loan Services Same as Domestic Lending Bank of Boston 100 Federal Street 01-08-02 Office Boston, MA 02110 Attn: Debora Williams Telephone: 617-434-9623 Telecopy: 617-434-9820 with a copy to: with a copy to: 100 Federal Street 01-08-02 100 Federal Street 01-08-02 Boston, MA 02110 Boston, MA 02110 Attn: Michelle Appleby Attn: Michelle Appleby Telephone: 617-434-6477 Telephone: 617-434-6477 Telecopy: 617-434-3652 Telecopy: 617-434-3652 The First Nat'l One First National Plaza Same as Domestic Lending Bank of Chicago Suite 0636/1-10 Office Chicago, IL 60670 Attn: Lynn Pozsgay Telephone: 312-732-8705 Telecopy: 312-732-4840 Fleet Bank, N.A. One Constitution Plaza (CTHM Same as Domestic Lending M03G) Office Hartford, CT 06115 Attn: Suresh V. Chivukula Telephone: 860-244-6038 Telecopy: 860-244-5391 LTCB Trust 165 Broadway Same as Domestic Lending Company New York, NY 10006 Office Attn: Winston Brown Telephone: 212-608-3081 Telecopy: 212-608-3081 Union Bank 445 S. Figueroa Street Same as Domestic Lending 15th Floor Office Los Angeles, CA 90071 Attn: David Musicant Telephone: 213-236-5023 Telecopy: 213-236-4096 SCHEDULE II GOVERNMENTAL APPROVALS 1. Order No. 21,839 of the New Hampshire Public Utilities Commission, dated September 27, 1995 SCHEDULE III INVESTMENTS None SCHEDULE IV COMMITMENTS Bank Commitment The First National Bank of Chicago $42,500,000 Barclays Bank PLC $42,500,000 The First National Bank of Boston $42,500,000 Union Bank $42,500,000 Fleet Bank, N.A. $20,000,000 Credit Lyonnais, New York Branch $20,000,000 LTCB Trust Company $15,000,000 EXHIBIT 1.01A FORM OF NOTE $[insert amount of Lender's New York, New York Commitment] [November , 1995] FOR VALUE RECEIVED, the undersigned, NORTH ATLANTIC ENERGY CORPORATION, a corporation organized under the laws of the State of New Hampshire, (the "Borrower"), hereby promises to pay to the order of (the "Lender"), at the office of The First National Bank of Chicago, One First National Plaza, Chicago, Illinois 60670, on the Termination Date (as defined in the Credit Agreement referred to below), the principal sum of [AMOUNT OF COMMITMENT IN FIGURES] or, if less, the aggregate principal amount of all Advances (as defined in such Credit Agreement) made by the Lender to the Borrower outstanding on such Termination Date, in lawful money of the United States of America in immediately available funds, and to pay interest on such principal amount from time to time outstanding, in like funds, at said office, at a rate or rates per annum and payable on such dates as determined pursuant to such Credit Agreement. The Borrower further promises to pay additional interest, on demand, on any overdue principal and, to the extent permitted by law, overdue interest from their due dates at a rate or rates determined as set forth in the Credit Agreement. The Borrower hereby waives diligence, presentment, demand, protest and notice of any kind whatsoever. The nonexercise by the holder of any of its rights hereunder in any particular instance shall not constitute a waiver thereof in that or any subsequent instance. All borrowings evidenced by this Note and all payments and prepayments of the principal hereof and interest hereon and the respective dates thereof shall be endorsed by the holder hereof on the schedule attached hereto and made a party hereof, or on a continuation thereof which shall be attached hereto and made a part hereof, or otherwise recorded by such holder in its internal records; provided, however, that any failure of the holder hereof to make such a notation or any error in such notation shall not in any manner affect the obligation of the Borrower to make payments of principal and interest in accordance with the terms of this Note and the Credit Agreement. This Note is one of the Notes referred to in that certain Term Credit Agreement, dated as of November 9, 1995, among the Borrower, the Lenders and Arrangers referred to therein and the First National Bank of Chicago, as Administrative Agent thereunder (such Term Credit Agreement, as the same may be amended, modified or supplemented from time to time, being herein referred to as the "Credit Agreement") and is entitled to the benefits thereof. The Credit Agreement, among other things, contains provisions for the accelera- tion of the maturity hereof upon the happening of certain events, for prepayment (including mandatory prepayment) of the principal hereof prior to the maturity hereof and for the amendment or waiver of the Credit Agreement or the provisions thereof, all upon the terms and conditions therein speci- fied. This Note shall be construed in accordance with and governed by the laws of the State of New York and any applicable laws of the United States of America. NORTH ATLANTIC ENERGY CORPORATION By Title: GRID NOTE SCHEDULE COMPANY NAME: NORTH ATLANTIC ENERGY CORPORATION DATE OF ADVANCE/ CONVERSION AMOUNT OF INTEREST INTEREST NUMBER INTEREST DATE AMOUNT NOTED DATE PRINCIPAL RATE PERIOD OF DAYS DUE PAID PAID BY - ----------------------------------------------------------------------------- - ----------------------------------------------------------------------------- - ----------------------------------------------------------------------------- - ----------------------------------------------------------------------------- - ----------------------------------------------------------------------------- EXHIBIT 3.01A FORM OF NOTICE OF BORROWING [Date]1 The First National Bank of Chicago, as Administrative Agent for the Lenders referred to below, One First National Plaza Chicago, Illinois 60670 Attention: Ladies and Gentlemen: The undersigned, NORTH ATLANTIC ENERGY CORPORATION (the "Borrower"), refers to the Term Credit Agreement, dated as of November 9, 1995, among the Borrower, the Lenders and Arrangers referred to therein and the First National Bank of Chicago, as Administrative Agent thereunder (the "Credit Agreement"). Capitalized terms used herein and not otherwise defined herein shall have the meanings assigned to such terms in the Credit Agreement. Pursuant to Section 3.01 of the Credit Agreement, the Borrower hereby notifies you of the Funding Date and requests an initial Borrowing under the Credit Agreement. In that connection, the Borrower has hereinbelow specified the Funding Date and set forth the terms on which such Borrowing is requested to be made: (A) Funding Date and Date of initial Borrowing (which is a Business Day) --------------------- (B) Principal Amount of Borrowing2 --------------------- (C) Interest rate basis3 --------------------- (D) Initial Interest Period and the last day thereof4 --------------------- 1 Not later than 10:00 A.M. (New York City time) three Business days before the specified Funding Date. 2 Not less than $10,000,00 and in integral multiples of 1,000,000 in excess thereof (in the case of Eurodollar Rate Borrowings). 3 Eurodollar Advance or Base Rate Advance. 4 Which shall be subject to the definition of "Interest Period". The undersigned hereby represents, warrants and certifies that (i) the Closing Date has occurred, (ii) the Funding Date specified above is not more than 35 days following the Closing Date and will occur on or before December 31, 1995 and (iii) all other conditions precedent specified in Section 5.02 of the Credit Agreement have been or will be satisfied on such Funding Date. Very truly yours, NORTH ATLANTIC ENERGY CORPORATION By Title: EXHIBIT 3.02A FORM OF NOTICE OF CONVERSION [Date]1 The First National Bank of Chicago, as Administrative Agent for the Lenders referred to below, One First National Plaza Chicago, Illinois 60670 Attention: Ladies and Gentlemen: The undersigned, NORTH ATLANTIC ENERGY CORPORATION (the "Borrower"), refers to the Term Credit Agreement, dated as of November 9, 1995, among the Borrower, the Lenders and Arrangers referred to therein and the First National Bank of Chicago, as Administrative Agent thereunder (the "Credit Agreement"). Capitalized terms used herein and not otherwise defined herein shall have the meanings assigned to such terms in the Credit Agreement. Pursuant to Section 3.02 of the Credit Agreement, the Borrower hereby requests a Conversion under the Credit Agreement, and in that connection sets forth below the information relating to such Conversion (the "Proposed Conversion") as required by Section 3.02(a) of the Revolving Credit Agree- ment. (i) The Business Day of the Proposed Conversion is: , 19 . (ii) Type of, and Interest Period applicable to, the Advances (or portions thereof) proposed to be Converted: . (iii) Type of Advance to which such Advances (or portions thereof) are proposed to be Converted: . (iv) Except in the case of a Conversion to Base Rate Advances, initial Interest Period to be applicable to the Advances resulting from such Conversion: . (v) The aggregate amount of Advances (or portions thereof) proposed to be Converted: $ . The undersigned hereby certifies that on the date hereof, and on the date of the Proposed Conversion, no event has occurred and is continuing, or would result from such Proposed Conversion, which constitutes an Event of Default. Very truly yours, NORTH ATLANTIC ENERGY CORPORATION By Title: 1 Not later than 10:00 A.M. three Business Days prior to date of the proposed Conversion. EXHIBIT 10.07A LENDER ASSIGNMENT Dated , Reference is made to that certain Term Credit Agreement, dated as of November 9, 1995, among NORTH ATLANTIC ENERGY CORPORATION (the "Borrower"), the Lenders and Arrangers referred to therein and the First National Bank of Chicago, as Administrative Agent thereunder (said Agreement, as it may hereafter be amended or otherwise modified from time to time, being the "Credit Agreement"). Capitalized terms used herein and not otherwise defined herein shall have the meanings assigned to such terms in the Credit Agree- ment. Pursuant to the Credit Agreement, (the "Assignor") has committed to make advances ("Advances") to the Borrower, which Advances are evidenced by a promissory note (the "Note") issued by the Borrower to the Assignor. The Assignor and (the Assignee) agree as follows: 1. The Assignor hereby sells and assigns, without recourse, to the Assignee, and the Assignee hereby purchases and assumes from the Assignor, without recourse to the Assignor, a portion of the Assignor's rights and obligations under the Credit Agreement as of the Effective Date (as defined below) which represents the percentage interest specified on Schedule 1 of all outstanding rights and obligations of the Lenders under the Credit Agreement (the "Assigned Interest"), including, without limitation, such percentage interest in the Commitment as in effect on the Effective Date, the Advances outstanding on the Effective Date and the Notes. After giving effect to such sale and assignment, the Assignee's Commitment will be as set forth in Section 2 of Schedule 1. The effective date of this sale and assignment shall be the date specified on Schedule 1 hereto (the "Effective Date"). 2. On the Effective Date, the Assignee will pay to the Assignor, in same day funds, at such address and account as the Assignor shall advise the Assignee, the principal amount of the Advances outstanding under the Credit Agreement which are being assigned hereunder, and the sale and assignment contemplated hereby shall thereupon become effective. From and after the Effective Date, the Assignor agrees that the Assignee shall be entitled to all rights, powers and privileges of the Assignor under the Credit Agreement and the Note to the extent of the Assigned Interest, including without limitation (i) the right to receive all payments in respect of the Assigned Interest for the period from and after the Effective Date, whether on account of principal, interest, fees, indemnities in respect of claims arising after the Effective Date (subject to Section 10.04 of the Credit Agreement), increased costs, additional amounts or otherwise; (ii) the right to vote and to instruct the Administrative Agent under the Credit Agreement based on the Assigned Interest; (iii) the right to set-off and to appropriate and apply deposits of the Borrower as set forth in the Credit Agreement; and (iv) the right to receive notices, requests, demands and other communications. The Assignor agrees that it will promptly remit to the Assignee any amount received by it in respect of the Assigned Interest (whether from the Borrow- er, the Administrative Agent or otherwise) in the same funds in which such amount is received by the Assignor. 3. The Assignor (i) represents and warrants that it is the legal and beneficial owner of the interest being assigned by it hereunder and that such interest is free and clear of any adverse claim; (ii) makes no representation or warranty and assumes no responsibility with respect to any statements, warranties or representations made in or in connection with the Credit Agreement or the Notes or the execution, legality, validity, enforceability, genuineness, sufficiency or value of the Credit Agreement, the Notes or any other instrument or document furnished pursuant thereto; (iii) makes no representation or warranty and assumes no responsibility with respect to the financial condition of the Borrower or the performance or observance by the Borrower of any of its obligations under the Credit Agreement, the Notes or any other instrument or document furnished pursuant thereto; and (iv) attaches its Note and requests that the Administrative Agent obtain new Note[s] from the Borrower in accordance with the terms of subsection 10.07(d) of the Credit Agreement. 4. The Assignee (i) confirms that it has received a copy of the Credit Agreement, together with copies of the financial statements referred to in Section 6.01(e) thereof and such other documents and information as it has deemed appropriate to make its own credit analysis and decision to enter into this Lender Assignment; (ii) agrees that it will, independently and without reliance upon the Administrative Agent, the Arrangers, the Assignor or any other Lender and based on such documents and information as it shall deem appropriate at the time, continue to make its own credit decisions in taking or not taking action under the Credit Agreement and the Notes; (iii) appoints and authorizes the Administrative Agent to take such action as agent on its behalf and to exercise such powers under the Credit Agreement and the Notes as are delegated to the Administrative Agent by the terms thereof, together with such powers as are reasonably incidental thereto; (iv) agrees that it will perform in accordance with their terms all of the obligations which by the terms of the Credit Agreement and the Notes are required to be performed by it as a Lender; (v) specifies as its Domestic Lending Office (and address for notices) and Eurodollar Lending Office the offices set forth beneath its name on the signature pages hereof; (vi) attaches the forms prescribed by the Internal Revenue Service of the United States certifying as to the Assignee's status for purposes of determining exemption from United States withholding taxes with respects to all payments to be made to the Assignee under the Credit Agreement (and the Notes) or such other documents as are necessary to indicate that all such payments are subject to such rates at a rate reduced by an applicable tax treaty; and (vii) confirms that it has paid the processing and recordation fee referred to in subsection 10.07(a)(iii) of the Credit Agreement. 5. Following the execution of this Lender Assignment, it will be delivered to the Administrative Agent for acceptance and recording by the Administrative Agent. Upon such acceptance and recording and receipt of any consent of the Borrower required pursuant to subsection 10.07(a), as of the Effective Date, (i) the Assignee shall be a party to the Credit Agreement and, to the extent provided in this Lender Assignment, have the rights and obligations of a Lender thereunder and under the Notes and (ii) the Assignor shall, to the extent provided in this Lender Assignment, relinquish its rights and be released from its obligations under the Credit Agreement and the Notes. 6. Upon such acceptance, recording and consent, from and after the Effective Date, the Administrative Agent shall make all payments under the Credit Agreement and the Notes in respect of the interest assigned hereby (including, without limitation, all payments of principal, interest and commitment fees with respect thereto) to the Assignee. The Assignor and Assignee shall make all appropriate adjustments in payments under the Credit Agreement and the Notes for periods prior to the Effective Date directly between themselves. 7. This Lender Assignment shall be governed by, and construed in accordance with, the laws of the State of New York. IN WITNESS WHEREOF, the parties hereto have caused this Lender Assign- ment to be executed by their respective officers thereunto duly authorized, as of the date first above written, such execution being made on Schedule 1 hereto. Schedule 1 to Lender Assignment Dated , Section 1. Total Credit Agreement Commitments: $ Percentage Interest:1 % Amount of Assigned Share: $ Section 2. Assignee's Commitment: $ Section 3. Effective Date:2 , [NAME OF ASSIGNOR] By Title: [NAME OF ASSIGNEE] By Title: 1 Specify percentage to no more than 8 decimal points. 2 See Section 10.07(a). Such date shall be at least 5 Business Days after the execution of this Lender Assignment. Domestic Lending Office (and address for notices): [Address] Eurodollar Lending Office: [Address] Consented to this day of , NORTH ATLANTIC ENERGY CORPORATION By Title: Accepted this day of , THE FIRST NATIONAL BANK OF CHICAGO, as Administrative Agent By Title: EX-10.1 6 FIRST AMENDMENT TO PSNH RATE AGREEMENT EXHIBIT 10.16.1 FIRST AMENDMENT TO RATE AGREEMENT THIS FIRST AMENDATORY AGREEMENT dated as of December 5, 1989 is between the parties to the agreement dated as of November 22, 1989 (the "Rate Agreement") between Northeast Utilities Service Company, acting on behalf of its parent Northeast Utilities, and the Governor and Attorney General of the State of New Hampshire, acting on behalf of the State of New Hampshire (the State"). WHEREAS, the parties desire to amend the Rate Agreement in the respects specified below, and the Attorney General is authorized to act for the State in agreeing to such amendments. NOW, THEREFORE, in consideration of the mutual agreements below, the Parties agree as follows: 1. Amendment of Paragraph 3(a). Paragraph 3(a) of the Rate Agreement is hereby amended to read as follows: 3. NU System Capacity - (a) To assure an adequate supply of electric service to the ratepayers of New Hampshire, NU system companies shall provide capacity to Stand-Alone PSNH and NUNH after the First Effective Date through a contract or contracts for unit entitlements designed to provide capacity at the average cost of the NU system. (NU has provided the State with a designation of the generating units from which the capacity is expected to be provided and the estimated capacity cost per kilowatt year-by-year in Appendix A to a letter dated November 20, 1989 from counsel for NU to Larry Smukler, Senior Assistant Attorney General for the State of New Hampshire. A copy of that letter and Appendix A thereto is attached hereto as Exhibit F.) The capacity arrangement shall remain in effect for ten years unless the Merger Agreement is terminated. In the event the Merger Agreement is terminated, the capacity arrangement shall continue until October 31, 1995 or such earlier date as may be specified in a notice of cancellation given by Stand-Alone PSNH to NU after the effective date of such termination (the "Termination Date") and at least two years prior to the date on which such cancellation is to become effective, as Stand-Alone PSNH's capacity requirements, as determined in accordance with Paragraph 3(b) hereof. The capacity arrangement shall then terminate unless the Merger Agreement is terminated under circumstances which require NU to pay Stand-Alone PSNH termination fee under the Merger Agreement and Stand-Alone PSNH elects within six months of the Termination Date to extend the capacity arrangement until October 31, 1999. Stand-Alone PSNH shall specify in its notice of such election the number of megawatts of capacity it will require for each year under the arrangement. Stand-Alone PSNH shall provide the NU system companies right of first refusal to any of the capacity provided by the NU system companies that it proposes to resell. 2. Amendment of Schedule I to Exhibit A. The definition of "Recovery Period" in paragraph H of Schedule I to Exhibit A. to the Rate Agreement is hereby amended to read as follows: The Recovery Period shall begin on the date that is six months after the end of the "fixed rate period" (as that term is defined in the Agreement dated November 22, l989 between Northeast Utilities Service Company, on behalf of NU, and NH) and shall end on the date that is ten years after the letter of the In-Service Date or the First Effective Date. 3. Addition of Exhibit F. The attachment hereto which is identified as Exhibit F is hereby made Exhibit F to the Rate Agreement. IN WITNESS WHEREOF, each of the Parties has duly executed this First Amendatory Agreement. NORTHEAST UTILITIES SERVICE COMPANY By /s/Bernard M. Fox THE STATE OF NEW HAMPSHIRE By /s/John P. Arnold New Hampshire Attorney General EXHIBIT F November 20, 1989 Larry M. Smukler, Esq. Senior Assistant Attorney General Office of the Attorney General Sate House Annex Concord, NH 03301 Dear Larry: Enclosed as Appendix A to this letter are the updated capacity costs, transmission costs and the percentage of slice associated with the transfer of capacity from the NU system companies to PSNH. At Norman Stahl's request, this letter and Appendix A are cross-referenced in paragraph 3 of the proposed agreement between NU and the State of New Hampshire. This letter supersedes my prior letter to you of July 21, 1989. Very truly yours, /s/C. Duane Blinn Day, Berry and Howard Counsellors at Law CDB/vw Enclosure cc: Frederick J. Coolbroth, Esq. Mr. Robert E. Busch Thomas D. Rath, Esq. John B. Nolan, Esq. Gerald Garfield, Esq. John R. Bashaw, Esq. Jeffrey G. Grody, Esq. J. Miles Read, Esq. APPENDIX A CAPACITY COSTS ASSOCIATED WITH THE TRANSFER OF CAPACITY FROM THE NU SYSTEM COMPANIES TO PSNH. These capacity transfers are made from a slice of NU system units with slice percentages and total costs (including transmission) as shown below. Units Percentage of Slice (%) Millstone Unit 1 10.73 Millstone Unit 2 10.73 Millstone Unit 3 17.54 Middletown Unit 3 5.14 Middletown Unit 4 8.56 Montville Unit 6 8.77 Norwalk Harbor Unit 1 3.51 Norwalk Harbor Unit 2 3.72 South Meadow Unit 11 1.19 South Meadow Unit 12 1.19 South Meadow Unit 13 1.19 South Meadow Unit 14 1.19 Cos Cob Unit 10 0.58 Cos Cob Unit 11 0.58 Cos Cob Unit 12 0.58 Northfield 24.80 100.00 Estimated Estimated Slice of System Transmission Total Year Capacity Cost Cost Cost ($/KW-YR) ($/KW-YR) ($/KW-YR) 1990 184.2 10.0 194.2 1991 185.3 10.0 195.3 1991 184.4 10.0 194.4 1992 193.0 10.0 203.0 1994 183.7 10.0 193.7 1995 198.5 10.0 208.5 1996 183.2 10.0 193.2 The base rate level of the FPPAC assumes the following annual capacity needs for NUNH. These needs take into account a 25% allocation to NUNH of the capability responsibility benefit resulting from the combination of the NU system companies with NUNH as a single pool participant. Year Estimated NUNH Capacity Need (MW) 1990 0 1991 0 1992 0 1993 0 1994 0 1995 0 1996 0 EX-10.2 7 SECOND AMENDMENT TO PSNH RATE AGREEMENT EXHIBIT 10.16.2 SECOND AMENDMENT TO RATE AGREEMENT THIS SECOND AMENDATORY AGREEMENT dated as of December 12, 1989 is between the parties to the agreement dated as of November 22, 1989, as amended by the First Amendatory Agreement dated as of December 5, 1989 (the "Rate Agreement") between Northeast Utilities Service Company, acting on behalf of its parent Northeast Utilities, and the Governor and Attorney General of the State of New Hampshire, acting on behalf of the State of New Hampshire (the "State"). WHEREAS, the parties desire to amend the Rate Agreement in the respects specified below, and the Attorney General is authorized to act for the State in agreeing to such amendments. NOW, THEREFORE, in consideration of the mutual agreements below, the Parties agree as follows: 1. Amendment of Paragraph A and B of Exhibit B. The provisions of paragraphs A and B of the Return on Equity Collar on pages 1 through 3 of Exhibit B of the Rate Agreement are hereby amended to read as follows: A. In the event the cumulative average net income ROE ("NI ROE") for the entire fixed rate period, as defined below, for Stand-Alone PSNH, and/or Stand-Alone PSNH and NUNH exceeds 13.25% or more on a net present value basis ("NPV"), 100% of any excess above 13.25% will be applied first as a credit to reduce the amount of any unamortized SPP or NHEC deferrals or Seabrook cancellation cost deferrals and, in the event any amount remains after such application, the remainder will be credited to customer bills. The determination of such excess shall be made on an annual basis beginning twelve months after the Termination Date or the Acquisition Effective Date; or B. A prompt general rate increase or a surcharge of base rates will be implemented if the cumulative NPV average NI ROE for Stand-Alone PSNH and/or for Stand-Alone PSNH and NUNH is forecasted to fall below 8% in the third 12-month period after the rate increase described in paragraph 5(a)(ii) of the Agreement, 9% in the fourth, 9-3/4% in the fifth and 10-1/2% in the sixth 12-month period (whether or not any portion thereof falls within or outside of the fixed rate period) after the rate increase described in paragraph 5(a)(ii) of the Agreement which will permit the NI ROE to at least attain the specified minimum level for the period. No floor amount will be applicable from the First Effective Date through the second 12-month period after the effective date of the rate increase described in paragraph 5(a)(ii) of the Agreement. 2. Amendment of Paragraph B.D. of Exhibit C. The provisions of paragraph B.D) on pages 3 through 5 of Exhibit C. to the Rate Agreement are hereby amended to read as follows: D. The entire payment made to qualifying facilities ("QF") and other small power producers facilities (which includes both capacity and energy expenses). The FPPAC base amounts listed in Schedule 1 include costs based on the rates presently in effect for these facilities for the fixed rate period. The following rules shall be applicable to costs with respect to the eight specific small power producers (SPP's) listed in Schedule 2 hereto: For the period from the First Effective Date to 1/1/92, the difference between the actual costs paid to these SPP's and the assumed avoided cost will be deferred. The balance at 1/1/92 will be amortized in ten equal annual installments beginning in 1992. For each of the calendar years beginning 1992 through the end of the fixed rate period, the difference between the actual costs paid to these SPP's and the assumed avoided cost will be deferred and will be amortized in ten equal annual installments. In order to provide for a sharing of benefits resulting from a reduction in SPP costs, 90% of the above amortization will be included in the FPPAC during the fixed rate period and 90% of the total projected amortization based on the assumption that no reductions in SPP costs are achieved has been included in the FPPAC BA base during the fixed rate period. Commencing with the first year after the end of the fixed rate period, the amortization of any remainder of any such deferral as may exist will be included in this FPPAC and in each of the years in which there is an unamortized balance, such balance will be included in the rate base of NUNH for the purpose of determining revenue requirements. The assumed avoided cost for each year is as follows: Year Avoided Cost (cents/kWh) 1990 5.8 1991 6.0 1992 6.6 1993 6.8 1994 6.9 1995 7.2 1996 7.5 After FPPAC ceases to exist, any unrecovered balance will continue to be amortized through rates over the balance of the applicable amortization periods specified above. The FPPAC base amounts listed in Schedule 1 for the fixed rate period include estimates of the effects of the above deferrals, exclusions and amortization assuming there is no success in reducing the payments to the eight SPPs identified in Exhibit C - Schedule 2. 3 Amendment of Schedule 1 to Exhibit C. Schedule 1 to Exhibit C is amended to read as shown in the attachment hereto. IN WITNESS WHEREOF, each of the parties has duly executed this Second Amendatory Agreement. NORTHEAST UTILITIES SERVICE COMPANY By: /s/ Robert E. Busch Senior Vice President-Finance THE STATE OF NEW HAMPSHIRE By: /s/ John P. Arnold New Hampshire Attorney General ATTACHMENT EXHIBIT C - SCHEDULE 1 ANNUAL BASE RATE LEVEL OF THE FUEL CHARGE ("BA") IN THE FUEL AND PURCHASED POWER ADJUSTMENT CLAUSE ("FPPAC") Fuel and Purchased Power "BA" Seabrook Seabrook Pre-Commercial Post-Commercial Year Operation (cents/kWh) Operation (cents/kWh) 1990 3.291 3.444 1991 3.154 3.427 1992 3.263 3.760 1993 3.457 4.104 1994 3.609 4.429 1995 3.985 4.857 1996 4.213 5.054 Note: This base rate level of fuel and purchased power assumes an initial capital structure and cost for NEWCO as follows: Structure Cost Debt 80% 11.5 and 15.0% Equity 20% 13.75% At the Second Effective Date the base rate level fuel charges will be updated using the actual NEWCO capital structure and cost and to reflect the results of any renegotiation with the New Hampshire Electric Cooperative, Inc. It is intended that such updates will have no impact on total rates if the reference assumptions, as updated, are achieved ADOPTION WHEREAS, on November 22, 1989, Northeast Utilities Service Company ("NUSCO"), acting on behalf of its parent Northeast Utilities ("NU"), and the Governor and Attorney General of the State of New Hampshire, acting on behalf of the State of New Hampshire (the "State") entered into an agreement that expressed the obligations of NU and the State with respect to NU's proposed acquisition of Public Service Company of New Hampshire ("PSNH") and the consummation of NUSCO's plan of reorganization for PSNH (the "Plan"); and WHEREAS, said agreement between NUSCO and the State was amended on December 5, 1989, and December 12, 1989 (the November 22, 1989 agreement and the two subsequent amendments are referred to herein as the "Rate Agreement"); and WHEREAS, on April 20, 1990, the United States Bankruptcy Court for the District of New Hampshire confirmed NUSCO's Plan; and WHEREAS, the new Board of Directors for PSNH has authorized PSNH to adopt the Rate Agreement. NOW THEREFORE, pursuant to Paragraph 20 of the Rate Agreement, effective as of the date set forth below PSNH hereby adopts the Rate Agreement, and hereby agrees to be bound by all of the terms, conditions representations and obligations set forth therein as if PSNH were an original party to the Rate Agreement. IN WITNESS WHEREOF, PSNH has duly executed this Adoption as of the 10th day of July, 1990. PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE By: /s/ Leon E. Maglathlin Jr. Its: President ACCEPTED THE STATE OF NEW HAMPSHIRE By: /s/ John P. Arnold New Hampshire Attorney General ACCEPTED NORTHEAST UTILITIES SERVICE COMPANY By: /s/ William B. Ellis EX-10.3 8 THIRD AMENDMENT TO PSNH RATE AGREEMENT EXHIBIT 10.16.3 THIRD AMENDMENT TO THE RATE AGREEMENT This THIRD AMENDATORY AGREEMENT executed as of the date written below, is between the parties to the agreement dated as of November 22, 1989, as amended by the First Amendatory Agreement dated as of December 5, 1989, and the Second Amendatory Agreement dated as of December 12, 1989 (the "Rate Agreement") between Northeast Utilities Service Company, acting on behalf of its parent Northeast Utilities, and the Attorney General of the State of New Hampshire, acting on behalf of the State of New Hampshire (the "State"). WHEREAS, the parties desire to amend the Rate Agreement in the respects specified below, and the Attorney General is authorized to act for the State in agreeing to such amendments. NOW, THEREFORE, in consideration of the mutual agreement below, the Parties agree as follows: 1. Definition of "Cumulative Net Present Value of Earnings for Common" for Purposes of the James River/Wausau Papers Special Contracts. The paragraph in Exhibit B to the Rate Agreement establishing how PSNH's Cumulative Net Present Value of Earnings for Common shall be computed (DR 89-244, Ex. NU 1E, paragraph beginning on the third line from the bottom of page D-83 and carried over onto page D-84) shall, subject to the approval of the New Hampshire Public Utilities Commission (the "Commission"), be amended and restated as follows: The Cumulative Net Present Value of Earnings for Common shall be the sum of the present value of Stand-Alone PSNH or NUNH earnings for common as reported in the FERC Form No. 1 from the base year through the current year (i) adjusted to eliminate the effects of any accruals recorded for expected future refunds or rate increases as a result of the operation of this collar from the base year through the current year, (ii) if PSNH is acquired by NU, the earnings for common shall be further adjusted to eliminate any impacts of the Seabrook investment during the Interim Period, and (iii) shall be further adjusted to eliminate the effect of the discounts provided to James River Corporation in Special Contract Electricity NUPUC-71 and to Wausau Papers of New Hampshire in Special Contract - Electricity NUPUC-72, on file with the NHPUC on June 22, 1993. The present value of earnings for common shall be the earnings for common for the reported year divided by the present value factor applicable to that year. 2. Amendment of Paragraph 5 and 8 of the Rate Agreement to Prevent Compounding the Increases in Nuclear Decommissioning Costs. a. Amendment of Paragraph 5(a)(v). Paragraph 5(a)(v) of the Rate Agreement relative to adjustments in base rates in addition to the annual 5.5% base rate changes (DR 89-244, Ex. NU 1E, pages D-12 to D-13) shall, subject to the approval of the Commission, be amended and restated as follows: (v) except for changes required by subparagraphs (ii), (iii) and (iv) above, the only changes to base rates during the period commencing on the First Effective Date and ending six years after the effective date of the rate increase referred to in paragraph (a)(ii) (the "fixed rate period") will be ones to adjust rates (A) for legislative or regulatory changes such as changes to federal or state tax laws or regulations of environmental orders, regulations, and laws, which require capital expenditures of at least $20,000,000 or an increase or decrease in annual expenses of at least $2,000,000, or (B) to reflect changes required by the Nuclear Decommissioning Financing Committee in the level of monthly payments to be made into the Nuclear Decommissioning Fund from the level prescribed in the Committee's Seventeenth Supplemental Order of June 2, 1989, or (C) to provide revenues to accomplish programs mandated for Stand-Alone PSNH or NUNH by legislators or regulators, or (D) to recover costs associated with conservation and load management programs that have been undertaken with the specific approval of the NUPUC. In the event that a change or circumstance of the nature described in clause (A), (B), (C) or (D) above occurs, Stand-Alone PSNH (or NUNH) shall be entitled to file for a temporary rate increase, subject to refund, and the temporary rate increase if granted by the NHPUC will remain in effect until a final order by the NHPUC after a determination that the additional revenues are associated with the reasonable expenses caused by such change. Rate adjustments authorized under this paragraph, except for rate adjustments authorized by clause (B) above, will increase or decrease the ongoing base rate level which is subject to the 5.5% annual increases occurring in the remainder of the fixed rate period. In addition, to the extent any new accounting standards are promulgated during the fixed rate period, Stand-Alone PSNH (or NUNH) shall be entitled to the same general rate treatment accorded other utilities in the State by the NHPUC, including, but not limited to, new accounting rules currently being contemplated by the Financial Accounting Standards Board for Post-retirement benefits other than pensions. b. Amendment of Paragraph 8(a). Paragraph 8(a) of the Rate Agreement relative to the obligations for payments into the Nuclear Decommissioning Financing Fund and recovery of nuclear decommissioning costs (DR 89-244, Ex. NU 1E, page D-17) shall, subject to the approval of the Commission, (the "Commission"), be amended and restated as follows: 8. Decommissioning and Low Level Nuclear Waste. Seabrook decommissioning costs, at the level specified by the Nuclear Decommissioning Financing Committee's Seventeenth Supplemental Order of June 2, 1989, have been included in the rate increases provided in paragraph 5 of this Agreement. All decommissioning costs attributable to Stand-Alone PSNH's and later NEWCO's ownership interest in the Seabrook Project, including any adjustments ordered by the Nuclear Decommissioning Financing Committee to the levels of contributions in said Seventeenth Supplemental Order and subject to paragraph 5(a)(v)(B) in this Agreement, shall be collected from NUNH by NEWCO through Section E of Schedule I of the Unit Contract with respect to Seabrook Nuclear Power Plan, Unit No. 1 ("Power Contract") and in accordance with New Hampshire law. NEWCO will make all required payments to the Nuclear Decommissioning Financing Fund. c. Amendment of Paragraph 8(b). Paragraph 8(b) of the Rate Agreement relative to nuclear decommissioning costs treatment in the event of a premature decommissioning of Seabrook (DR 89-244, Ex. NU 1E, page D-18) shall, subject to the approval of the Commission, be amended and restated as follows: (b) In the event of premature decommissioning of Seabrook, decommissioning costs shall continue to be collected pursuant to paragraph (a) under the Power Contract with NEWCO, and the NHPUC shall permit the pass through to customers of the decommissioning costs NUNH pays to NEWCO in accordance with paragraphs 5(a)(v) and 8(a) of this Agreement and New Hampshire law. 3. Amendment of Paragraph B.E)(2) of Exhibit C - Delay in Recovery of Deferred Seabrook Capital Expense. Paragraph B.E)(2) of Exhibit C to the Rate Agreement relative to costs paid to NEWCO under the Seabrook Power Contract that are recovered under FPPAC (DR 89-244, Ex. NU 1E, page D-96) shall, subject to the approval of the Commission, be amended and restated as follows: (2) After the Second Effective Date, the entire payment made under the Power Contract after Seabrook operates (but excluding decommissioning payments which are to be made directly to the state Nuclear Decommissioning Fund and which are included in the rates provided in paragraph 5 of the Agreement); except for depreciation or amortization of, and a return on, Stand-Alone PSNH's share of costs incurred after the First Effective Date to place Seabrook in commercial operation which are determined by the NHPUC to be imprudent in accordance with subparagraph (3) of this paragraph E; provided, however, the charges made by NEWCO and collected from NUNH under paragraph U of Schedule I of the Power Contract for the period from December 1, 1997 through May 31, 1998 will be deferred, with interest paid on the unrecovered balance at three percent (3.00%), and thereafter will be recovered through FPPAC beginning June 1, 1998 over a thirty-six month period on an amortization basis comparable to that described in paragraph H of Schedule I in addition to the Deferred Capital Expenses expected to be collected under paragraph H of Schedule I of the Power Contract. IN WITNESS WHEREOF, each of the Parties has duly executed this Third Amendatory Agreement as of the day and year first above written. NORTHEAST UTILITIES SERVICE Company By: /s/ John W. Noyes Date: December 28, 1993 THE STATE OF NEW HAMPSHIRE By: /s/ Jeffrey R. Howard Date: December 3, 1993 EX-10.4 9 FOURTH AMENDMENT TO PSNH RATE AGREEMENT EXHIBIT 10.16.4 FOURTH AMENDMENT TO THE RATE AGREEMENT THIS FOURTH AMENDATORY AGREEMENT dated as of the date last written below is between the parties to the agreement dated as of November 22, 1989, as amended by the First Amendatory Agreement dated as of December 5, 1989, the Second Amendatory Agreement dated as of December 12, 1989, and the Third Amendatory Agreement dated as of December 28, 1993 (the "Rate Agreement") between Northeast Utilities Service Company, acting on behalf of its parent Northeast Utilities, and the Governor and Attorney General of the State of New Hampshire, acting on behalf of the State of New Hampshire (the "State"). WHEREAS, the parties desire to amend the Rate Agreement in the respects specified below, and the Attorney General is authorized to act for the State in agreeing to such amendments. NOW, THEREFORE, in consideration of the mutual agreement below, the Parties agree as follows: I. By Report and Order No. 21,090 in Dockets DR 93-092 and DE 93-114, North Atlantic Energy Corporation (NAEC) was granted permission to purchase and acquire an ownership interest in Seabrook Station Unit I from the Vermont Electric Generation and Transmission Cooperative, Inc. Pursuant to the same order, the Commission accepted a recommendation to approve PSNH's decision to enter into a unit power sales contract with NAEC under which PSNH would purchase the output of this new ownership interest from NAEC. These approvals were conditioned upon there being no change in rates paid by customers of PSNH under base assumptions. The transfer of ownership was completed on February 15, 1994. II. In order to accomplish the objective of generating no increase in base rates due to the newly acquired interest in Seabrook, the "BA" assumptions under the Exhibit C, Schedule 1 of the Rate Agreement, as amended, need to be recalculated. A change to the "BA" assumptions necessitates an amendment to the Rate Agreement. The Parties hereby agree that the Rate Agreement is amended so that base rates reflect the "BA" figures which are depicted in Schedule A to this Fourth Amendment. This Fourth Amendment is subject to the approval of the New Hampshire Public Utilities Commission under Paragraph 17 of the Rate Agreement. III. This Fourth Amendment is executed by the parties subject to the approval of PSNH creditors and the New Hampshire Public Utilities Commission. IN WITNESS WHEREOF, each of the Parties has duly executed this Fourth Amendatory Agreement as of the day and year first above written. NORTHEAST UTILITIES SERVICE COMPANY By /s/ John J. Roman Date: 9-9-94 THE STATE OF NEW HAMPSHIRE Jeffrey R. Howard Attorney General By /s/ Wynn E. Arnold, Assistant Attorney General Date: 9-21-94 SCHEDULE A PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE RESTATEMENT OF THE FPPAC BA FACTOR REFLECTING EFFECT OF VEG&T ENTITLEMENT (1) 1994 Updated, Restated 1994 Calculation of BA Change Costs Using Act. (2) Updated, Restated for Effect of the VEG&T NAEC Capital Adjust for Reflecting Seabrook Entitlement Structure VEG&T VEG&T - ----------------------------------------------------------------------------- - - Energy costs for own generating units, purchases and sales of energy in Accounts 501, 518, 547 and 555 103,285 103,285 Small power producer costs net of amortizations 109,767 109,767 Seabrook Power Contract, non energy 133,419 1,352 134,771 NHEC buyback agreement costs, non energy 7,864 7,864 NU to NUNH slice transfer of capacity - 0 Costs of Sharing Agreement and NEPOOL (24,937) (24,937) - ---------------------------------------------------------------------------- Total Amount - ENf 329,398 1,352 330,750 Total Amount - PCf - - - Total Amount - EA - - - - ---------------------------------------------------------------------------- Total Costs 329,398 1,352 330,750 ============================================================================ Total system requirements - kWh Req. 8,511,000 8,511,000 Delivery Efficiency - DE .930233 .930233 - ---------------------------------------------------------------------------- Net system sales 7,917,213 7,917,213 ============================================================================ Base Factor - BA ($/KWh) $ .04161 $ .04178 ============================================================================ (1) As filed in Docket DR 92-165 (2) Reflects the impact of the VEG&T entitlement on Joint Dispatch Savings and the prospective level of Seabrook Nuclear Property Tax approved by the State in House Bill 53 on April 16, 1993. SCHEDULE A PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE RESTATEMENT OF THE FPPAC BA FACTOR REFLECTING EFFECT OF VEG&T ENTITLEMENT (1) 1995 Updated, Restated 1995 Calculation of BA Change Costs Using Act. (2) Updated, Restated for Effect of the VEG&T NAEC Capital Adjust Reflecting Seabrook Entitlement Structure for VEG&T VEG&T - ----------------------------------------------------------------------------- Energy costs for own generating units, purchases and sales of energy in Accounts 501, 518, 547 and 555 124,292 124,292 Small power producer costs net of amortizations 116,190 116,190 Seabrook Power Contract, non energy 147,284 1,268 148,552 NHEC buyback agreement costs, non energy 8,625 8,625 NU to NUNH slice transfer of capacity - 0 Costs of Sharing Agreement and NEPOOL (20,301) (20,301) Total Amount - ENf 376,090 1,268 377,358 Total Amount - PCf - - - Total Amount - EA - - - - ----------------------------------------------------------------------------- Total Costs 376,090 1,268 377,358 ============================================================================= Total system requirements - kWh Req. 8,751,000 8,751,000 Delivery Efficiency - DE .930233 .930233 - ----------------------------------------------------------------------------- Net system sales 8,140,469 8,140,469 ============================================================================= Base Factor - BA ($/KWh) $ .04620 $ .04636 ============================================================================= (1) As filed in Docket DR 92-165 (2) Reflects the impact of the VEG&T entitlement on Joint Dispatch Savings and the prospective level of Seabrook Nuclear Property Tax approved by the State in House Bill 53 on April 16, 1993. SCHEDULE A PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE RESTATEMENT OF THE FPPAC BA FACTOR REFLECTING EFFECT OF VEG&T ENTITLEMENT (1) 1996 Updated, Restated 1996 Calculation of BA Change Costs Using Act. (2) Updated, Restated for Effect of the VEG&T NAEC Capital Adjust for Reflecting Seabrook Entitlement Structure VEG&T VEG&T - --------------------------------------------------------------------------- Energy costs for own generating units, purchases and sales of energy in Accounts 501, 518, 547 and 555 145,862 145,862 Small power producer costs net of amortizations 122,602 122,602 Seabrook Power Contract, non energy 154,211 1,119 155,330 NHEC buyback agreement costs, non energy 10,019 10,019 NU to NUNH slice transfer of capacity - 0 Costs of Sharing Agreement and NEPOOL (20,204) (20,204) - -------------------------------------------------------------------------- Total Amount - ENf 412,490 1,119 413,609 Total Amount - PCf - - - Total Amount - EA - - - - -------------------------------------------------------------------------- Total Costs 412,490 1,119 413,609 ========================================================================== Total system requirements - kWh Req. 8,974,000 8,974,000 Delivery Efficiency - DE .930233 .930233 - -------------------------------------------------------------------------- Net system sales 8,347,911 8,347,911 ========================================================================= Base Factor - BA ($/KWh) $ .04941 $ .04955 ========================================================================= (1) As filed in Docket DR 92-165 (2) Reflects the impact of the VEG&T entitlement on Joint Dispatch Savings and the prospective level of Seabrook Nuclear Property Tax approved by the State in House Bill 53 on April 16, 1993. EX-10.5 10 FIFTH AMENDMENT TO PSNH RATE AGREEMENT EXHIBIT 10.16.5 FIFTH AMENDMENT TO RATE AGREEMENT This Fifth Amendment to Rate Agreement ("Amendment"), dated as of the date last written below, is entered into by and between Northeast Utilities Service Company ("NUSCO"), acting on behalf of its parent Northeast Utilities ("NU"), and the Attorney General of the State of New Hampshire, acting on behalf of the State of New Hampshire. WITNESSETH: WHEREAS, the parties hereto are parties to that certain "Agreement" identified at RSA 362-C:2(I) (the "Rate Agreement"), as subsequently amended; and WHEREAS, pursuant to Section 17 of the Rate Agreement, NUSCO and the Attorney General may enter into modifications of the Rate Agreement as necessary, and in circumstances when the New Hampshire Public Utilities Commission ("Commission") is not designated to act; and WHEREAS, Section 12 of the Rate Agreement provides for the renegotiation of, among other things, power sales arrangements between Public Service Company of New Hampshire ("PSNH") and several small power producers identified at Exhibit D of the Rate Agreement; and WHEREAS, on August 4, 1994 (supplemented by an addendum dated August 17, 1994), PSNH and several other parties filed a "Joint Settlement" in New Hampshire Public Utilities Commission Docket No. DR 93-179, resolving all issues with respect to the implementation of two "Settlement Agreements" between PSNH and two of the small power producers identified in Exhibit D of the Rate Agreement; and WHEREAS, the parties to this Amendment desire to ensure consistency between the terms of the Joint Settlement and the Rate Agreement; NOW THEREFORE, the parties hereto agree as follows: 1. Condition to Effectiveness. This Amendment shall become effective only on the condition that the Joint Settlement and this Amendment are approved by the Commission. 2. Amendment to Rate Agreement Re: Wood Plants. The Rate Agreement is hereby amended to the limited extent necessary to allow for the implementation of the Joint Settlement according to its terms, as such terms may be approved, modified or implemented by order of the Commission; PROVIDED, that this Amendment shall not: (i) apply to, and may not be construed as authorizing or implementing, or as precedent with respect to, any other past or future transactions with any small power producers identified in the Rate Agreement. Without limiting the foregoing, the Rate Agreement is amended as follows: A. PSNH will provide a total of $2.5 million during the "fixed rate period under the Rate Agreement as guaranteed savings from the two Settlement Agreements. These guaranteed savings will be applied to the IPP deferral account and FPPAC as per the Joint Settlement. B. Of this amount of guaranteed savings, PSNH shall be allocated a total of $550,000 as its share of savings under the Joint Settlement. C. PSNH costs associated with the "mitigation funds" created under the Settlement Agreements, and issuance costs and increased business profits tax liabilities associated with closing on Settlement Agreement transactions will be set up in separate accounts to be amortized at a rate of 10% per year and recovered through FPPAC during the remainder of the fixed rate period. After the fixed rate period the remaining unamortized balances of these accounts will be recovered through rates in a manner determined in the Commission. D. The "Payment Amounts" under the Settlement Agreements will be added to the IPP deferral account, and made subject to 10-year amortization schedules. During the fixed rate period of 100% of the savings associated with the Settlement Agreements will be applied to the IPP deferral account. After the fixed rate period, 50% of the savings provided by the Settlement Agreements will be applied to the IPP deferral accounts, and 50% flowed to PSNH wholesale and retail customers through FPPAC or any successor clause designated by the Commission. This Fifth Amendment is executed by the parties subject to the approval of PSNH creditors and the New Hampshire Public Utilities Commission. IN WITNESS WHEREOF, each of the parties has duly executed this Fifth Amendment to Rate Agreement pursuant to Section 17 of the Rate Agreement. NORTHEAST UTILITIES SERVICE COMPANY By: /s/ John J. Roman Date: 9-9-94 THE STATE OF NEW HAMPSHIRE By its attorneys, Jeffrey R. Howard Attorney General /s/ Wynn E. Arnold Assistant Attorney General Civil Bureau 33 Capitol Street Concord, N.H. 03301-6397 (603) 271-3658 EX-10.6 11 32ND AMENDMENT TO NEPOOL AGREEMENT EXHIBIT 10.23.5 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, 1995, and as proposed to be amended by a pending amendment dated as of July 1, 1995 (Participant) By: Name: Title: Address: 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. EX-10.7 12 THIRD AMENDMENT TO THE SERP EXHIBIT 10.36.3 AMENDMENT NO. 3 TO SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN FOR OFFICERS OF NORTHEAST UTILITIES SYSTEM COMPANIES The first sentence of the definition of "Compensation" in Section II of the Supplemental Executive Retirement Plan for Officers of Northeast Utilities System Companies is hereby amended to read as follows, effective as of January 1, 1996: "Compensation" shall have the same meaning as provided in the Retirement Plan, but shall also include amounts disregarded pursuant to Section 401(a)(17) of the Code, amounts (included in Compensation as earned) receipt of which is deferred by a Participant pursuant to a plan or agreement that is not qualified under the Code, and, for any period in question, awards under the EICP and the Incentive Plan to the extent made with respect to performance during such period, each such award to be allocated on a pro rata basis to each of the calendar months in the period to which it relates. EX-10.8 13 NU DEFERRED COMPENSATION PLAN FOR TRUSTEES EXHIBIT 10.39 NORTHEAST UTILITIES DEFERRED COMPENSATION PLAN FOR TRUSTEES AMENDED AND RESTATED DECEMBER 13, 1994 Each Trustee of Northeast Utilities (NU) who is not an employee of NU or any of its affiliated companies may elect to defer payment to him or her of compensation for his or her services as a member of the NU Board of Trustees and committees thereof during any calendar year (excluding from the term "compensation" reimbursement of travel and other incidental expenses incurred for the benefit of, and in the course of rendering services to, NU) on the following basis: l. An election by a Trustee to defer payment of compensation shall apply to all or any portion of cash and/or NU common share compensation earned during a calendar year and shall be made in writing to the Secretary of NU prior to the beginning of each calendar year, provided, that each newly elected Trustee may make an election to defer payment of compensation for services to be rendered during the year of his or her election as a Trustee at the time of, or following his or her election but prior to the date of the rendering of the first services for which compensation is to be deferred. Such election, once made, shall be irrevocable for the period for which it is made. 2. NU shall establish for each Trustee who elects to defer cash compensation a "Deferred Cash Compensation Account" (which shall be solely a book account) to which NU shall credit on the last day of each calendar quarter (a) an amount equal to the cash compensation which would otherwise have been paid to such Trustee during that calendar quarter and (b) interest at the rate set forth in Section 37-l of the Connecticut General Statutes (as amended from time to time) on the amount standing in such Trustee's Deferred Cash Compensation Account as of the beginning of such quarter reduced by the amount of any payments made during the first six weeks of that quarter under paragraphs 3 and 4 of this plan. NU shall establish for each Trustee who elects to defer NU common share compensation a "Deferred Stock Compensation Account" (which shall be solely a book account) to which NU shall credit (a) on each date such shares would otherwise have been paid to such Trustee, an amount equal to the number of shares which would otherwise have been paid to such Trustee on such date and (b) on each date on which a dividend, stock split, split up, stock dividend, or dividend in kind or similar payment is made or corporate change resulting in a payment to NU common shareholders becomes effective ("accretions"), an amount equal to the number of NU common shares that could have been purchased with such accretions with respect to the shares in such Deferred Stock Compensation Account, assuming that each such accretion was reinvested in additional NU common shares on the date paid, at a rate equal to the closing price of an NU common share on the New York Stock Exchange on such date. Within thirty days following the end of each calendar year NU shall provide each Trustee for whom a Deferred Cash and/or Deferred Stock Compensation Account has been established with a statement of the amount standing to his or her credit as of the end of that year. 3. At the time of each election to defer payment of compensation, a Trustee shall also elect to receive distribution of the amounts credited to his or her Deferred Cash and/or Deferred Stock Compensation Account, as the case may be, during the period for which such election is made, together with the interest and/or accretions thereon, as the case may be, upon, or commencing with, the occurrence of one of the following events: termination of service on the Board for any reason or a specified date which is after the period for which the election is made. Such election, once made, shall be irrevocable as to amounts credited with respect to the period for which the election is made. 4. At the time of each election to defer payment of compensation, a Trustee shall designate whether, upon or commencing with the occurrence of one of the events set forth in paragraph 3, the amounts credited to his or her Deferred Cash and/or Deferred Stock Compensation Account, as the case may be, during the period for which such election is made, together with the interest and/or accretions thereon, as the case may be, shall be paid to him or her in a lump sum or in not more than five approximately equal annual installments. Such election, once made, shall be irrevocable as to amounts credited with respect to the period for which the election is made. 5. In the event that a Trustee shall die prior to the payment to him or her of all amounts credited to his or her Deferred Cash and Deferred Stock Compensation Accounts, the balance credited to such accounts at the time of his or her death shall be paid to such beneficiaries as he or she shall have designated in writing to the Secretary of NU (which designation may be changed from time to time) or, in the absence of such a designation, to the estate of such Trustee. 6. The amounts standing in Deferred Cash or Deferred Stock Compensation Accounts shall be unfunded obligations of NU payable only under the terms stated herein, and Trustees shall have no right or claim against any specified assets of NU and shall have only a contractual right against NU hereunder. Any payment to a Trustee from a Deferred Stock Compensation Account shall be made in NU common shares purchased in the open market, except as otherwise may be provided from time to time by the Board of Trustees. 7. No Deferred Cash or Deferred Stock Compensation Account shall be subject in any manner to anticipation, alienation, sale, transfer, assignment, pledge or encumbrance by a Trustee or any person claiming under or through him or her, nor shall it be subject to the debts, contracts, liabilities, engagements or torts of a Trustee or anyone else prior to actual payment thereof. 8.This Plan may be amended or terminated by the Board of Trustees at any time; provided, no such amendment or termination shall serve to diminish the rights of a Trustee with respect to amounts credited to his or her Deferred Cash and/or Deferred Stock Compensation Accounts or accelerate payment of such amounts. 9.Nothing contained in this Plan shall be construed as an obligation of NU to secure the re-election of any person as a Trustee of NU, or as an obligation of any person to stand for re-election as a Trustee of NU or as a prohibition against the resignation of any person as a Trustee. EX-10.9 14 NU DEFERRED COMP PLAN FOR OFFICERS EXHIBIT 10.40 DEFERRED COMPENSATION PLAN FOR OFFICERS OF NORTHEAST UTILITIES SYSTEM COMPANIES ADOPTED SEPTEMBER 23, 1986 Each Officer of Northeast Utilities and/or its subsidiary companies (hereinafter "the Company") may elect to defer payment to him or her of up to 75 percent of compensation for his or her services as an employee of a Northeast Utilities system company on the following basis: 1. "Compensation" shall mean an officer's base salary, less any pre-tax deductions (e.g., pre-tax deductions under the 401(k) Plan or the Flexible Benefits Program). An election by an Officer to defer payment of compensation shall apply to a selected percentage, but not more than 75 percent, of compensation earned during a calendar year. An election to defer compensation shall be made in writing to the Vice President and Controller of Northeast Utilities Service Company (NUSCO) prior to the beginning of each calendar year, provided, an election to defer payment of compensation for services to be rendered during the calendar year 1986 shall be made no later than September 30, 1986 and shall be applicable only to compensation earned after that date. In addition, each newly elected Officer may make an election to defer payment of compensation for services to be rendered during the year of his or her election as an Officer, provided that such election to defer payment of compensation shall be made within 30 days after his or her election as an Officer and shall be made prior to the date of the rendering of the first services for which compensation is to be deferred. Such election, once made, shall be irrevocable for the period for which it is made. 2. NUSCO shall establish for each Officer who elects to defer compensation a "Deferred Compensation Account" (which shall be solely a book account) to which NUSCO shall credit on the last day of each month (a) an amount equal to the selected percentage of compensation which would otherwise have been paid to such Officer during that calendar month and (b) interest at the rate set forth in Section 37-1 of the Connecticut General Statutes (as amended from time to time) on the amount standing in such Officer's Deferred Compensation Account as of the beginning of such month reduced by the amount of any payments made during the first two weeks of that month under paragraphs 3 and 4 of this Plan. Within sixty days following the end of each calendar year, NUSCO shall provide each Officer for whom a Deferred Compensation Account has been established with a statement of the amount standing to his or her credit as of the end of that year. 3. At the time of each election to defer payment of compensation, an Officer shall also elect when such deferred compensation, together with the interest accrued thereon, shall be distributed to him or her. Such distribution must occur upon or commence with (i) termination of employment with a Northeast Utilities system company for any reason or (ii) a specified date which is after the period for which the election is made. Such election, once made, shall be irrevocable as to amounts credited with respect to the period for which the election is made. 4. At the time of each election to defer payment of compensation, an Officer shall designate whether, upon or commencing with the occurrence of one of the events set forth in paragraph 3, the amounts credited to his or her Deferred Compensation Account during the period for which such election is made, together with the interest thereon, shall be paid to him or her in a lump sum or in not more than five approximately equal annual installments which shall be paid during the first thirty days of each year. Such election, once made, shall be irrevocable as to amounts credited with respect to the period for which the election is made. 5. In the event that an Officer shall die prior to the payment to him or her of all amounts credited to his or her Deferred Compensation Account, the balance credited to such account at the time of his or her death shall be paid to such beneficiaries as he or she shall have designated in writing to the Vice President and Controller of NUSCO; (which designation may be changed from time to time) or, in the absence of such a designation, to the estate of such Officer. 6. The amounts standing in Deferred Compensation Accounts shall be unfunded obligations of the Northeast Utilities system company employing each officer and shall be payable only under the terms stated herein. Officers shall have no right or claim against any specified assets of the Company and shall have only a contractual right against the Northeast Utilities system company employing him or her. 7. No Deferred Compensation Account shall be subject in any manner to anticipation, alienation, sale, transfer, assignment, pledge or encumbrance by an Officer or any person claiming under or through him or her, nor shall it be subject to the debts, contracts, liabilities, engagements or torts of an Officer or any one else prior to actual payment thereof. 8. This Plan may be amended or terminated by the Board of Trustees of Northeast Utilities at any time, provided, no such amendment or termination shall serve to diminish the rights of an Officer with respect to amounts credited to his or her Deferred Compensation Account or accelerate payment of such amounts. 9. Nothing contained in this Plan shall be construed as an assurance by the Company of reelection of any person as an Officer of the Company, as an obligation of any person to stand for reelection as an Officer of the Company, or as a prohibition against the resignation of any person as an Officer of the Company. EX-10.10 15 RECIPROCAL SUPPORT AGREEMENT EXHIBIT 10.41 EXECUTION COPY RECIPROCAL SUPPORT AGREEMENT AMONG NORTHEAST NUCLEAR ENERGY COMPANY, NORTH ATLANTIC ENERGY SERVICE CORPORATION, CONNECTICUT YANKEE ATOMIC POWER COMPANY, YANKEE ATOMIC ELECTRIC COMPANY AND NORTHEAST UTILITIES SERVICE COMPANY This Reciprocal Support Agreement is made as of January 1, 1996, by and among Northeast Nuclear Energy Company ("NNECO"), a Connecticut corporation, North Atlantic Energy Service Corporation ("NAESCO"), a New Hampshire corporation, Connecticut Yankee Atomic Power Company ("CYAPC"), a Connecticut corporation, Yankee Atomic Electric Company ("YAEC"), a Massachusetts corporation, acting by and through its Nuclear Services Division ("NSD"), and Northeast Utilities Service Company ("NUSCO"), a Connecticut corporation. WHEREAS, NNECO is a wholly owned service company subsidiary of Northeast Utilities ("NU") that operates and manages Millstone Units 1, 2, and 3 (individually a "Millstone Unit" and collectively the "Millstone Units"); and WHEREAS, NAESCO is a wholly owned service company subsidiary of NU that operates and manages Seabrook Station (Seabrook); and WHEREAS, CYAPC is an electric utility affiliate of NU and New England Electric System ("NEES") that owns and operates the Connecticut Yankee Atomic Power Plant ("Connecticut Yankee"); and WHEREAS, YAEC is an electric utility affiliate of NU and NEES that owns the Yankee Nuclear Power Station ("Yankee Nuclear Power Station") and, acting through NSD, provides technical services to Yankee Nuclear Power Station and other nuclear facilities (each of the Millstone Units, Seabrook, Connecticut Yankee and Yankee Nuclear Power Station being referred to herein as a "Nuclear Plant" and collectively as the "Nuclear Plants"); and WHEREAS, NUSCO is a wholly owned service company subsidiary of NU that provides legal, accounting and other administrative services to companies in the NU system; and WHEREAS, NNECO, NAESCO, CYAPC AND YAEC (each an "Operator" and collectively the "Operators") each has employees with specialized knowledge and expertise regarding nuclear plant procurement, engineering, licensing, construction, operations, maintenance, decommissioning, design, inspection, testing, planning and other relevant and related skills that they wish to make available to each other in a mutually cooperative fashion; and WHEREAS, each of the Operators has certain equipment, tools, and components that are used in connection with plant operation or maintenance (excluding specifically equipment, spare parts and consumables held in inventory) (collectively "Equipment"), on hand for use in its Nuclear Plant that may be required by another Operator from time to time in the course of operating and maintaining its Nuclear Plant, and the Operators are willing to make Equipment available to each other in a mutually cooperative fashion to meet their respective needs; and WHEREAS, increased economies and efficiencies and improved plant reliability will result from the sharing of expertise, technical resources, personnel and Equipment by and among the Operators; NOW THEREFORE, in consideration of the mutual promises contained herein and other good and valuable consideration, the receipt and adequacy of which is hereby acknowledged, the Operators and NUSCO (each a "party" and collectively the "Parties") agree as follows: ARTICLE I - SERVICES AND EQUIPMENT Section 1.1 - Any Operator may request another Operator to make available, on a temporary basis, specified personnel, or personnel having specified expertise, to assist the requesting Operator in any aspect of the requesting Operator's procurement, engineering, licensing, construction, operation, maintenance, decommissioning, design, inspection, testing or planning activities or other relevant and related skills (collectively "Operator Services"). Additionally, any Operator may request another Operator to furnish, for temporary use and not for permanent transfer or installation, a specified article, kind, or quality of Equipment to meet the requesting Operator's needs. It is not intended that this Agreement be used as a vehicle for the permanent acquisition or use of Equipment by any Nuclear Plant. Prior to making a request for Operator Services or Equipment, an Operator shall give appropriate consideration to whether it would be more advantageous to obtain such services or equipment from a third party vendor (instead of from another Operator) in light of relevant factors, such as cost, delivery schedule, design, quality, warranty protection and assurance of supply. Section 1.2 - Any Operator receiving a request for Operator Services or Equipment shall make reasonable efforts to accommodate such request, subject to the receiving Operator's own needs and requirements and the availability of appropriate personnel or Equipment, as the case may be. No Operator shall be required to comply with a request for Operator Services or Equipment, but each Operator shall cooperate in good faith with the other Operators to maximize the potential benefits of this Agreement to all Operators by making requested personnel available on a temporary basis or providing available Equipment on a temporary basis when it is reasonably possible to do so. All Operator Services and Equipment will be furnished on a mutually agreeable schedule pursuant to a master purchase order or service request issued by the Operator requesting the Operator Services or Equipment that refers to this Agreement and incorporates its terms by reference. A copy of such master purchase order or service request shall be sent to NUSCO at the time Operator Services are requested. Any Equipment that is furnished in a decontaminated condition shall be returned to the furnishing Operator in the same condition. Any Equipment that is furnished in a contaminated condition may be returned to the furnishing Operator in the same condition. Section 1.3 - Personnel of an Operator who are made available to another Operator to provide Operator Services shall at all times remain the employees of the Operator who makes them available and shall not become employees of the requesting Operator, but such personnel shall be subject to the supervision and control of the requesting Operator while Operator Services are being provided at the requesting Operator's Nuclear Plant. Except as explicitly provided in this Agreement, no Operator who receives Operator Services shall become responsible for any wages, salary, benefits, expenses or other costs associated with the personnel providing such Operator Services, all of which shall remain the responsibility of the Operator who is furnishing such Operator Services. ARTICLE II - PAYMENT FOR SERVICES Section 2.1 - Any Operator that furnishes Operator Services or Equipment to another Operator shall provide a report to NUSCO or through the Northeast Utilities financial system (currently the "Management Information and Budgeting System") (with a copy to the Operator who received the Operator Services or the Equipment) no later than the twentieth (20th) day after the end of each calendar month in which Operator Services or Equipment are provided containing a statement of cost reflecting the following factors or information for such calendar month: (A) in the case of Operator Services, (1) the name and cost control center of each employee who furnished Operator Services; (2) a description of the Operator Services furnished by each employee; (3) the direct labor costs for the period; and (4) a statement of any out-of-pocket costs reasonably incurred at each cost control center; and (B) in the case of Equipment, (1) a description of the Equipment furnished; (2) the operating cost of such equipment; and (3) the cost of any shipping, handling, insurance, storage or other operating costs associated with its delivery to the requesting Operator. Section 2.2 - Within ten (10) days after receipt of such report, the Operator who received such Operator Services or Equipment will be invoiced by the furnishing Operator or through the Northeast Utilities financial system for all direct costs reflected in such report (including, but not limited to, wages, salaries and out-of-pocket costs in the case of Operator Services, and operating costs, plus the cost of shipping, handling, insurance and other costs in the case of Equipment), which will be payable directly to the Operator who furnished the Operator Services or Equipment within 30 days after receipt of such invoice. NUSCO may take such actions as it deems appropriate to verify the information contained in any cost report or invoice furnished hereunder. Section 2.3 - All amounts invoiced for Operator Services or Equipment provided under this Agreement shall be billed "at cost", as defined in the Public Utility Holding Company Act of 1935 (the "Act") and the rules and regulations promulgated thereunder. The indirect and overhead costs associated with Operator Services (including without limitation costs of capital) shall be calculated and allocated on a reasonable and equitable basis in accordance with the requirements of the Act, and shall be invoiced periodically by the Operator furnishing such Operator Services or Equipment, by NUSCO or through the Northeast Utilities financial system to each Operator who received Operator Services hereunder, but in no event later than January 31 of each calendar year for the preceding calendar year. All such invoices shall be payable in the amounts and to the Operators specified therein within thirty (30) days after receipt. Section 2.4 - It is the intention of the Parties that NUSCO's role under this Agreement shall be limited to the billing, accounting and facilitating activities specifically described herein ("NUSCO Services"), and NUSCO shall not provide any other services, unless NUSCO is requested to provide Operator Services by another Operator. Furthermore, to the extent possible, all NUSCO Services shall be accomplished automatically through the NU financial system. All NUSCO Services provided hereunder and not otherwise provided under any other agreement shall be billed "at cost" to the Operators who receive Operator Services or Equipment hereunder during each calendar year. Direct charges will be made for NUSCO Services where a direct assignment of cost is possible. Charges for NUSCO Services not directly assignable (including without limitation costs of capital) shall be calculated and allocated on a periodic basis (but no less frequently than annually) by NUSCO on a reasonable and equitable basis in accordance with the requirements of the Act. NUSCO shall allocate costs for NUSCO Services not directly assignable among the Operators in proportion to the direct charges made for NUSCO Services received by each Operator during the relevant period. Each Operator that received Operator Services or Equipment during a calendar year shall be invoiced for the cost of NUSCO Services no later than January 31 of the following year, and all such invoices shall be payable within thirty (30) days after receipt. Section 2.5 - In order to permit each of the Operators to make informed decisions about possible requests for Operator Services and Equipment hereunder, on or before November 1 of each calendar year (or in the case of the calendar year in which this Agreement becomes effective, within thirty (30) days after the effective date of this Agreement), each Operator and NUSCO shall provide a written notice to each other Operator and to NUSCO of the categories of expense that will be included in indirect and overhead costs for the next calendar year (or for the remainder of the calendar year in the case of the calendar year in which this Agreement becomes effective) identified by cost control center or other appropriate means. Billings for indirect and overhead costs during the next calendar year (or for the remainder of the calendar year in the case of the calendar year in which this Agreement becomes effective) shall be made in a manner consistent with such notices. Billings for indirect and overhead costs may be based upon reasonable estimates, subject to true-up no later than March 1 of the following calendar year. Section 2.6 - Each of the Operators and NUSCO shall keep complete and accurate accounts of all receipts and expenditures hereunder in respect of Operator Services, NUSCO Services (collectively with Operator Services, the "Services") and Equipment in accordance with the regulations of the Securities and Exchange Commission ("SEC") and the Uniform System of Accounts prescribed for Public Utilities and Licensees subject to the provisions of the Federal Power Act, as amended from time to time. Section 2.7 - All sales, use, excise, gross receipts, franchise or other similar taxes which may be applicable to the Services or Equipment provided by any Party to another Party shall be borne by the recipient of such Services or Equipment. In no event shall any Party be responsible for any federal, state or local income tax of any other Party incurred with respect to Services or Equipment. Section 2.8 - Any joint owner, participant or shareholder in a Unit that has received Operator Services or Equipment may, at its expense, perform or cause to be performed an audit of the accounts and records of the furnishing Operator and/or NUSCO relating solely to the performance of such Operator's or NUSCO's obligations under this Agreement at such Operator's or NUSCO's offices, at reasonable times, by an independent public accountant or other representative; provided that any such audit shall not include the right to examine any accounts or records of such Operator or NUSCO which are not related to such Operator's or NUSCO's billings to such Nuclear Plant under this Agreement. ARTICLE III - STANDARD OF PERFORMANCE Section 3.1 - Each Operator and NUSCO shall, at all times during the term of this Agreement perform Services and furnish Equipment in accordance with the standard of "Prudent Utility Practice." As used herein, the term "Prudent Utility Practice" shall, at a particular time, mean any of the practices, methods or acts which, in the exercise of reasonable judgment in the light of the facts known to an Operator or NUSCO at the time the decision was made, could have been expected to accomplish the desired result at a reasonable cost and consistent with federal and state legal, licensing and regulatory requirements, environmental considerations, reliability, safety and expedition and taking into account the interests of all affected Parties. In determining whether any practice, method or act is in accordance with Prudent Utility Practice, due consideration shall be given to the fact that the design and other aspects of the operation of nuclear electric generating units involve the application of advancing technology and are subject to changing regulatory and environmental limitations. Prudent Utility Practice is not intended to be limited to the optimum practice, method or act to the exclusion of all others but rather to encompass a spectrum of possible practices, methods of acts, including those involving the use of new concepts or technology. Section 3.2 - ALL OPERATOR SERVICES AND EQUIPMENT FURNISHED HEREUNDER SHALL BE FURNISHED "AS IS, WHERE IS" WITHOUT REPRESENTATION OR WARRANTY OF ANY KIND WITH RESPECT TO QUALITY, MERCHANTABILITY, FITNESS FOR INTENDED PURPOSE, ABSENCE OF DEFECTS, OR OTHERWISE. Any Operator providing Equipment to another Operator shall assign to the receiving Operator any manufacturer's, vendor's or supplier's warranty that is assignable and assist the receiving Operator in the enforcement of such warranty. ARTICLE IV - EFFECTIVE DATE, TERM AND MODIFICATIONS Section 4.1 - The term of this Agreement shall commence as of the date hereof, and, unless earlier terminated in accordance with the provisions of this Article, shall continue in effect until the last to expire of the NRC operating licenses for the Nuclear Plants. Any Party to this Agreement may terminate its participation hereunder, with or without cause, upon written notice given not less than ninety (90) days prior to the effective date of such termination. Section 4.2 - This Agreement shall also be subject to termination and shall terminate, without any action by any Party, to the extent and from the time that performance may conflict with the Act or with any rule, regulation or order of the SEC adopted before or after the making hereof. Notwithstanding the foregoing, the Parties will use reasonable efforts to negotiate any amendments to this Agreement which are necessary for this Agreement to comply with the Act or any rule, regulation or order thereunder. Section 4.3 - Modifications to the terms of this Agreement may be made at any time only by written agreement among the Parties. ARTICLE V - LIMITATION OF LIABILITY AND SET-OFF Section 5.1 - Notwithstanding any provision of this Agreement to the contrary, for and in consideration of the fact that each of the Parties is undertaking its responsibility for the Services or Equipment provided hereunder without compensation or charge other than recovery of its costs for those Services or Equipment, no Party, nor any shareholder or joint owner on its behalf, shall be entitled to recover from any other Party, or the directors, trustees, officers, employees, agents or affiliates of such other Party (or the directors, trustees, officers, employees or agents of such affiliates) (collectively, the "Protected Parties") any damages resulting from the performance or non-performance of its responsibilities hereunder or for any damage to any Nuclear Plant, any curtailment of power, or any other damages of any kind, including direct, incidental, consequential, special, indirect or punitive damages, whether occurring during the course of the provision of Services or Equipment hereunder or otherwise or arising out of the performance or non-performance of this Agreement, unless such damages shall have resulted directly from the willful misconduct of such other Party, or, to the extent legally attributable to such Party, directly from the willful misconduct of a Protected Party. Section 5.2 - Notwithstanding any provision of this Agreement to the contrary, all provisions of this Agreement providing for limitation of, or protection against, liability shall apply to the full extent permitted by law, regardless of fault, and shall survive either termination pursuant to this Agreement or expiration. ARTICLE VI - ASSIGNMENT AND THIRD PARTY BENEFICIARIES Section 6.1 - This Agreement shall be binding upon and inure to the benefit of each of the Parties and their successors and permitted assigns. None of the Parties shall assign its rights or obligations hereunder without the prior written consent of the other Parties, and any attempted assignment in violation of this provision shall be null and void. Section 6.2 - The provisions of this Agreement are solely for the benefit of the Parties and are not intended to benefit or create rights in any third parties, except for the benefits accruing to Protected Parties under Section 5.1. ARTICLE VII - MISCELLANEOUS Section 7.1 - This Agreement shall be governed by and construed in accordance with the laws of the State of Connecticut regardless of any conflicts of laws provision to the contrary. Section 7.2 - EXCEPT AS SET FORTH IN SECTION 3.1, NO WARRANTIES OF ANY KIND, WHETHER STATUTORY, EXPRESS, WRITTEN, ORAL OR IMPLIED (INCLUDING, WITHOUT LIMITATION, WARRANTIES OF QUALITY, ABSENCE OF DEFECTS, MERCHANTABILITY OR FITNESS FOR A PARTICULAR PURPOSE) SHALL APPLY TO THE SERVICES OR EQUIPMENT FURNISHED HEREUNDER. The foregoing shall not be deemed to affect in any manner any warranties provided by manufacturers, vendors or suppliers. Section 7.3 - This Agreement constitutes the entire agreement of the Parties with respect to the furnishing of Services or Equipment hereunder. Section 7.4 - This Agreement shall be subject to the approval of any federal or state regulatory body whose approval is a legal prerequisite to its execution, delivery, and performance. Section 7.5 - Notices and other communications required or permitted to be given or made under this Agreement shall be in writing, and shall be deemed to have been duly made or given when delivered personally or when made or given by telex, telegraph or telecopier, or certified or first class mail, prepaid, at the address shown for each Party in Exhibit A hereto, or at such other address as a Party may from time to time designate by a written notice that complies with this Section 7.5. Section 7.6 - In the event that any clause or provision of this Agreement, or any part thereof, shall be declared invalid or unenforceable by any regulatory body or court having jurisdiction, such invalidity or unenforceability shall not affect the validity or enforceability of the remaining portions of this Agreement. Section 7.7 - Any number of counterparts of this Agreement may be executed and each shall have the same force and effect as the original. Section 7.8 - Nothing contained herein shall evidence any intent to effect a change in control of any of the Nuclear Plants operated by the Parties. Section 7.9 - Nothing contained herein shall be deemed to abrogate, modify or amend the provision of any existing agreement by or among any of the Parties hereto. IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be duly executed, by their respective officers thereunto duly authorized, all as of the day and year first above written. NORTHEAST NUCLEAR ENERGY COMPANY By /s/ Donald B. Miller, Jr. Senior Vice President - Nuclear Safety and Oversight NORTH ATLANTIC ENERGY SERVICE CORPORATION By /s/ Ted C. Feigenbaum Executive Vice President and Chief Nuclear Officer CONNECTICUT YANKEE ATOMIC POWER COMPANY By /s/ Fred R. Dacimo Vice President - Haddam Neck Station YANKEE ATOMIC ELECTRIC COMPANY By /s/ Andrew C. Kadak President and Chief Executive Officer NORTHEAST UTILITIES SERVICE COMPANY By /s/ Eric A. DeBarba Vice President - Nuclear Technical Services EXHIBIT A Northeast Nuclear Energy Company P.O. Box 270 Hartford, CT 06141-0270 Attention: With a copy to: North Atlantic Energy Service Corporation P.O. Box 300 Seabrook, NH 03874 Attention: With a copy to: Connecticut Yankee Atomic Power Company P.O. Box 270 Hartford, CT 06141-0270 Attention: With a copy to: Yankee Atomic Electric Company 580 Main Street Bolton, MA 01742 Attention: With a copy to: Northeast Utilities Service Company P.O. Box 270 Hartford, CT 06141-0270 Attention: With a copy to: EX-13.1 16 ANNUAL REPORT TO NU SHAREHOLDERS EXHIBIT 13.1 TABLE OF CONTENTS FINANCIAL AND STATISTICAL SECTION Pages 15-21 - ----------- MANAGEMENT'S DISCUSSION AND ANALYSIS Page 22 - ----------- COMPANY REPORT Page 23 - ----------- REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS Page 24 - ----------- CONSOLIDATED STATEMENTS OF INCOME Page 25 - ----------- CONSOLIDATED STATEMENTS OF CASH FLOWS Pages 26-27 - ----------- CONSOLIDATED BALANCE SHEETS Pages 28-29 - ----------- CONSOLIDATED STATEMENTS OF CAPITALIZATION Page 30 - ----------- CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY Page 31 - ----------- CONSOLIDATED STATEMENTS OF INCOME TAXES Pages 32-43 - ----------- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Page 44 - ----------- CONSOLIDATED STATEMENTS OF QUARTERLY FINANCIAL DATA (UNAUDITED) Page 44 - ----------- CONSOLIDATED GENERATION STATISTICS Page 45 - ----------- SELECTED CONSOLIDATED FINANCIAL DATA Page 46 - ----------- CONSOLIDATED SALES STATISTICS MANAGEMENT'S DISCUSSION AND ANALYSIS FINANCIAL CONDITION OVERVIEW Earnings per common share were $2.24 in 1995, a decrease of $0.06, from $2.30 in 1994. The 1995 earnings were lower as a result of higher operation expenses, lower wholesale revenues, and higher fuel and purchased-power costs. These decreases were partially offset by higher fuel revenues, higher revenues from the final step of The Connecticut Light and Power Company's (CL&P) three-year rate plan and the sixth step of the Public Service Company of New Hampshire (PSNH) rate agreement, higher deferral of cogeneration expenses in Connecticut, lower income tax expenses, and a reduction in maintenance costs. Retail kilowatt-hour sales fell by 0.1 percent in 1995, as a result of a flat economy in southern New England and mild weather in the first quarter of 1995. Retail kilowatt-hour sales were down 0.3 percent for CL&P, and 0.1 percent for Western Massachusetts Electric Company (WMECO), but sales rose 0.4 percent for PSNH. With the southern New England economy not forecasted to grow substantially during 1996, sales levels are expected to remain flat. NU's operating companies act as both buyers and sellers of electricity in the highly competitive wholesale electricity market in the Northeast. Increased competition has made the renegotiation of expiring wholesale contracts, as well as the signing of new contracts, financially challenging. As a result, wholesale power revenues fell to approximately $303 million in 1995, from approximately $331 million in 1994. NU's efforts to enhance its wholesale revenues resulted in several new contracts in 1995. During 1995, the Federal Energy Regulatory Commission issued a proposal for restructuring the electric-power industry, which calls for open access to transmission facilities, a standard formula for calculating rates, and full recovery of stranded investments. The impact on NU of this proposal, which is expected to be finalized in 1996, is not known at this time. During 1995, a Massachusetts Senate Committee and the Coalition of Northeastern Governors released reports addressing the restructuring of the electric-power industry and its resulting impact on customers and states. Both of these reports presented the future as one in which there would be some form of continued regulation for transmission and distribution with fully competitive generation. In 1995, the New Hampshire Legislature created a committee to review the industry's structure and called for the New Hampshire Public Utilities Commission (NHPUC) to initiate a retail wheeling pilot program. Under the current NHPUC proposal, the program, which is expected to begin in 1996, will initially impact 3 percent of PSNH's peak retail electric load, but only allows for a 50-percent recovery of PSNH's potentially strandable costs. PSNH and the NHPUC staff have entered into a joint recommendation that, if approved by the NHPUC, would govern PSNH's participation in the retail wheeling pilot program. Under this settlement, PSNH would provide competing electric suppliers access to 3 percent of its retail customers. PSNH would recover 100 percent of its potentially strandable costs via a delivery charge, but would provide a 10-percent incentive credit off its traditional rates to encourage customer participation in the two-year experiment. Also in 1995, Connecticut and Massachusetts regulatory commissions concluded that while increased competition is in the public interest, electric utilities should have the opportunity to recover "net, nonmitigatable stranded costs" during a transition period to full competition. While such a conclusion is encouraging, there is uncertainty with regard to the final regulatory and legislative definitions of terms such as "net, nonmitigatable" and "stranded costs." NU is taking a proactive role in the electric-power industry's movement toward competition. In its "Path To A Competitive Future" (the plan), NU outlined a comprehensive approach to enhancing customer satisfaction and market efficiency while moving toward full competition in the electricity marketplace. The plan calls for several significant changes in electricity pricing, the ability to introduce new products and services, the method of rate-setting, and the operation of the New England Power Pool. The plan also calls for the phase-in of supplier choices through the use of pilot programs. Management believes that a fully competitive market for electricity should begin once all issues relating to the transition from traditional utility regulation have been thoroughly addressed. [REGULATORY ASSETS CHART as follows] REGULATORY ASSETS (in millions) ACTUAL 1993 - $2,032 1994 - $2,045 1995 - $2,034 ------------- PROJECTED 1996 - $2,000 1998 - $1,500 2000 - $1,000 ------------- As our industry becomes more competitive, significant reductions of the deferred costs known as "regulatory assets" over the next five years is one of NU's key financial strategies. [END CHART] In addition to the formulation of this plan and ongoing meetings with legislators, regulators, and others in the industry, NU is moving ahead in other areas, including revenue enhancement initiatives and cost reductions, to better position itself for an increasingly competitive environment. A comprehensive companywide effort, which started in 1994, to reengineer NU's business and operating processes continued throughout 1995. NU expects that this effort will have significant positive effects on operating costs and customer service. Many of the organizational changes in the operating and service functions announced in 1995 and early 1996 are consistent with the initial recommendations of the reengineering teams. While NU's reengineering efforts will be reduced in 1996, implementation costs relating to the previous reengineering efforts are expected to increase. With retail electric revenues accounting for approximately 90 percent of its 1995 revenues, NU has continued to develop a number of initiatives to retain and serve its existing customers and to expand its retail customer base. The most visible result of these efforts is the expansion of the Retail Marketing organization. Retail Marketing's mission is to better understand the needs and concerns of NU's retail customer and to develop innovative approaches to address these issues. These initiatives include providing discounts to certain customers for signing economic development and competitive generation-based contracts, offering demand-side-management services, and providing additional products and services. WORKFORCE REDUCTIONS In January 1996, NU completed its nuclear workforce reduction plan. Approximately 220 positions were eliminated through a combination of early retirements, attrition, and layoffs. The total pretax cost of the workforce reduction, which was recognized in 1995, was approximately $9 million. RATE MATTERS NU follows accounting principles in accordance with Statement of Financial Accounting Standards (SFAS) 71, "Accounting for the Effects of Certain Types of Regulation" that allows the economic effects of rate regulation to be reflected. Under these principles, regulators may permit incurred costs for certain events or transactions, which would be treated as expenses by nonregulated enterprises, to be deferred as regulatory assets and recovered in revenues at a later date. The creation of these regulatory assets has kept down electric rates in past years, at the expense of having higher rates in the future. At December 31, 1995, NU's regulatory assets totaled approximately $2.0 billion. The largest regulatory asset, nearly $1.2 billion, is related to the future recovery of income taxes. The substantial costs of amortizing these regulatory assets would hinder NU from competing effectively in an openly competitive electric market if customers are not required to pay such costs. Given the increasingly competitive nature of the industry and increased activity in the regulatory environment, NU has made the recovery of regulatory assets one of its central financial strategies, while balancing the customer's pricing needs with shareholder's earnings requirements. Under its existing rate agreements, NU is allowed to recover a significant portion of its regulatory assets during the next five years. However, maintaining or increasing the present recovery level is dependent upon the outcome of negotiations between NU and its regulatory agencies when its current rate agreements expire in each of its jurisdictions. The chart on this page illustrates the levels of regulatory assets from 1993 to 1995, and the projected levels for 1996, 1998, and 2000 under existing rate agreements. Given that NU's current rate agreements expire during 1996 and 1997, NU will actively pursue early negotiations with its regulatory agencies to determine whether, or to what extent, rates should be adjusted going forward. NU's strategy during these negotiations will be to maintain stable rates, applying any available earnings that may result to reduce the balance of its regulatory assets. Management is unable to predict the ultimate outcome of these negotiations, which will be subject to regulatory approvals. This strategy will require NU to maintain its strong cash flow from operations, as measured by approximately a 4:1 cash coverage of the common dividend in 1995. At its January meeting, the NU Board of Trustees (the Board) decided to continue the current $0.44 per quarter common dividend. Although NU has a strong cash coverage of the current dividend, the Board decided against increasing the dividend at this time, given regulatory uncertainties, continued weakness in the economy, and the need for improvement of the Millstone nuclear operations. In March 1995, the Financial Accounting Standards Board (FASB) issued SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of." SFAS 121, which was effective January 1, 1996, requires assets, including regulatory assets, that are no longer probable of recovery through future revenues be charged to earnings. If future competition or regulatory actions cause any portion of its operations to no longer be subject to SFAS 71, NU would be required to determine the fair value of the related regulatory assets and liabilities and record any necessary write-downs. Additionally, if events create uncertainty about the recoverability of any of NU's remaining long-lived assets, a similar analysis would be required for those assets in accordance with SFAS 121. Under its current regulatory environment, NU believes that its use of SFAS 71 remains appropriate and that the adoption of SFAS 121 will not have a material impact on its financial position or results of operations. See the "Notes to Consolidated Financial Statements," Note 1G, for further details on regulatory accounting. CONNECTICUT CL&P's retail rates increased by approximately $48 million, or 2.06 percent, in July 1995, representing the final step of a three-year rate plan approved by the Department of Public Utility Control (DPUC). CL&P's 1993 rate decision has been appealed; however, management believes it is unlikely that the appeal will prevail. CL&P recovers from, or refunds to, customers certain fuel costs if its nuclear units do not operate at a predetermined capacity factor (currently 72 percent) through a Generation Utilization Adjustment Clause (GUAC). CL&P is currently recovering approximately $80 million of fuel costs for the 1994-1995 GUAC period (net of $19 million of asserted fuel overrecoveries for the period) over 18 months. CL&P has appealed the $19 million that was set aside from its allowed recovery and will seek to join this appeal to appeals currently pending from previous GUAC periods. NEW HAMPSHIRE In June 1995, PSNH's base rates increased by 5.5 percent under the sixth step of a seven-year 1989 rate agreement approved by the NHPUC. In November 1995, the NHPUC authorized a PSNH request to reduce its Fuel and Purchased Power Adjustment Clause (FPPAC) rate, which took effect on December 1, 1995, and will continue through May 31, 1996. The decision reduced PSNH's overall rates by approximately 2.6 percent. In 1995, PSNH completed installation of equipment to comply with the Clean Air Act Amendments of 1990. The capitalized cost of the installation was approximately $25 million, and will cause PSNH to spend approximately $4 million annually for additional operation and maintenance costs. In April 1995, the NHPUC began proceedings to determine whether these costs are recoverable from customers. The NHPUC is allowing PSNH to recover these costs through the FPPAC, subject to refund, pending a final decision. The costs associated with purchases by PSNH from certain nonutility generators (NUGs) over the level assumed in rates are deferred for recovery over ten-year periods through the FPPAC. PSNH is attempting to renegotiate these arrangements with the NUGs. At December 31, 1995, the unrecovered deferral was approximately $192 million, including buyout payments of approximately $34 million for two of PSNH's eight wood-fired NUGs. By December 31, 1995, PSNH had reached agreements with the owners of the remaining six wood-fired NUGs. If consummated, these agreements could result in net savings of approximately $430 million to PSNH's customers over a period of 20 years following guaranteed payments of approximately $250 million. Management will reevaluate whether to proceed with these agreements if the NHPUC fails to provide for full recovery of stranded costs. MASSACHUSETTS In February 1996, WMECO and the Massachusetts Attorney General proposed a settlement with the Department of Public Utilities (DPU), which, if approved, would continue the 2.4-percent rate reduction instituted in June 1994. The reduction would remain in effect through February 1998. Additionally, the settlement would terminate WMECO's pending reviews of its generating plant performance, any potential reviews associated with Millstone 2's 1994-1995 extended outage, and accelerate its recovery of generation assets by approximately $6 million and $10 million in 1996 and 1997, respectively. NUCLEAR PERFORMANCE On January 31, 1996, the Nuclear Regulatory Commission (NRC) placed Millstone 1, 2, and 3 (Millstone) on its "watch list." The NRC's action was in response to a number of performance concerns which have arisen since 1990 and a failure to resolve employee safety concerns. The NRC's action will result in close monitoring of programs and performance at Millstone to assure the development and implementation of effective corrective actions. Management plans to continue its extensive efforts already under way to address these concerns. Concurrent with the NRC's action, NU provided the NRC with the results of a comprehensive self-assessment review of the employee concern program at Millstone. Additionally, in January 1996, NU announced a reorganization of its nuclear operations, which included the creation of a new office of Nuclear Safety and Oversight. Although the start-up of Millstone 1, which is currently in outage, will be affected by its placement on the NRC's "watch list," operations at Millstone 2 and 3 have not been restricted. Management expects that the increased NRC attention will inevitably have effects and costs that are not known at this time. In November 1995, Millstone 1 began a planned refueling and maintenance outage. The outage has been extended to allow NU to complete reviews required by the NRC. In response to a request by the NRC, NU is conducting a detailed review of Millstone 1's Final Safety Analysis Report and an assessment of the plant's readiness to ensure that the future operation of the plant will be conducted in accordance with the terms and conditions of its operating license and the NRC's regulations. The outage schedule is currently under review, but the unit is not expected to return to service before the mid-to-late part of the second quarter of 1996. Total replacement-power costs attributable to the Millstone 1 outage extension for CL&P and WMECO are expected to be approximately $6.5 million per month. In addition, operation and maintenance (O&M) costs to be incurred as a result of the extension are estimated to be approximately $20 million. Replacement-power costs are deferred and amortized through rates for CL&P and are recovered currently through rates for WMECO. Nuclear outage O&M costs are deferred and amortized through rates for both companies. The recovery, or refund, of outage costs is subject to prudence reviews in both Connecticut and Massachusetts. The composite capacity factor of the five nuclear generating units that NU operates--including the Connecticut Yankee nuclear unit--was 69.9 percent in 1995, compared with 67.5 percent for 1994, and a 1995 national average of 77.6 percent. The 1995 capacity factor was impacted by an extended refueling and maintenance outage for Millstone 2. See the "Notes to Consolidated Financial Statements," Note 6B, for further information on outage deferrals and recoveries. ENVIRONMENTAL MATTERS NU devotes substantial resources to identify and comply with the multitude of environmental requirements it faces. NU has active auditing programs addressing a variety of regulatory requirements, including an environmental auditing program to detect and remedy noncompliance with environmental laws or regulations. NU is potentially liable for environmental cleanup costs at a number of sites both inside and outside its service territories. To date, the future estimated environmental remediation liability has not been material with respect to the earnings or financial position of NU. At December 31, 1995, NU had recorded an environmental reserve amounting to approximately $15 million, the minimum amount required under SFAS 5, "Accounting for Contingencies." These costs could be significantly higher if alternate remedies become necessary. In October 1995, the Connecticut Department of Environmental Protection (CDEP) issued a consent order to CL&P and the Long Island Lighting Company (LILCO) requiring those companies to address leaks from the Long Island cable, which is jointly owned by CL&P and LILCO. NU will incur additional costs to meet the requirements of the order and to meet any subsequent CDEP requirements resulting from the studies under the consent order, which cannot be estimated at this time. Management also cannot determine at this time whether long-term future operation of the cable will remain cost effective subsequent to any additional CDEP requirements. NUCLEAR DECOMMISSIONING NU's estimated cost to decommission its shares of Millstone 1, 2, and 3 and Seabrook 1 is approximately $1.2 billion in year-end 1995 dollars. These costs are being recognized over the lives of the respective units and a portion is being recovered through rates. The FASB is currently reviewing the accounting for closure and removal costs, including decommissioning and similar costs for long-lived assets. If current electric-power industry accounting practices for such decommissioning costs were changed, annual provisions for decommissioning would increase and the estimated costs for decommissioning would be recorded as a liability rather than as a component of accumulated depreciation. See the "Notes to Consolidated Financial Statements," Note 3, for further information on nuclear decommissioning, including NU's share of costs to decommission the regional nuclear generating units. LIQUIDITY AND CAPITAL RESOURCES Cash provided from operations decreased approximately $49 million in 1995, from 1994, primarily due to higher cash operating expenses and lower working capital, partially offset by higher revenues from rate recoveries. Cash used for financing activities decreased approximately $51 million in 1995, from 1994, primarily due to lower net reacquisitions and retirements of long-term debt and the issuance of additional common shares in 1995 for use in NU's Dividend Reinvestment Plan and the allocation of shares through the Employee Stock Ownership Plan, partially offset by a net decrease in short-term debt. Cash used for investments increased approximately $8 million in 1995, from 1994, primarily due to higher investments in the nuclear decommissioning trust in 1995, partially offset by lower construction expenditures. In October 1995, Moody's Investors Service lowered its ratings of PSNH and North Atlantic Energy Corporation (NAEC) securities, bringing the rating for PSNH's First Mortgage Bonds below investment grade. Standard & Poor's had previously downgraded PSNH to below investment grade. NAEC securities had not been previously rated at investment grade. These downgrades could adversely affect the future availability and cost of funds for these companies. Over the past three years, NU paid off approximately $1 billion of debt and reduced outstanding levels of preferred securities by approximately $75 million. Cash generated by improved earnings and higher levels of noncash expenses more than offset the cash needs of a modest construction program. NU projects further reductions of its long-term debt levels by $250 to $350 million during 1996 despite construction expenditures, which are budgeted to be approximately $35 million higher in 1996 than the $230 million program in 1995, since strong cash generation should continue. Short-term debt is expected to remain at approximately the same level as 1995. PSNH may be required to issue a significant amount of new debt in 1996, since it must fund the maturity of its $172.5 million first mortgage bond issue at the same time that it may need to finance more than $100 million for payments to its wood-fired NUGs. NU debt levels could drop by even more than the $250 to $350 million projected above if PSNH does not make any upfront payments to the NUGs. CL&P, PSNH, NAEC, and WMECO have entered into interest-rate-cap, interest-rate-swap, or fossil-fuel-swap contracts to reduce a portion of NU's interest-rate and fuel-price risks. CHANGE IN OPERATING REVENUES Increase/(Decrease) - ----------------------------------------------------------------- 1995 vs. 1994 1994 vs. 1993 - ----------------------------------------------------------------- (Millions of Dollars) Regulatory decisions $79 $53 Fuel, purchased power, and FPPAC cost recoveries 63 (3) Sales volume (6) 48 Wholesale revenues (19) (67) Other revenues (11) (17) ---- --- Total revenue change $106 $14 ==== === - ----------------------------------------------------------------- See the "Notes to Consolidated Financial Statements," Note 7, for further information on derivative financial instruments and the "Consolidated Statements of Capitalization," for information on construction and long-term debt funding requirements. RESULTS OF OPERATIONS The relative magnitude of how revenues received in 1995 were used by NU's continuing operations in 1995 is illustrated in the chart on the next page. OPERATING REVENUES The components of the change in operating revenues for the past two years are provided in the table above. Operating revenues increased approximately $106 million in 1995, from 1994. Regulatory revenues increased primarily because of retail-rate increases for PSNH and CL&P and higher recoveries for demand-side-management costs. Fuel, purchased power, and FPPAC cost recoveries increased, primarily due to higher energy costs and the recovery of GUAC costs for CL&P. Wholesale revenues decreased, primarily due to capacity sales contracts that expired in 1994. Operating revenues increased approximately $14 million in 1994, from 1993. Revenues related to regulatory decisions increased, primarily because of the effects of changes in retail rates for CL&P and PSNH, and the July 1993 retail-rate increase for WMECO, partially offset by the June 1994 retail-rate reduction for WMECO and lower recoveries for demand-side-management costs. Sales volume increased as a result of higher retail sales from an improved economy. Retail sales increased 2.9 percent in 1994, from 1993 sales levels. Wholesale revenues decreased, primarily due to the expiration, in late 1993 and 1994, of some significant capacity sales contracts. FUEL, PURCHASED AND NET INTERCHANGE POWER Fuel, purchased and net interchange power expense increased approximately $77 million in 1995, from 1994, primarily due to higher fossil generation, higher priced outside energy purchases from other utilities in 1995, and higher amortization, in 1995, of previously deferred FPPAC expenses. Fuel, purchased and net interchange power decreased approximately $86 million in 1994, from 1993, primarily due to the lower recognition of CL&P replacement-power fuel costs in 1994, partially offset by a higher level of outside energy purchases from other utilities in 1994. OTHER OPERATION AND MAINTENANCE EXPENSES Other operation and maintenance expenses, net increased approximately $29 million in 1995, from 1994. Operation expenses increased approximately $46 million, primarily due to higher demand-side-management costs, higher rate recovery of postretirement benefit costs, and higher capacity charges from the regional nuclear generating units, partially offset by higher nuclear reserves for excess/obsolete inventory in 1994. Maintenance expenses decreased approximately $17 million, primarily due to lower maintenance costs at the fossil units and fossil reserves for excess/obsolete inventory in 1994. Other operation and maintenance expenses decreased approximately $20 million in 1994, from 1993, primarily due to higher costs in 1993 associated with early- retirement programs, lower 1994 payroll and benefit costs, lower fossil-unit costs, and lower capacity charges from the regional nuclear generating units, partially offset by higher 1994 costs associated with the operation and maintenance activities of the nuclear units (approximately $23 million), higher reserves for excess/obsolete inventory at the nuclear and fossil units in 1994, and higher outside services primarily related to the companywide process reengineering efforts. DEPRECIATION EXPENSES Depreciation expenses increased approximately $19 million in 1995, from 1994, and approximately $14 million in 1994, from 1993, primarily as a result of higher plant balances and higher decommissioning levels. AMORTIZATION OF REGULATORY ASSETS, NET Amortization of regulatory assets, net decreased approximately $32 million in 1995, from 1994, primarily because of the higher CL&P cogeneration deferrals in 1995 (approximately $18 million), the completion, during 1994, of the amortization of a 1993 cogeneration buyout, and the completion of WMECO's amortization of Millstone 3 phase-in costs in June 1995. Amortization of regulatory assets, net decreased approximately $48 million in 1994, from 1993, primarily because of the deferral of CL&P cogeneration expenses beginning in July 1994 as allowed under CL&P's 1993 retail-rate decision, the higher amortization in 1994 of PSNH's regulatory liability as allowed under a 1993 global settlement, and lower expenses associated with the recovery of Hydro-Quebec support payments, partially offset by higher amortization of Millstone 3 and Seabrook 1 phase-in costs. FEDERAL AND STATE INCOME TAXES Federal and state income taxes decreased approximately $18 million in 1995, from 1994, primarily because of tax benefits from a favorable tax ruling and the expiration of the federal statute of limitations for 1991. Federal and state income taxes increased approximately $66 million in 1994, from 1993, primarily because of higher taxable income. TAXES OTHER THAN INCOME TAXES Although the change in 1995, from 1994, was not significant, taxes other than income taxes increased approximately $7 million in 1994, from 1993, primarily due to higher Connecticut sales tax expense. DEFERRED NUCLEAR PLANTS RETURN Deferred nuclear plants return decreased approximately $31 million in 1995, from 1994, and approximately $25 million in 1994, from 1993, primarily because additional Millstone 3 and Seabrook 1 investments were phased into rates. INTEREST CHARGES Although the change in 1995, from 1994, was not significant, interest on long-term debt decreased approximately $19 million in 1994, from 1993, primarily because of lower average interest rates as a result of refinancing activities and lower 1994 debt levels. [PIE CHART as follows] 1995 USE OF REVENUE - ------------------- 24.3% - Energy Costs 20.8% - Other Operation and Maintenance Expenses 13.6% - Taxes 13.0% - Nonfuel Operating Expenses and Other Income, Net 12.7% - Wages and Benefits 8.6% - Interest Charges 7.0% - Common and Preferred Dividends [END CHART] CUMULATIVE EFFECT OF ACCOUNTING CHANGE The cumulative effect of the accounting change of approximately $52 million in 1993 represents the one-time change in the method of accounting for Connecticut municipal property tax expense recognized in the first quarter of 1993. COMPANY REPORT The consolidated financial statements of Northeast Utilities and subsidiaries and other sections of this Annual Report were prepared by the company. These financial statements, which were audited by Arthur Andersen LLP, were prepared in accordance with generally accepted accounting principles using estimates and judgment, where required, and giving consideration to materiality. The company has endeavored to establish a control environment that encourages the maintenance of high standards of conduct in all of its business activities. The company maintains a system of internal controls over financial reporting, which is designed to provide reasonable assurance to the company's management and Board of Trustees regarding the preparation of reliable, published financial statements. The system is supported by an organization of trained management personnel, policies and procedures, and a comprehensive program of internal audits. Through established programs, the company regularly communicates to its management employees their internal control responsibilities and policies prohibiting conflicts of interest. The Audit Committee of the Board of Trustees is composed entirely of outside trustees. This committee meets periodically with management, the internal auditors, and the independent auditors to review the activities of each and to discuss audit matters, financial reporting, and the adequacy of internal controls. Because of inherent limitations in any system of internal controls, errors or irregularities may occur and not be detected. The company believes, however, that its system of internal accounting controls and control environment provide reasonable assurance that its assets are safeguarded from loss or unauthorized use and that its financial records, which are the basis for the preparation of all financial statements, are reliable. REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS TO THE BOARD OF TRUSTEES AND SHAREHOLDERS OF NORTHEAST UTILITIES: We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Northeast Utilities (a Massachusetts trust) and subsidiaries as of December 31, 1995 and 1994, and the related consolidated statements of income, common shareholders' equity, cash flows, and income taxes 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 Northeast Utilities and subsidiaries as of December 31, 1995 and 1994, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1995, in conformity with generally accepted accounting principles. As explained in Note 1A to the financial statements, effective January 1, 1993, Northeast Utilities and subsidiaries changed their method of accounting for property taxes. ARTHUR ANDERSEN LLP Hartford, Connecticut February 16, 1996 CONSOLIDATED STATEMENTS OF INCOME
For the Years Ended December 31, 1995 1994 1993 - --------------------------------------------------------------------------------------------------------------------------------- (Thousands of Dollars, except share information) OPERATING REVENUES .................................................. $ 3,748,991 $ 3,642,742 $ 3,629,093 ------------ ------------ ------------ OPERATING EXPENSES: Operation-- Fuel, purchased and net interchange power........................ 909,244 832,420 917,957 Other............................................................ 965,443 919,044 979,403 Maintenance........................................................ 288,927 306,429 265,926 Depreciation....................................................... 354,293 335,019 321,359 Amortization of regulatory assets, net............................. 128,413 160,909 208,506 Federal and state income taxes (See Consolidated Statements of Income Taxes)...................................... 261,228 287,951 222,832 Taxes other than income taxes...................................... 249,463 247,045 240,413 ------------ ------------ ------------ Total operating expenses....................................... 3,157,011 3,088,817 3,156,396 ------------ ------------ ------------ OPERATING INCOME..................................................... 591,980 553,925 472,697 ------------ ------------ ------------ OTHER INCOME: Deferred nuclear plants return--other funds........................ 14,196 27,085 38,373 Equity in earnings of regional nuclear generating and transmission companies....................................... 13,208 14,426 12,980 Other, net......................................................... 2,389 7,745 4,747 Income taxes....................................................... (742) 7,825 8,926 ------------ ------------ ------------ Other income, net................................................ 29,051 57,081 65,026 ------------ ------------ ------------ Income before interest charges................................... 621,031 611,006 537,723 ------------ ------------ ------------ INTEREST CHARGES: Interest on long-term debt......................................... 315,862 314,191 333,163 Other interest..................................................... 6,666 8,037 13,059 Deferred nuclear plants return--borrowed funds..................... (23,310) (41,138) (54,462) ------------ ------------ ------------ Interest charges, net............................................ 299,218 281,090 291,760 ------------ ------------ ------------ Income before cumulative effect of accounting change............. 321,813 329,916 245,963 CUMULATIVE EFFECT OF ACCOUNTING CHANGE (Note 1A)..................... -- -- 51,681 ------------ ------------ ------------ Income before preferred dividends of subsidiaries................ 321,813 329,916 297,644 PREFERRED DIVIDENDS OF SUBSIDIARIES.................................. 39,379 43,042 47,691 ------------ ------------ ------------ NET INCOME........................................................... $ 282,434 $ 286,874 $ 249,953 ============ ============ ============ EARNINGS PER COMMON SHARE: Before cumulative effect of accounting change...................... $2.24 $2.30 $1.60 Cumulative effect of accounting change (Note 1A)................... -- -- .42 ------------ ------------ ------------ TOTAL EARNINGS PER COMMON SHARE...................................... $2.24 $2.30 $2.02 ============ ============ ============ COMMON SHARES OUTSTANDING (AVERAGE).................................. 126,083,645 124,678,192 123,947,631 ============ ============ ============
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS. CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1995 1994 1993 - ----------------------------------------------------------------------------------------------------------------------------- (Thousands of Dollars) OPERATING ACTIVITIES: Income before preferred dividends of subsidiaries....................... $ 321,813 $ 329,916 $ 297,644 Adjustments to reconcile to net cash from operating activities: Depreciation.......................................................... 354,293 335,019 321,359 Deferred income taxes and investment tax credits, net ................ 164,208 146,560 63,506 Deferred nuclear plants return........................................ (37,506) (68,223) (92,835) Amortization of deferred nuclear plants return........................ 109,294 118,217 111,024 Recoverable energy costs, net of amortization......................... (51,474) (85,573) 93,302 Amortization of PSNH acquisition costs................................ 55,547 55,319 67,379 Deferred cogeneration costs--CL&P..................................... (55,341) (36,821) -- Other sources of cash................................................. 101,334 69,888 132,662 Other uses of cash.................................................... (43,972) (36,596) (24,186) Changes in working capital: Receivables and accrued utility revenues.............................. (72,081) 8,133 2,797 Fuel, materials, and supplies......................................... (10,518) 4,906 10,126 Accounts payable...................................................... 38,096 51,824 (678) Accrued taxes......................................................... 17,686 17,031 (97,789) Other working capital (excludes cash)................................. (8,045) 22,329 30,010 ---------- ---------- ---------- Net cash flows from operating activities.................................. 883,334 931,929 914,321 ---------- ---------- ---------- FINANCING ACTIVITIES: Issuance of common shares............................................... 47,218 14,551 22,252 Issuance of long-term debt.............................................. 225,100 625,000 924,650 Issuance of preferred stock............................................. -- -- 80,000 Issuance of Monthly Income Preferred Securities (Note 9)......................................... 100,000 -- -- Net (decrease) increase in short-term debt.............................. (91,000) 16,500 (179,240) Reacquisitions and retirements of long-term debt........................ (425,500) (982,920) (1,051,501) Reacquisitions and retirements of preferred stock....................... (140,675) (7,325) (116,496) Cash dividends on preferred stock....................................... (39,379) (43,042) (47,691) Cash dividends on common shares......................................... (221,701) (219,317) (218,179) ---------- ---------- ---------- Net cash flows used for financing activities.............................. (545,937) (596,553) (586,205) ---------- ---------- ---------- INVESTMENT ACTIVITIES: Investment in plant: Electric and other utility plant...................................... (231,408) (259,904) (275,741) Nuclear fuel.......................................................... (18,261) (28,308) (33,202) ---------- ---------- ---------- Net cash flows used for investments in plant............................ (249,669) (288,212) (308,943) Other investment activities, net........................................ (91,399) (44,593) (32,811) ---------- ---------- ---------- Net cash flows used for investments....................................... (341,068) (332,805) (341,754) ---------- ---------- ---------- NET (DECREASE) INCREASE IN CASH FOR THE PERIOD............................ (3,671) 2,571 (13,638) Cash--beginning of period................................................. 34,579 32,008 45,646 ---------- ---------- ---------- Cash--end of period....................................................... $ 30,908 $ 34,579 $ 32,008 ========== ========== ========== SUPPLEMENTAL CASH FLOW INFORMATION: Cash paid during the year for: Interest, net of amounts capitalized.................................... $ 321,148 $ 306,224 $ 325,552 ========== ========== ========== Income taxes............................................................ $ 108,928 $ 134,727 $ 142,669 ========== ========== ========== Increase in obligations: Niantic Bay Fuel Trust and other capital leases......................... $ 41,388 $ 65,932 $ 54,205 ========== ========== ==========
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS. CONSOLIDATED BALANCE SHEETS
At December 31, 1995 1994 - ----------------------------------------------------------------------------------------------------------------------------- (Thousands of Dollars) ASSETS UTILITY PLANT, AT COST: Electric................................................................ $ 9,490,142 $ 9,334,912 Other................................................................... 187,389 157,632 ----------- ----------- 9,677,531 9,492,544 Less: Accumulated provision for depreciation......................... 3,629,559 3,293,660 ----------- ----------- 6,047,972 6,198,884 Unamortized PSNH acquisition costs (Note 1I)............................ 588,910 678,974 Construction work in progress........................................... 165,111 179,724 Nuclear fuel, net....................................................... 198,844 224,839 ----------- ----------- Total net utility plant............................................... 7,000,837 7,282,421 ----------- ----------- OTHER PROPERTY AND INVESTMENTS: Nuclear decommissioning trusts, at market............................... 325,674 240,229 Investments in regional nuclear generating companies, at equity......... 81,996 82,464 Investments in transmission companies, at equity........................ 23,558 26,106 Investments in Charter Oak Energy, Inc. projects........................ 41,221 11,137 Other, at cost.......................................................... 33,448 29,759 ----------- ----------- 505,897 389,695 ----------- ----------- CURRENT ASSETS: Cash.................................................................... 30,908 34,579 Receivables, less accumulated provision for uncollectible accounts of $14,378,000 in 1995 and $16,826,000 in 1994............... 435,931 357,322 Accrued utility revenues................................................ 136,260 142,788 Fuel, materials, and supplies, at average cost.......................... 200,580 190,062 Recoverable energy costs, net--current portion.......................... 79,300 19,522 Prepayments and other................................................... 34,430 35,364 ----------- ----------- 917,409 779,637 ----------- ----------- DEFERRED CHARGES: Regulatory assets (Note 1G)............................................. 2,034,351 2,045,390 Unamortized debt expense................................................ 37,645 33,517 Other................................................................... 48,827 54,220 ----------- ----------- 2,120,823 2,133,127 ----------- ----------- TOTAL ASSETS.......................................................... $10,544,966 $10,584,880 =========== ===========
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS.
At December 31, 1995 1994 - ----------------------------------------------------------------------------------------------------------------------------- (Thousands of Dollars) CAPITALIZATION AND LIABILITIES CAPITALIZATION: (See Consolidated Statements of Capitalization) Common shareholders' equity (See Note (a)--Consolidated Statements of Common Shareholders' Equity): Common shares, $5 par value--authorized 225,000,000 shares; 135,611,166 shares issued and 127,050,647 shares outstanding in 1995 and 134,210,226 shares issued and 124,994,322 shares outstanding in 1994............ $ 678,056 $ 671,051 Capital surplus, paid in.............................................. 936,308 904,371 Deferred benefit plan--employee stock ownership plan (Note 5D)........ (198,152) (213,324) Retained earnings..................................................... 1,007,340 946,988 ----------- ----------- Total common shareholders' equity................................... 2,423,552 2,309,086 Preferred stock not subject to mandatory redemption................... 169,700 234,700 Preferred stock subject to mandatory redemption....................... 302,500 375,250 Long-term debt........................................................ 3,705,215 3,942,005 ----------- ----------- Total capitalization................................................ 6,600,967 6,861,041 ----------- ----------- MINORITY INTEREST IN CONSOLIDATED SUBSIDIARIES (NOTE 9)................... 99,935 -- ----------- ----------- OBLIGATIONS UNDER CAPITAL LEASES.......................................... 147,372 166,018 ----------- ----------- CURRENT LIABILITIES: Notes payable to banks.................................................. 99,000 180,000 Commercial paper........................................................ -- 10,000 Long-term debt and preferred stock--current portion..................... 219,657 174,948 Obligations under capital leases--current portion....................... 83,110 73,103 Accounts payable........................................................ 319,038 280,942 Accrued taxes........................................................... 75,218 57,532 Accrued interest........................................................ 53,699 70,639 Accrued pension benefits................................................ 90,630 90,194 Other................................................................... 105,821 98,296 ----------- ----------- 1,046,173 1,035,654 ----------- ----------- DEFERRED CREDITS: Accumulated deferred income taxes (Note 1H)............................. 2,135,852 1,968,230 Accumulated deferred investment tax credits............................. 178,060 188,005 Deferred contractual obligation......................................... 103,475 157,147 Other................................................................... 233,132 208,785 ----------- ----------- 2,650,519 2,522,167 ----------- ----------- COMMITMENTS AND CONTINGENCIES (Note 6) TOTAL CAPITALIZATION AND LIABILITIES.................................. $10,544,966 $10,584,880 =========== ===========
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS. CONSOLIDATED STATEMENTS OF CAPITALIZATION
At December 31, 1995 1994 - ----------------------------------------------------------------------------------------------------------------------------- (Thousands of Dollars) COMMON SHAREHOLDERS' EQUITY (See Consolidated Balance Sheets) ............ $ 2,423,552 $ 2,309,086 ----------- ----------- CUMULATIVE PREFERRED STOCK OF SUBSIDIARIES: $25 par value--authorized 36,600,000 shares at December 31, 1995 and 1994; 7,300,000 shares outstanding in 1995 and 12,927,000 shares in 1994; $50 par value--authorized 9,000,000 shares at December 31, 1995 and 1994; 5,424,000 shares outstanding in 1995 and 1994; $100 par value--authorized 1,000,000 shares at December 31, 1995 and 1994; 200,000 shares outstanding in 1995 and 1994 Current Redemption Current Shares Dividend Rates Prices (a) Outstanding -------------- ---------- ----------- NOT SUBJECT TO MANDATORY REDEMPTION: $25 par value--Adjustable Rate $25.00 1,340,000... 33,500 98,500 $50 par value--$1.90 to $3.28 $50.50 to $54.00 2,324,000... 116,200 116,200 $100 par value--$7.72 $103.51 200,000... 20,000 20,000 ----------- ----------- Total Preferred Stock Not Subject to Mandatory Redemption................ 169,700 234,700 ----------- ----------- SUBJECT TO MANDATORY REDEMPTION: (b) $25 par value--$1.90 to $2.65 $25.00 to $25.89 5,960,000... 149,000 224,675 $50 par value--$2.65 to $3.615 $51.00 to $52.41 3,100,000... 155,000 155,000 ----------- ----------- Total Preferred Stock Subject to Mandatory Redemption.................... 304,000 379,675 Less: Preferred Stock to be redeemed within one year.................... 1,500 4,425 ----------- ----------- Preferred Stock Subject to Mandatory Redemption, net..................... 302,500 375,250 ----------- ----------- LONG-TERM DEBT: (c) First Mortgage Bonds-- Maturity Interest Rates -------- -------------- 1995 9.25%............................................ -- 34,300 1996 8.875%........................................... 172,500 172,500 1997 5.75% to 7.625%.................................. 211,945 214,850 1998 6.50% to 9.17%................................... 199,800 199,900 1999 5.50% to 7.25%................................... 280,000 280,000 2000 5.75% to 6.875%.................................. 260,000 260,000 2002 7.75% to 9.05%................................... 420,000 440,000 2004 6.125%........................................... 140,000 140,000 2019-2023 7.375% to 7.50%.................................. 120,000 120,000 2024-2025 7.375% to 8.50%.................................. 430,000 430,000 ----------- ----------- Total First Mortgage Bonds.......................................... 2,234,245 2,291,550 ----------- ----------- Other Long-Term Debt-- (d) Pollution Control Notes and Other Notes-- 1996 Adjustable Rate.................................. -- 141,000 2000 Adjustable Rate (e) and 15.23%................... 225,000 205,000 2005-2006 8.38% to 8.58%................................... 224,000 236,000 2013-2016 Adjustable Rate.................................. 23,400 23,400 2018-2020 7.17% and Adjustable Rate........................ 49,874 50,191 2021-2022 7.50% to 7.65% and Adjustable Rate............... 552,485 552,485 2028 Adjustable Rate.................................. 369,300 369,300 ----------- ----------- Total Pollution Control Notes and Other Notes....................... 1,444,059 1,577,376 Fees and interest due for spent nuclear fuel disposal costs (Note 1N). 185,158 174,934 Other................................................................. 68,312 78,090 ----------- ----------- Total Other Long-Term Debt.......................................... 1,697,529 1,830,400 ----------- ----------- Unamortized premium and discount, net................................... (8,402) (9,422) ----------- ----------- Total Long-Term Debt.................................................. 3,923,372 4,112,528 Less amounts due within one year...................................... 218,157 170,523 ----------- ----------- Long-Term Debt, net................................................... 3,705,215 3,942,005 ----------- ----------- TOTAL CAPITALIZATION................................................ $ 6,600,967 $ 6,861,041 =========== ===========
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS. NOTES TO CONSOLIDATED STATEMENTS OF CAPITALIZATION (a) Each of these series is subject to certain refunding limitations for the first five years after issuance. Redemption prices reduce in future years. (b) Changes in Preferred Stock Subject to Mandatory Redemption: (Thousands of Dollars) Balance at January 1, 1993................ $353,500 Issues.................................. 80,000 Reacquisitions and Retirements.......... (51,500) -------- Balance at December 31, 1993.............. 382,000 Reacquisitions and Retirements.......... (2,325) -------- Balance at December 31, 1994.............. 379,675 Reacquisitions and Retirements.......... (75,675) -------- Balance at December 31, 1995.............. $304,000 ======== The minimum sinking-fund requirements of the series subject to mandatory redemption aggregate approximately $1.5 million in 1996, $26.5 million in 1997, $30.3 million in 1998, and $46.3 million in 1999 and 2000. In case of default on sinking-fund payments, no payments may be made on any junior stock by way of dividends or otherwise (other than in shares of junior stock) so long as the default continues. If a subsidiary is in arrears in the payment of dividends on any outstanding shares of preferred stock, the subsidiary is prohibited from redeeming or purchasing less than all of the outstanding preferred stock. (c) Long-term debt maturities and cash sinking-fund requirements, excluding fees and interest due for spent nuclear fuel disposal costs, on debt outstanding at December 31, 1995 for the years 1996 through 2000 are approximately $218.2 million, $261.3 million, $239.5 million, $371.9 million, and $578.2 million, respectively. In addition, there are annual 1 percent sinking- and improvement-fund requirements of approximately $15.6 million for 1996 and 1997, $13.5 million for 1998, $13.2 million for 1999, and $10.4 million for 2000. Such sinking- and improvement-fund requirements may be satisfied by the deposit of cash or bonds or by certification of property additions. Essentially all utility plant of The Connecticut Light and Power Company (CL&P), Public Service Company of New Hampshire (PSNH), Western Massachusetts Electric Company (WMECO), and North Atlantic Energy Corporation (NAEC), wholly owned subsidiaries of NU, is subject to the liens of each company's respective first mortgage bond indenture. NAEC's first mortgage bonds are also secured by payments made to NAEC by PSNH under the terms of the Seabrook Power Contracts. In addition, CL&P and WMECO have secured $369.3 million of pollution-control notes with second mortgage liens on Millstone 1, junior to the liens of their respective first mortgage bond indentures. PSNH's Revolving Credit Facility has a second lien, junior to the lien of its first mortgage bond indenture, on all PSNH property located in New Hampshire, which will expire in May 1996. At December 31, 1995, there were no borrowings under the Revolving Credit Facility. Concurrent with the issuance of PSNH's Series A and B First Mortgage Bonds, PSNH entered into financing arrangements with the Business Finance Authority (BFA) of the state of New Hampshire. Pursuant to these arrangements, the BFA issued seven series of Pollution Control Revenue Bonds (PCRBs) and loaned the proceeds to PSNH. At December 31, 1995, $516.5 million of the PCRBs were outstanding. PSNH's obligation to repay each series of PCRBs is secured by a series of First Mortgage Bonds that was issued under its indenture. Each such series of First Mortgage Bonds contains terms and provisions with respect to maturity, principal payment, interest rate, and redemption that correspond to those of the applicable series of PCRBs. For financial reporting purposes, these bonds would not be considered outstanding unless PSNH fails to meet its obligations under the PCRBs. (d) The average effective interest rates on the variable-rate pollution-control notes ranged from 3.6 percent to 6.1 percent for 1995 and 2.5 percent to 4.3 percent for 1994. The average effective interest rates for the PSNH Term Loan for 1995 and 1994 were approximately 7.1 percent and 5.2 percent, respectively. (e) Interest-rate-swap agreements with financial institutions effectively fix the interest rate of NAEC's $225 million variable-rate bank note at 7.05 percent. For further information on NAEC's interest-rate swaps, see Note 7, "Derivative Financial Instruments." CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY
DEFERRED BENEFIT CAPITAL PLAN-- COMMON SURPLUS, ESOP RETAINED SHARES (a) PAID IN (NOTE 5D) EARNINGS (b) TOTAL - ------------------------------------------------------------------------------------------------------------------------------ (Thousands of Dollars) BALANCE AT JANUARY 1, 1993.............. $669,315 $897,317 $(240,399) $847,744 $2,173,977 Net income for 1993................... 249,953 249,953 Cash dividends on common shares-- $1.76 per share..................... (218,179) (218,179) Issuance of 344,106 common shares, $5 par value........................ 1,720 6,538 8,258 Allocation of benefits--ESOP.......... 1,800 12,194 13,994 Capital stock expenses, net........... (3,915) (3,915) -------- -------- --------- ---------- ---------- BALANCE AT DECEMBER 31, 1993............ 671,035 901,740 (228,205) 879,518 2,224,088 Net income for 1994................... 286,874 286,874 Cash dividends on common shares-- $1.76 per share..................... (219,317) (219,317) Loss on retirement of preferred stock (87) (87) Issuance of 3,201 common shares, $5 par value........................ 16 61 77 Allocation of benefits--ESOP.......... (406) 14,881 14,475 Capital stock expenses, net........... 2,976 2,976 -------- -------- --------- ---------- ---------- BALANCE AT DECEMBER 31, 1994............ 671,051 904,371 (213,324) 946,988 2,309,086 Net income for 1995................... 282,434 282,434 Cash dividends on common shares-- $1.76 per share..................... (221,701) (221,701) Loss on retirement of preferred stock (381) (381) Issuance of 1,400,940 common shares, $5 par value........................ 7,005 24,971 31,976 Allocation of benefits--ESOP.......... 70 15,172 15,242 Capital stock expenses, net........... 6,896 6,896 -------- -------- --------- ---------- ---------- BALANCE AT DECEMBER 31, 1995............ $678,056 $936,308 $(198,152) $1,007,340 $2,423,552 ======== ======== ========= ========== ========== - ------------------------------------------------------------------------------------------------------------------------------ (a) As part of its acquisition of PSNH, NU issued 8,430,910 warrants to former PSNH equity security holders. Each warrant, which expires on June 5, 1997, entitles the holder to purchase one share of NU common stock at an exercise price of $24 per share. As of December 31, 1995, 462,224 shares had been purchased through the exercise of warrants. (b) Certain consolidated subsidiaries have dividend restrictions imposed by their long-term debt agreements. These restrictions also limit the amount of retained earnings available for NU common dividends. At December 31, 1995, these restrictions totaled approximately $559.6 million.
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS. CONSOLIDATED STATEMENTS OF INCOME TAXES
For the Years Ended December 31, 1995 1994 1993 - ------------------------------------------------------------------------------------------------------------------------------- (Thousands of Dollars) The components of the federal and state income tax provisions charged to operations are: Current income taxes: Federal............................................................ $ 53,862 $ 88,483 $ 99,591 State.............................................................. 43,900 45,083 50,809 -------- -------- -------- Total current.................................................... 97,762 133,566 150,400 -------- -------- -------- Deferred income taxes, net: Federal............................................................ 167,091 149,391 87,105 State.............................................................. 7,224 6,988 (10,058) -------- -------- -------- Total deferred................................................... 174,315 156,379 77,047 -------- -------- -------- Investment tax credits, net........................................... (10,107) (9,819) (13,541) -------- -------- -------- Total income tax expense................................................. $261,970 $280,126 $213,906 ======== ======== ======== The components of total income tax expense are classified as follows: Income taxes charged to operating expenses............................. $261,228 $287,951 $222,832 Other income taxes..................................................... 742 (7,825) (8,926) -------- -------- -------- Total income tax expense................................................. $261,970 $280,126 $213,906 ======== ======== ======== Deferred income taxes are comprised of the tax effects of temporary differences as follows: Depreciation, leased nuclear fuel, settlement credits, and disposal costs................................................. $ 82,318 $ 72,078 $ 79,288 Energy adjustment clauses............................................ 26,851 49,017 (39,660) Nuclear plant deferrals.............................................. 2,666 (10,542) (1,773) Contractual settlements.............................................. (9,496) 109 (308) Bond redemptions..................................................... 9,224 8,325 8,508 Amortization of New Hampshire regulatory settlement.................. 11,501 11,501 7,667 Deferred tax asset associated with net operating losses.............. 57,543 23,611 25,438 Other................................................................ (6,292) 2,280 (2,113) -------- -------- -------- Deferred income taxes, net............................................... $174,315 $156,379 $ 77,047 ======== ======== ======== A reconciliation between income tax expense and the expected tax expense at 35 percent of pretax income: Expected federal income tax............................................ $204,324 $213,515 $179,043 Tax effect of differences: Depreciation......................................................... 25,639 20,003 21,319 Deferred nuclear plants return....................................... (4,969) (9,480) (13,486) Amortization of deferred nuclear plants return....................... 21,883 23,103 21,988 Amortization of PSNH acquisition costs............................... 31,522 31,508 31,432 Seabrook intercompany loss........................................... (13,048) (19,637) (19,176) Investment tax credit amortization................................... (10,107) (9,819) (13,541) State income taxes, net of federal benefit........................... 33,231 33,847 26,488 Property tax......................................................... (159) 5,824 (13,514) Adjustment for prior years' taxes.................................... (20,312) (4,588) (4,134) Other, net........................................................... (6,034) (4,150) (2,513) -------- -------- -------- Total income tax expense................................................. $261,970 $280,126 $213,906 ======== ======== ========
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES A. PRESENTATION Northeast Utilities (NU or the company) is the parent company of the Northeast Utilities system (the system). The system furnishes retail electric service in Connecticut, New Hampshire, and western Massachusetts through four wholly owned subsidiaries, CL&P, PSNH, WMECO, and Holyoke Water Power Company (HWP). A fifth wholly owned subsidiary, NAEC, sells all of its capacity to PSNH. In addition to its retail service, the system furnishes firm and other wholesale electric services to various municipalities and other utilities. The system serves about 30 percent of New England's electric needs and is one of the 20 largest electric utility systems in the country as measured by revenues. The consolidated financial statements of the company include the accounts of all wholly owned subsidiaries. Significant intercompany transactions have been eliminated in consolidation. 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 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. Certain reclassifications of prior years' data have been made to conform with the current year's presentation. PROPERTY TAXES: Certain subsidiaries of NU, including CL&P and WMECO, changed their method of accounting for municipal property tax expense for their respective Connecticut properties during 1993. This one-time change increased 1993 net income and earnings per common share by approximately $51.7 million and $0.42, respectively. B. FUTURE ACCOUNTING STANDARD The Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) 121, ACCOUNTING FOR THE IMPAIRMENT OF LONG-LIVED ASSETS AND FOR LONG-LIVED ASSETS TO BE DISPOSED OF, in March 1995. SFAS 121 became effective January 1, 1996 and establishes accounting standards for evaluating and recording asset impairment. SFAS 121 requires the evaluation of long-lived assets for impairment when certain events occur or conditions exist that indicate the carrying amounts of assets may not be recoverable. Refer to Note 1G, "Regulatory Accounting," for further information on the regulatory impacts of the company's adoption of SFAS 121. C. INVESTMENTS AND JOINTLY OWNED ELECTRIC UTILITY PLANT REGIONAL NUCLEAR GENERATING COMPANIES: CL&P, PSNH, and WMECO own common stock of four regional nuclear generating companies (Yankee companies). The system holds a 49.0 percent ownership interest in Connecticut Yankee Atomic Power Company (CY), a 38.5 percent ownership interest in Yankee Atomic Electric Company (YAEC), a 20.0 percent ownership interest in Maine Yankee Atomic Power Company (MY), and a 16.0 percent ownership interest in Vermont Yankee Nuclear Power Corporation (VY). The system's investments in the Yankee companies are accounted for on the equity basis due to NU's ability to exercise significant influence over their operating and financial policies. The electricity produced by the facilities that are operating is committed substantially on the basis of ownership interests and is billed pursuant to contractual agreements. Under ownership agreements with the Yankee companies, CL&P, PSNH, and WMECO may be asked to provide direct or indirect financial support for one or more of the companies. For more information on these agreements, see Note 6E, "Commitments and Contingencies--Long-term Contractual Arrangements." YAEC's nuclear power plant was shut down permanently on February 26, 1992. For more information on the Yankee companies, see Note 3, "Nuclear Decommissioning." MILLSTONE 3: CL&P, PSNH, and WMECO have a 68.02 percent joint-ownership interest in Millstone 3, a 1,154-megawatt (MW) nuclear generating unit. As of December 31, 1995 and 1994, plant-in-service included approximately $2.4 billion and the accumulated provision for depreciation included approximately $572.3 million and $525.9 million, respectively, for the system's share of Millstone 3. The system's share of Millstone 3 expenses is included in the corresponding operating expenses on the accompanying Consolidated Statements of Income. SEABROOK 1: CL&P and NAEC have a 40.04 percent joint-ownership interest in Seabrook 1, a 1,148-MW nuclear generating unit. NAEC sells all of its share of the power generated by Seabrook 1 to PSNH under two long-term contracts. As of December 31, 1995 and 1994, plant-in-service included approximately $889.0 million and $887.4 million, respectively, and the accumulated provision for depreciation included approximately $107.0 million and $83.2 million, respectively, for the system's share of Seabrook 1. The system's share of Seabrook 1 expenses is included in the corresponding operating expenses on the accompanying Consolidated Statements of Income. HYDRO-QUEBEC: NU has a 22.66 percent equity-ownership interest, totaling approximately $23.6 million, in two companies that transmit electricity imported from the Hydro-Quebec system in Canada. The two companies own and operate transmission and terminal facilities, which have the capability of importing up to 2,000 MW from the Hydro-Quebec system. See Note 6E, "Commitments and Contingencies--Long-term Contractual Arrangements," for additional information. CHARTER OAK ENERGY, INC. (COE): COE owns and/or participates through special purpose subsidiaries in various nonutility generation projects as permitted under the Public Utility Holding Company Act of 1935. These investments may be accounted for on either a cost or equity basis based upon COE's level of participation. D. DEPRECIATION The provision for depreciation is calculated using the straight-line method based on estimated remaining lives of depreciable utility plant-in-service, adjusted for salvage value and removal costs, as approved by the appropriate regulatory agency. Except for major facilities, depreciation factors are applied to the average plant-in-service during the period. Major facilities are depreciated from the time they are placed in service. When plant is retired from service, the original cost of plant, including costs of removal, less salvage, is charged to the accumulated provision for depreciation. The depreciation rates for the several classes of electric plant-in-service are equivalent to a composite rate of 3.8 percent in 1995, 3.7 percent in 1994, and 3.6 percent in 1993. See Note 3, "Nuclear Decommissioning," for information on nuclear plant decommissioning. E. PUBLIC UTILITY REGULATION NU is registered with the Securities and Exchange Commission (SEC) as a holding company under the Public Utility Holding Company Act of 1935 (1935 Act), and it and its subsidiaries are subject to the provisions of the 1935 Act. Arrangements among the system companies, outside agencies, and other utilities covering interconnections, interchange of electric power, and sales of utility property are subject to regulation by the Federal Energy Regulatory Commission (FERC) and/or the SEC. The operating subsidiaries are subject to further regulation for rates, accounting, and other matters by the FERC and/or applicable state regulatory commissions. F. REVENUES Other than revenues under fixed-rate agreements negotiated with certain wholesale, industrial, and commercial customers, utility revenues are based on authorized rates applied to each customer's use of electricity. In general, rates can be changed only through a formal proceeding before the appropriate regulatory commission. At the end of each accounting period, CL&P, PSNH, and WMECO accrue an estimate for the amount of energy delivered but unbilled. G. REGULATORY ACCOUNTING The accounting policies of the operating companies and the accompanying consolidated financial statements conform to generally accepted accounting principles applicable to rate-regulated enterprises and reflect the effects of the ratemaking process in accordance with SFAS 71, ACCOUNTING FOR THE EFFECTS OF CERTAIN TYPES OF REGULATION. Assuming a cost-of-service based regulatory structure, regulators may permit incurred costs, normally treated as expenses, to be deferred and recovered in future revenues. Through their actions, regulators may also reduce or eliminate the value of an asset, or create a liability. If any portion of the company's operations were no longer subject to the provisions of SFAS 71, as a result of a change in the cost-of-service based regulatory structure or the effects of competition, the company would be required to write off related regulatory assets and liabilities. The company would also be required to determine any impairment to other assets and write down these assets to fair value. Based on current regulation and recent regulatory decisions and initiatives relating to competition in the system's markets, the company believes that its use of regulatory accounting remains appropriate. SFAS 121 requires that any assets, including regulatory assets, which are no longer probable of recovery through future revenues, be revalued based on estimated future cash flows. If the revaluation is less than the book value of the asset, an impairment loss would be charged to earnings. As noted above, based on the current regulatory environment in the company's service areas, it is not expected that SFAS 121 will have a material impact on the company's financial position or results of operations upon adoption. This conclusion may change in the future as competitive factors influence wholesale and retail pricing in the electric utility industry or if the cost-of-service based regulatory structure were to change. For further information on the company's regulatory environment, refer to Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A). The components of regulatory assets are as follows: - -------------------------------------------------------------------- At December 31, 1995 1994 - -------------------------------------------------------------------- (Thousands of Dollars) Income taxes, net (Note 1H). $1,176,356 $1,124,119 Recoverable energy costs, net (Note 1J). . . . . . . . . . . 260,678 268,982 Deferred costs--nuclear plants (Note 1K) . . . . . . . . . 168,600 233,145 Unrecovered contractual obligation (Note 3). . . . . . . . 103,475 157,147 Deferred demand-side management costs (Note 1L) . . . . . 117,070 116,133 Cogeneration costs-- CL&P (Note 1M) . . . . . . . . . . 92,162 36,821 Other. . . . . . . . . . . . . . . . . 116,010 109,043 ---------- ---------- $2,034,351 $2,045,390 ========== ========== - -------------------------------------------------------------------- H. INCOME TAXES The tax effect of temporary differences (differences between the periods in which transactions affect income in the financial statements and the periods in which they affect the determination of income subject to tax) is accounted for in accordance with the ratemaking treatment of the applicable regulatory commissions. The adoption of SFAS 109, ACCOUNTING FOR INCOME TAXES, in 1993 increased the company's net deferred tax obligation. As it is probable that the increase in deferred tax liabilities will be recovered from customers through rates, NU established a regulatory asset. See Consolidated Statements of Income Taxes for the components of income tax expense. The tax effect of temporary differences, including timing differences accrued under previously approved accounting standards, which give rise to the accumulated deferred tax obligation is as follows: - ---------------------------------------------------------------------- At December 31, 1995 1994 - ---------------------------------------------------------------------- (Thousands of Dollars) Accelerated depreciation and other plant-related differences. . . $1,703,680 $1,470,372 Net operating loss carryforwards . . . (191,873) (247,440) Regulatory assets--income tax gross up . . . . . . . . . . . . . . 477,959 473,399 Other. . . . . . . . . . . . . . . . . 146,086 271,899 ---------- ---------- $2,135,852 $1,968,230 ========== ========== - ---------------------------------------------------------------------- At December 31, 1995, PSNH had a net operating loss (NOL) carryforward of approximately $572 million to be used against PSNH's federal taxable income and to expire between the years 2000 and 2006. PSNH also had Investment Tax Credit (ITC) carryforwards of $52 million, which expire between the years 1996 and 2004. For a portion of the carryforward amounts indicated above, the reorganization of PSNH under Chapter 11 of the United States Bankruptcy Code limits the annual amount of NOL and ITC carryforwards that may be used. Approximately $95 million of the NOL and $21 million of the ITC carryforwards are subject to this limitation. I. UNAMORTIZED PSNH ACQUISITION COSTS The unamortized PSNH acquisition costs represent the aggregate value placed by the 1989 rate agreement with the state of New Hampshire (Rate Agreement) on PSNH's assets in excess of the net book value of PSNH's non-Seabrook assets plus the $700-million value assigned to Seabrook by the Rate Agreement, as part of the bankruptcy resolution on June 5, 1992 (Acquisition Date). The Rate Agreement provides for the recovery, through rates, with a return, of the amortization of the unamortized PSNH acquisition costs. The Rate Agreement provides that $425 million of the unamortized PSNH acquisition costs be amortized over the first seven years after PSNH's May 16, 1991 reorganization from bankruptcy (Reorganization Date), with the remaining amount to be amortized over the 20-year period after the Reorganization Date. As of December 31, 1995, approximately $411.8 million of acquisition costs have been collected through rates. J. RECOVERABLE ENERGY COSTS Under the Energy Policy Act of 1992 (Energy Act), CL&P, PSNH, WMECO, and NAEC are assessed for their proportionate shares of the costs of decontaminating and decommissioning uranium enrichment plants owned by the United States Department of Energy (D&D assessment). The Energy Act requires that regulators treat D&D assessments as a reasonable and necessary current cost of fuel, to be fully recovered in rates, like any other fuel cost. CL&P, PSNH, WMECO, and NAEC are currently recovering these costs through rates. As of December 31, 1995, the company's total D&D deferrals were approximately $62.4 million. CL&P: Retail electric rates include a fuel adjustment clause (FAC) under which fossil-fuel prices above or below base-rate levels are charged or credited to customers. Monthly FAC rates are also subject to quarterly retroactive regulatory review and appropriate adjustments. CL&P also utilizes a generation utilization adjustment clause (GUAC), which defers the effect on fuel costs caused by variations from a specified composite nuclear generation capacity factor embedded in base rates. CL&P is currently recovering $80 million of its GUAC balance over 18 months. CL&P set aside $19 million of its 1994-1995 GUAC year request pending the resolution of CL&P's appeals associated with the two prior GUAC periods. At December 31, 1995, CL&P's net recoverable energy costs, excluding current recoverable energy costs, were approximately $27.3 million. For additional information, see Note 6B, "Commitments and Contingencies--Nuclear Performance." PSNH: The Rate Agreement includes a comprehensive fuel and purchased-power adjustment clause (FPPAC) permitting PSNH to pass through to retail customers, for a ten-year period, the retail portion of differences between the fuel and purchased-power costs assumed in the Rate Agreement and PSNH's actual costs, which include the costs related to the Seabrook Power Contracts and the Clean Air Act Amendment. The cost components of the FPPAC are subject to a prudence review by the New Hampshire Public Utilities Commission (NHPUC). The costs associated with purchases from certain nonutility generators (NUGs) over the level assumed in the Rate Agreement are deferred and recovered through the FPPAC. PSNH has been renegotiating the rate orders mandating the purchase of high-cost NUG power. The NHPUC has approved an amendment to the Rate Agreement allowing settlement agreements to be implemented with two wood-fired NUGs. In 1994, the two NUGs that were settled gave up their rights to sell their output to PSNH in exchange for lump-sum cash payments totaling approximately $40 million. The deferred buyout payments are included as part of PSNH's recoverable energy costs. During the Rate Agreement's fixed-rate period, all of the savings from the buyout will be used to reduce PSNH's recoverable energy costs. At the end of the fixed-rate period, 50 percent of the savings will be used to reduce the recoverable energy costs, with the remainder reducing current rates. PSNH has also reached tentative agreements with the six remaining wood-fired NUGs. These agreements are subject to NHPUC approval. At December 31, 1995, PSNH's net recoverable energy costs were approximately $220 million, including purchased-power deferrals of $185.6 million and the NUGs deferred buyout payments of $34.2 million. K. DEFERRED COSTS--NUCLEAR PLANTS As prescribed by the Rate Agreement, NAEC is phasing into rates the recoverable portion of its investment in Seabrook 1 and is deferring certain costs for future collection. This plan is in compliance with SFAS 92, REGULATED ENTERPRISES--ACCOUNTING FOR PHASE-IN PLANS. As of December 31, 1995, the portion of the investment on which NAEC is entitled to earn a cash return was 85 percent. he investment will be fully phased into NAEC's rate base as of May 1, 1996. From the Acquisition Date through December 31, 1995, NAEC recorded $162.4 million of deferred return on the excluded portion of its investment in Seabrook 1. The deferred return on the excluded portion of NAEC's investment in Seabrook 1 will be recovered with carrying charges beginning six months after the end of PSNH's fixed-rate period (which continues through May 1997) and will be fully recovered by May 2001. L. DEMAND-SIDE MANAGEMENT (DSM) CL&P's DSM costs are recovered in base rates through a Conservation Adjustment Mechanism (CAM). As of December 31, 1995, these costs will be fully recovered by 2000. During October 1995, CL&P filed its 1996 DSM program and forecasted CAM for 1996 with the Connecticut Department of Public Utility Control (DPUC). The filing proposes expenditures of $37.1 million in 1996, with recovery over 2.4 years and a zero CAM rate. M. CL&P COGENERATION COSTS In accordance with its three-year rate plan that began in July 1993, CL&P was required to defer approximately $72 million and $36 million of cogeneration expense in years two and three, respectively, of the rate plan. CL&P is allowed to defer these costs with carrying charges and will begin amortization of these costs over a five-year period beginning July 1, 1996. On June 30, 1995, CL&P terminated its existing agreement to purchase power from the O'Brien EPA cogeneration facility and entered into an agreement to purchase an equivalent amount of power from Citizens Lehman Power LP, at a cost below the O'Brien EPA rates. CL&P has applied the resulting savings to the amortization of the cogeneration deferral. N. SPENT NUCLEAR FUEL DISPOSAL COSTS Under the Nuclear Waste Policy Act of 1982, CL&P, PSNH, WMECO, and NAEC must pay the United States Department of Energy (DOE) for the disposal of spent nuclear fuel and high-level radioactive waste. Fees for nuclear fuel burned on or after April 7, 1983 are billed currently to customers and paid to the DOE on a quarterly basis. For nuclear fuel used to generate electricity prior to April 7, 1983 (prior-period fuel), payment may be made anytime prior to the first delivery of spent fuel to the DOE, which may be as early as 1998. Until such payment is made, the outstanding balance will continue to accrue interest at the three-month Treasury Bill Yield Rate. At December 31, 1995, fees due to the DOE for the disposal of prior-period fuel were approximately $185.2 million, including interest costs of $103.1 million. As of December 31, 1995, all fees have been collected through rates. O. DERIVATIVE FINANCIAL INSTRUMENTS The company utilizes interest-rate caps, interest-rate swaps, and fuel swaps to manage well-defined interest-rate and fuel-price risks. Premiums paid for purchased interest-rate-cap agreements are amortized to interest expense over the terms of the caps. Unamortized premiums are included in deferred charges. Amounts receivable under cap agreements and amounts receivable or payable under interest-rate-swap agreements are accrued and offset against interest expense. Amounts receivable or payable under fuel-swap agreements are recognized in income when realized. Any material unrealized gains or losses on interest-rate swaps, fuel swaps or interest-rate caps will be deferred until realized. For further information on derivatives, see Note 7, "Derivative Financial Instruments." 2. LEASES CL&P and WMECO finance up to $475 million of nuclear fuel for Millstone 1 and 2 and their respective shares of the nuclear fuel for Millstone 3 under the Niantic Bay Fuel Trust (NBFT) capital lease agreement. CL&P and WMECO make quarterly lease payments for the cost of nuclear fuel consumed in the reactors, based on a units-of-production method at rates which reflect estimated kilowatt-hours of energy provided, plus financing costs associated with the fuel in the reactors. Upon permanent discharge from the reactors, ownership of the nuclear fuel transfers to CL&P and WMECO. The system companies have also entered into lease agreements, some of which are capital leases, for the use of data processing and office equipment, vehicles, nuclear control room simulators, and office space. The provisions of these lease agreements generally provide for renewal options. Capital lease rental payments charged to operating expense were $75,894,000 in 1995, $81,952,000 in 1994, and $100,911,000 in 1993. Interest included in capital lease rental payments was $15,025,000 in 1995, $14,881,000 in 1994, and $16,525,000 in 1993. Operating lease rental payments charged to operating expense were $20,859,000 in 1995, $20,118,000 in 1994, and $22,630,000 in 1993. Substantially all of the capital lease rental payments were made pursuant to the nuclear fuel lease agreement. Future minimum lease payments under the nuclear fuel capital lease cannot be reasonably estimated on an annual basis due to variations in the usage of nuclear fuel. Future minimum rental payments, excluding annual nuclear fuel lease payments and executory costs, such as property taxes, state use taxes, insurance, and maintenance, under long-term noncancelable leases, as of December 31, 1995, are: - ----------------------------------------------------------------- Capital Operating Year Leases Leases - ----------------------------------------------------------------- (Thousands of Dollars) 1996. . . . . . . . . . . . . . . . . . $ 9,000 $21,500 1997. . . . . . . . . . . . . . . . . . 8,400 18,900 1998. . . . . . . . . . . . . . . . . . 8,000 11,200 1999. . . . . . . . . . . . . . . . . . 7,500 8,500 2000. . . . . . . . . . . . . . . . . . 6,900 7,100 After 2000. . . . . . . . . . . . . . . 42,500 13,600 -------- ------- Future minimum lease payments . . . . . 82,300 $80,800 ======= Less amount representing interest . . . . . . . . . . . . . . 40,500 -------- Present value of future minimum lease payments for other than nuclear fuel. . . . . 41,800 Present value of future nuclear fuel lease payments. . . . . . . . . 188,700 -------- Total . . . . . . . . . . . . $230,500 ======== - ----------------------------------------------------------------- 3. NUCLEAR DECOMMISSIONING The NU system's nuclear power plants have service lives that are expected to end during the years 2010 through 2026. Upon retirement, these units must be decommissioned. The company's 1992 decommissioning study concluded that complete and immediate dismantlement at retirement continues to be the most viable and economic method of decommissioning the three Millstone units. A 1994 Seabrook decommissioning study also confirmed that complete and immediate dismantlement at retirement is the most viable and economic method of decommissioning Seabrook 1. Decommissioning studies are reviewed and updated periodically to reflect changes in decommissioning requirements, costs, technology, and inflation. The estimated cost of decommissioning Millstone 1 and 2, in year-end 1995 dollars, is $370.7 million and $328.1 million, respectively. The system's ownership share of the estimated cost of decommissioning Millstone 3 and Seabrook 1 in year-end 1995 dollars, is $298.2 million and $169.7 million, respectively. These estimated costs assumed levelized collections for the Millstone units and escalated collections for Seabrook 1, and after-tax earnings on the Millstone and Seabrook decommissioning funds of 6.5 percent and 6.1 percent, respectively. The Millstone units and Seabrook 1 decommissioning costs will be increased annually by their respective escalation rates. Nuclear decommissioning costs are accrued over the expected service life of the units and are included in depreciation expense on the Consolidated Statements of Income. Nuclear decommissioning costs amounted to $38.9 million in 1995, $33.5 million in 1994, and $29.4 million in 1993. Nuclear decommissioning, as a cost of removal, is included in the accumulated provision for depreciation on the Consolidated Balance Sheets. At December 31, 1995, the balance in the accumulated reserve for decommissioning amounted to $357.7 million. See "Nuclear Decommissioning" in the MD&A for a discussion of changes being considered by the FASB relating to accounting for closure and removal of long-lived assets (including nuclear decommissioning) CL&P and WMECO have established external decommissioning trusts through a trustee for their portions of the costs of decommissioning Millstone 1, 2, and 3. PSNH makes payments to an independent decommissioning trust for its portion of the costs of decommissioning Millstone 3. CL&P's and NAEC's portions of the cost of decommissioning Seabrook 1 are paid to an independent decommissioning financing fund managed by the state of New Hampshire. As of December 31, 1995, CL&P, PSNH, and WMECO collected, through rates, $203.5 million, $1.8 million, and $47.4 million, respectively, toward the future decommissioning costs of their share of the Millstone units, of which $220.6 million has been transferred to external decommissioning trusts. As of December 31, 1995, CL&P and NAEC (including payments made prior to the Acquisition Date by PSNH) paid approximately $1.9 million and $13.1 million, respectively, into Seabrook 1's decommissioning financing fund. Earnings on the decommissioning trusts and financing fund increase the decommissioning trust balance and the accumulated reserve for decommissioning. Unrealized gains and losses associated with the decommissioning trusts also impact the balance of the trusts and the accumulated reserve for decommissioning. Changes in requirements or technology, the timing of funding or dismantling, or adoption of a decommissioning method other than immediate dismantlement would change decommissioning cost estimates and the amounts required to be recovered. CL&P, PSNH, and WMECO attempt to recover sufficient amounts through their allowed rates to cover their expected decommissioning costs. Only the portion of currently estimated total decommissioning costs that has been accepted by regulatory agencies is reflected in rates of the system companies. Based on present estimates and assuming its nuclear units operate to the end of their respective license periods, the system expects that the decommissioning trusts and financing fund will be substantially funded when the units are retired from service. CL&P, PSNH, and WMECO, along with other New England utilities, have equity investments in the four Yankee companies. Each Yankee company owns a single nuclear generating unit with service lives that are expected to end during the years 2007 through 2012. The system's ownership share of estimated costs, in year-end 1995 dollars, of decommissioning the units owned and operated by CY, MY, and VY are $188.9 million, $70.7 million, and $55.6 million, respectively. Under the terms of the contracts with the Yankee companies, the shareholders-sponsors are responsible for their proportionate share of the operating costs of each unit, including decommissioning. The nuclear decommissioning costs of the Yankee companies are included as part of the cost of power purchased by CL&P, PSNH, and WMECO. YAEC is in the process of dismantling its nuclear facility. Accelerated decommissioning of that unit has been delayed because of litigation over the Nuclear Regulatory Commission's (NRC) approval of YAEC's decommissioning plan. Effective November 1995, YAEC began billing its sponsors, including the NU system companies, amounts based on a revised estimate approved by the FERC that assumes decommissioning of the plant by the year 2000. This revised decommissioning estimate was based on access to the Barnwell, South Carolina, low-level radioactive waste facility, changes in assumptions about earnings in decommissioning trust investments, and changes in other decommissioning cost assumptions. At December 31, 1995, the estimated remaining costs, including decommissioning, amounted to $268.8 million of which the NU system's share was approximately $103.5 million. Management expects that CL&P, PSNH, and WMECO will continue to be allowed to recover such FERC-approved costs from their customers. Accordingly, NU has recognized these costs as regulatory assets, with corresponding obligations, on its Consolidated Balance Sheets. 4. SHORT-TERM DEBT The system companies have various revolving credit lines, totaling $468 million. NU, CL&P, WMECO, HWP, Northeast Nuclear Energy Company (NNECO), and The Rocky River Realty Company (RRR) have established a revolving-credit facility with a group of 15 banks. Under this facility, the participating companies may borrow up to an aggregate of $343 million. Individual borrowing limits as of January 1, 1996 were $150 million for NU, $325 million for CL&P, $60 million for WMECO, $5 million for HWP, $50 million for NNECO, and $22 million for RRR. The system companies may borrow funds on a short-term revolving basis, using either fixed-rate loans or standby loans. Fixed rates are set using competitive bidding. Standby-loan rates are based upon several alternative variable rates. The system companies are obligated to pay a facility fee of 0.15 percent per annum of each bank's total commitment under the three-year portion of the facility, representing 75 percent of the total facility, plus 0.10 percent per annum of each bank's total commitment under the 364-day portion of the facility, representing 25 percent of the total facility. At December 31, 1995 and 1994, there were $42.5 million and $30 million in borrowings, respectively, under the facility. PSNH has credit lines totaling $125 million available through a revolving-credit agreement with a group of 19 banks. PSNH may borrow funds on a short-term revolving basis using either fixed-rate or standby loans. Fixed rates are set using competitive bidding. Standby loan rates are based upon several alternative variable rates. PSNH is obligated to pay a facility fee of 0.25 percent per annum on the total commitment. At December 31, 1995 and 1994, there were no borrowings under the agreement. These credit lines expire in May 1996. PSNH is in the process of negotiating an increase and extension to the revolving credit agreement. The weighted average interest rate on notes payable to banks outstanding on December 31, 1995 was 6.0 percent. The weighted average interest rates on notes payable to banks and commercial paper outstanding on December 31, 1994 were 6.2 and 6.4 percent, respectively. Maturities of the short-term debt obligations were for periods of three months or less. The amount of short-term borrowings that may be incurred by the system's utility companies is subject to periodic approval by the SEC under the 1935 Act. In addition, the charters of CL&P and WMECO contain provisions restricting the amount of short-term borrowings. Under the SEC and/or charter restrictions, CL&P, PSNH, WMECO, and NAEC were authorized, as of January 1, 1995, to incur short-term borrowings up to a maximum of $325 million, $175 million, $60 million, and $50 million, respectively. PSNH is see king approval from the NHPUC to increase its short-term debt limit to $225 million. 5. EMPLOYEE BENEFITS A. PENSION BENEFITS The system's subsidiaries participate in a uniform noncontributory-defined benefit retirement plan covering all regular system employees. Benefits are based on years of service and employees' highest eligible compensation during five consecutive years of employment. Total pension cost, part of which was charged to utility plant, approximated $0.4 million in 1995, $7.7 million in 1994, and $29.2 million in 1993. Pension costs for 1995, 1994, and 1993 included approximately $6.8 million, $9.2 million, and $27.7 million, respectively, related to workforce-reduction programs. Currently, the subsidiaries fund annually an amount at least equal to that which will satisfy the requirements of the Employee Retirement Income Security Act and the Internal Revenue Code. Pension costs are determined using market-related values of pension assets. Pension assets are invested primarily in domestic and international equity securities and bonds. The components of net pension cost are: - ------------------------------------------------------------------------------ For the Years Ended December 31, 1995 1994 1993 - ------------------------------------------------------------------------------ (Thousands of Dollars) Service cost . . . . . . . . . . . . $ 35,771 $ 39,317 $ 59,068 Interest cost. . . . . . . . . . . . 89,351 84,284 81,456 Return on plan assets. . . . . . . . (310,997) 2,268 (176,798) Net amortization . . . . . . . . . . 186,310 (118,188) 65,447 --------- --------- --------- Net pension cost . . . . . . . . . . $ 435 $ 7,681 $ 29,173 ========= ========= ========= - ------------------------------------------------------------------------------ For calculating pension cost, the following assumptions were used: - ------------------------------------------------------------------------------ For the Years Ended December 31, 1995 1994 1993 - ------------------------------------------------------------------------------ Discount rate. . . . . . . . . . . . 8.25% 7.75% 8.00% Expected long-term rate of return. . . . . . . . . . . . 8.50 8.50 8.50 Compensation/progression rate . . . . . . . . . . . . . . 5.00 4.75 5.00 - ------------------------------------------------------------------------------ The following table represents the plan's funded status reconciled to the Consolidated Balance Sheets: - ------------------------------------------------------------------------------ At December 31, 1995 1994 - ------------------------------------------------------------------------------ (Thousands of Dollars) Accumulated benefit obligation, including vested benefits at December 31, 1995 and 1994 of $913,269,000 and $815,646,000, respectively . . . $ 998,614 $ 893,653 ========== ========== Projected benefit obligation . . . . $1,278,434 $1,112,993 Market value of plan assets. . . . . 1,503,597 1,266,239 ---------- ---------- Market value in excess of projected benefit obligation . . . 225,163 153,246 Unrecognized transition amount . . . (13,648) (15,191) Unrecognized prior service costs . . 9,710 10,373 Unrecognized net gain. . . . . . . . (311,855) (238,622) --------- ----------- Accrued pension liability. . . . . . $ (90,630) $ (90,194) ========= ========== - ------------------------------------------------------------------------------ The following actuarial assumptions were used in calculating the plan's year-end funded status: - ------------------------------------------------------------------------------ At December 31, 1995 1994 - ------------------------------------------------------------------------------ Discount rate. . . . . . . . . . . . 7.50% 8.25% Compensation/progression rate. . . . 4.75 5.00 - ------------------------------------------------------------------------------ B. POSTRETIREMENT BENEFITS OTHER THAN PENSIONS The system's subsidiaries provide certain health care benefits, primarily medical and dental, and life insurance benefits through a benefit plan to retired employees (referred to as SFAS 106 benefits). These benefits are available for employees retiring from the system who have met specified service requirements. For current employees and certain retirees, the total SFAS 106 benefit is limited to two times the 1993 per-retiree health care costs. The SFAS 106 obligation has been calculated based on this assumption. Total SFAS 106 benefits, part of which were deferred or charged to utility plant, approximated $44.1 million in 1995, $47.6 million in 1994, and $50.1 million in 1993. All of the subsidiaries of NU are funding SFAS 106 postretirement costs through external trusts. The subsidiaries are funding, on an annual basis, amounts that have been rate-recovered and which also are tax-deductible under the Internal Revenue Code. The trust assets are invested primarily in equity securities and bonds. The components of health care and life insurance costs are: - ------------------------------------------------------------------------------ For the Years Ended December 31, 1995 1994 1993 - ------------------------------------------------------------------------------ (Thousands of Dollars) Service cost . . . . . . . . . . . . . $ 7,137 $ 7,418 $ 9,175 Interest cost. . . . . . . . . . . . . 24,693 25,319 25,330 Return on plan assets. . . . . . . . . (7,812) 236 (220) Amortization of unrecognized transition obligation. . . . . . . . 15,134 15,134 15,961 Other amortization, net. . . . . . . . 4,924 (553) (106) ------- ------- ------- Net health care and life insurance costs. . . . . . . . . . . $44,076 $47,554 $50,140 ======= ======= ======= - ------------------------------------------------------------------------------ For calculating SFAS 106 benefits cost, the following assumptions were used: - ------------------------------------------------------------------------------ For the Years Ended December 31, 1995 1994 1993 - ------------------------------------------------------------------------------ Discount rate. . . . . . . . . . . . . 8.00% 7.75% 7.75% Long-term rate of return-- Health assets, net of tax. . . . . . 5.00 5.00 5.00 Life assets. . . . . . . . . . . . . 8.50 8.50 8.50 - ------------------------------------------------------------------------------ The following table represents the plan's funded status reconciled to the Consolidated Balance Sheets: - ------------------------------------------------------------------------------ At December 31, 1995 1994 - ------------------------------------------------------------------------------ (Thousands of Dollars) Accumulated postretirement benefit obligation of: Retirees . . . . . . . . . . . . . $ 253,993 $ 251,448 Fully eligible active employees. . 354 416 Active employees not eligible to retire. . . . . . . . . . . . 84,056 69,556 --------- --------- Total accumulated postretirement benefit obligation . . . . . . . . . 338,403 321,420 Market value of plan assets. . . . . . 56,791 26,406 --------- --------- Accumulated postretirement benefit obligation in excess of plan assets. (281,612) (295,014) Unrecognized transition amount . . . . . . . . . . . . . . . 257,283 272,417 Unrecognized net loss (gain) . . . . . 96 (4,772) --------- --------- Accrued postretirement benefit liability. . . . . . . . . . $ (24,233) $ (27,369) ========= ========= - ------------------------------------------------------------------------------ The following actuarial assumptions were used in calculating the plan's year-end funded status: - ------------------------------------------------------------------------------ At December 31, 1995 1994 - ------------------------------------------------------------------------------ Discount rate. . . . . . . . . . . . . 7.50% 8.00% Health care cost trend rate (a) . . . 8.40 10.20 - ------------------------------------------------------------------------------ (a) The annual growth in per capita cost of covered health care benefits was assumed to decrease to 5.4 percent by 2001. The effect of increasing the assumed health-care-cost trend rate by one percentage point in each year would increase the accumulated postretirement benefit obligation as of December 31, 1995 by $18.3 million and the aggregate of the service and interest-cost components of net periodic postretirement benefit cost for the year then ended by $1.6 million. The trust holding the plan assets is subject to federal income taxes at a 35 percent tax rate. CL&P, PSNH, and WMECO are currently recovering SFAS 106 costs, including amounts previously deferred. C. 401(K) SAVINGS PLAN NU maintains a 401(k) Savings Plan for substantially all employees. This savings plan provides for employee contributions up to specified limits. The company matches employee contributions up to a maximum of 3 percent of eligible compensation. The matching contributions for the company were $12.1 million for 1995 and 1994, and $12.2 million for 1993. D. EMPLOYEE STOCK OWNERSHIP PLAN (ESOP) NU maintains an ESOP for purposes of allocating shares to employees participating in the system's 401(k) plan. Under this arrangement, NU issued unsecured notes during 1991 and 1992 totaling $250 million, the proceeds of which were lent to the ESOP trust for purchase of approximately 10.8 million newly issued NU common shares. NU makes principal and interest payments on the ESOP notes at the same rate that ESOP shares are allocated to employees. In 1995 and 1994, the ESOP trust issued approximately 655,000 and 664,000 of NU common shares, respectively, totaling approximately $15.2 million and $15.5 million, respectively. These costs were charged to the 401(k) plan. As of December 31, 1995 and 1994, the total allocated ESOP shares were 2,239,666 and 1,585,281, respectively, and total unallocated ESOP shares were 8,560,519 and 9,215,904, respectively. The fair market value of unallocated ESOP shares as of December 31, 1995 and 1994 was approximately $207.6 million and $199.3 million, respectively. During 1995, the ESOP trust used approximately $22.7 million in dividends paid on NU common shares and $13.2 million in contributions from NU to meet principal and interest payments on ESOP notes. 6. COMMITMENTS AND CONTINGENCIES A. CONSTRUCTION PROGRAM The construction program is subject to periodic review and revision. The system companies currently forecast construction expenditures of approximately $1.2 billion for the years 1996-2000, including $265.1 million for 1996. In addition, the system companies estimate that nuclear fuel requirements, including nuclear fuel financed through the NBFT, will be $344.9 million for the years 1996-2000, including $45.7 million for 1996. See Note 2, "Leases," for additional information about the financing of nuclear fuel. B. NUCLEAR PERFORMANCE Outages that occurred over the period October 1990 through February 1992 at the Millstone nuclear units have been the subject of five ongoing prudence reviews in Connecticut. CL&P has received final decisions on each of the reviews. Three of these prudence reviews are either on appeal or still pending at the DPUC. The exposure under these three dockets is approximately $92 million. On April 10, 1995, the DPUC initiated a proceeding to investigate the prudence of a Millstone 2 extended outage, which ended June 1994. Approximately $13 million of costs are at issue. In October 1994, Millstone 2 began a planned refueling and maintenance outage that was originally scheduled for 63 days. The outage encountered several unexpected difficulties which extended the duration of the outage until August 4, 1995. Total replacement-power costs attributable to the extension of the outage for CL&P and WMECO were approximately $85 million. Operation and maintenance (O&M) costs incurred during the outage were approximately $70 million, an increase of $24 million as a result of the outage extension. O&M costs associated with the refueling outage are deferred and amortized through rates for CL&P and WMECO. The recovery of replacement-power and O&M costs is subject to refund pending prudence reviews in both Connecticut and Massachusetts. Management does not believe the outcome of the prudence reviews discussed above will have a material adverse impact on the system's financial position and results of operations. In November 1995, Millstone 1 began a planned refueling and maintenance outage that was originally scheduled for 49 days. The outage has encountered several unexpected difficulties, which have lengthened the duration of the outage. The impact of the outage extension is currently under review, but the unit is not expected to return to service until the mid-to-late part of the second quarter of 1996. The estimated costs attributable to the outage extension are replacement-power costs of $6.5 million per month and O&M costs of approximately $20 million. Recovery of the costs related to this outage is subject to prudence reviews by the DPUC and the Massachusetts Department of Public Utilities. On January 31, 1996, the NRC announced that the three Millstone nuclear power plants had been placed on its "watch list" because of long-standing performance concerns. The NRC cited a number of operational problems, which have arisen since 1990 at the Millstone plants. The NRC recognized that there are significant current variations in the performance of the three units. The performance concerns cited by the NRC, combined with NU's failure to maintain previous performance improvements, have resulted in the NRC requiring close monitoring of Millstone unit operations and the implementation of a corrective action program. While the NRC has not specifically restricted operations at the Millstone site, the company expects that there will be costs associated with the NRC's actions that cannot accurately be estimated at this time. C. ENVIRONMENTAL MATTERS The system is subject to regulation by federal, state, and local authorities with respect to air and water quality, handling the disposal of toxic substances and hazardous and solid wastes, and the handling and use of chemical products. The system has an active environmental auditing and training program and believes that it is in substantial compliance with current environmental laws and regulations. Environmental requirements could hinder the construction of new generating units, transmission and distribution lines, substations, and other facilities. The cumulative long-term, cost impact of increasingly stringent environmental requirements cannot accurately be estimated. Changing environmental requirements could also require extensive and costly modifications to the system's existing generating units, and transmission and distribution systems, and could raise operating costs significantly. As a result, the system may incur significant additional environmental costs, greater than amounts included in cost of removal and other reserves, in connection with the generation and transmission of electricity and the storage, transportation, and disposal of by-products and wastes. The system may also encounter significantly increased costs to remedy the environmental effects of prior waste handling activities. The system has recorded a liability for what it believes, based upon information currently available, are its estimated environmental remediation costs for waste disposal sites that the system's subsidiaries expect to incur. In most cases, additional future environmental cleanup costs are not reasonably estimable due to a number of factors, including the unknown magnitude of possible contamination, the appropriate remediation methods, the possible effects of future legislation or regulation, and the possible effects of technological changes. At December 31, 1995, the net liability recorded by the system for its estimated environmental remediation costs, excluding any possible insurance recoveries or recoveries from third parties, amounted to approximately $15 million, which management has determined to be the most probable amount within the range of $15 million to $19 million. The system cannot estimate the potential liability for future claims, including environmental remediation costs, that may be brought against it. However, considering known facts, existing laws, and regulatory practices, management does not believe the matters disclosed above will have a material effect on the system's financial position or future results of operations. D. NUCLEAR INSURANCE CONTINGENCIES Under certain circumstances, in the event of a nuclear incident at one of the nuclear facilities covered by the federal government's third-party liability indemnification program, the system could be assessed in proportion to its ownership interest in each nuclear unit up to $75.5 million not to exceed $10 million per nuclear unit in any one year. The maximum assessment is to be adjusted at least every five years for inflationary changes. Based on the ownership interests in Millstone 1, 2, and 3 and in Seabrook 1, the system's maximum liability, including any additional potential assessments, would be $244.2 million per incident. In addition, through power-purchase contracts with the three operating Yankee regional nuclear generating companies, the system would be responsible for up to an additional $67.4 million per incident. Payments for the system's ownership interest in nuclear generating facilities would be limited to a maximum of $39.3 million per incident per year. Insurance was purchased to cover the primary cost of repair, replacement, or decontamination of utility property resulting from insured occurrences. The system is subject to retroactive assessments if losses exceed the accumulated funds available to the insurer. The maximum potential assessment against the system with respect to losses arising during the current policy year is approximately $15.6 million under the primary property insurance program. Insurance has been purchased to cover certain extra costs incurred in obtaining replacement power during prolonged accidental outages and the excess cost of repair, replacement, or decontamination or premature decommissioning of utility property resulting from insured occurrences. The system is subject to retroactive assessments if losses exceed the accumulated funds available to the insurer. The maximum potential assessments against the system with respect to losses arising during current policy years are approximately $12.3 million under the replacement-power policies and $50.6 million under the excess property damage, decontamination, and decommissioning policies. The cost of a nuclear incident could exceed available insurance proceeds. Insurance has been purchased aggregating $200 million on an industry basis for coverage of worker claims. All participating reactor operators insured under this coverage are subject to retrospective assessments of $3.0 million per reactor. The maximum potential assessment against the system with respect to losses arising during the current policy period is approximately $13.1 million. E. LONG-TERM CONTRACTUAL ARRANGEMENTS YANKEE COMPANIES: CL&P, PSNH, and WMECO purchased approximately 6.7 percent of their electricity requirements pursuant to long-term contracts with the Yankee companies. Under the terms of their agreements, the companies pay their ownership (or entitlement) shares of generating costs, which include depreciation, O&M expenses, taxes, the estimated cost of decommissioning, and a return on invested capital. These costs are recorded as purchased-power expense and recovered through the companies' rates. The total cost of purchases under these contracts for the units that are operating amounted to $161.1 million in 1995, $154.3 million in 1994, and $169.0 million in 1993. See Note 1C, "Summary of Significant Accounting Policies--Investments and Jointly Owned Electric Utility Plant," and Note 3, "Nuclear Decommissioning," for more information on the Yankee companies. NONUTILITY GENERATORS: CL&P, PSNH, and WMECO have entered into various arrangements for the purchase of capacity and energy from NUGs. Some of these arrangements have terms from 10 to 30 years, currently expiring in the years 1998 through 2026, and require the companies to purchase the energy at specified prices or formula rates. For the 12 months ended December 31, 1995, approximately 13 percent of system electricity requirements was met by NUGs. The total cost of purchases under these arrangements amounted to $440.4 million in 1995, $435.0 million in 1994, and $426.8 million in 1993. These costs are eventually recovered through the companies' rates. For additional information, see Note 1J, "Summary of Significant Accounting Policies--Recoverable Energy Costs--PSNH." NEW HAMPSHIRE ELECTRIC COOPERATIVE, INC. (NHEC): PSNH entered into a buy-back agreement to purchase the capacity and energy of NHEC's share of Seabrook 1 and to pay all of NHEC's Seabrook 1 costs for a ten-year period, which began July 1, 1990. The total cost of purchases under this agreement was $15.8 million in 1995, $14.6 million in 1994, and $14.4 million in 1993. A portion of these costs is collected currently through the FPPAC and the remaining costs are deferred for future collection in accordance with the Rate Agreement. In connection with the agreement, NHEC agreed to continue as a firm-requirements customer of PSNH for 15 years. HYDRO-QUEBEC: Along with other New England utilities, CL&P, PSNH, WMECO, and HWP entered into agreements to support transmission and terminal facilities to import electricity from the Hydro-Quebec system in Canada. CL&P, PSNH, WMECO, and HWP, in the aggregate, are obligated to pay, over a 30-year period ending in 2020, their proportionate shares of the annual O&M and capital costs of these facilities. The estimated annual costs of the system's significant long-term contractual arrangements are as follows: - -------------------------------------------------------------------------- 1996 1997 1998 1999 2000 - -------------------------------------------------------------------------- (Millions of Dollars) Yankee Companies . . . . . $160.1 $156.8 $169.0 $171.3 $182.9 Nonutility Generators. . . . . 430.2 440.5 452.1 467.3 474.8 NHEC. . . . . . . . 14.6 22.5 29.5 29.7 14.6 Hydro-Quebec. . . . 35.8 34.0 32.9 32.1 31.6 - -------------------------------------------------------------------------- 7. DERIVATIVE FINANCIAL INSTRUMENTS The company utilizes derivative financial instruments to manage well-defined interest-rate and fuel-price risks. The company does not use them for trading purposes. INTEREST-RATE CAP CONTRACTS: CL&P, PSNH, and WMECO have entered into interest-rate cap contracts with financial institutions in order to reduce a portion of the interest-rate risk associated with certain variable-rate tax-exempt pollution control revenue bonds. During 1995, there were three outstanding contracts held by CL&P, PSNH, and WMECO covering $467 million of variable-rate debt, all of which expired in January 1996. The contracts entitled CL&P, PSNH, and WMECO to receive from counterparties the amounts, if any, by which the interest payments on a portion of its variable-rate tax-exempt pollution control revenue bonds exceed the J.J. Kenny High Grade Index. Due to their upcoming expiration, as of December 31, 1995, the total fair market value of these caps was $0. FUEL SWAPS: CL&P also uses fuel-swap agreements with financial institutions to hedge against some of the fuel-price risk created by long-term negotiated energy contracts. These fuel swaps minimize exposure associated with rising fuel prices and effectively fix most of CL&P's cost of fuel for these negotiated energy contracts. Under the swap agreements, CL&P exchanges monthly payments based on the differential between a fixed and variable price for the associated fuel. As of December 31, 1995, CL&P had outstanding agreements with a total notional value of approximately $249 million, and a negative mark-to-market position of approximately $19 million. When the mark-to-market position for the swap agreements is negative, the profitability of the long-term negotiated energy contracts whose fuel exposure has been hedged increases by a corresponding amount. INTEREST-RATE SWAPS: NAEC uses interest-rate swap agreements with financial institutions to hedge against interest-rate risk associated with its $225 million variable-rate bank note. The interest-rate swaps minimize exposure associated with rising interest rates, and effectively fix the interest rate for this borrowing arrangement. Under the swap agreement, NAEC exchanges quarterly payments based on a differential between a fixed contractual interest rate and the three-month LIBOR rate at a given time. As of December 31, 1995, NAEC had outstanding agreements with a total notional value of approximately $225 million and a negative mark-to-market position of approximately $3.8 million. These swap agreements have been made with various financial institutions, each of which are rated "A" or better by Standard & Poor's rating group. The system companies are exposed to credit risk on fuel swaps, and interest-rate swaps if the counterparties fail to perform their obligations. However, the system companies anticipate that the counterparties will be able to fully satisfy their obligations under the contracts. 8. FAIR VALUE OF FINANCIAL INSTRUMENTS The following methods and assumptions were used to estimate the fair value of each of the following financial instruments: CASH AND NUCLEAR DECOMMISSIONING TRUSTS: The carrying amounts approximate fair value. SFAS 115, ACCOUNTING FOR CERTAIN INVESTMENTS IN DEBT AND EQUITY SECURITIES, requires investments in debt and equity securities to be presented at fair value, and was adopted by the company on a prospective basis as of January 1, 1994. During 1995, the investments held in the company's nuclear decommissioning trusts increased by approximately $19.3 million as of December 31, 1995 and decreased by approximately $5.5 million as of December 31, 1994, with a corresponding offset to the accumulated provision for depreciation. The $19.3 million increase in 1995 represents cumulative gross unrealized holding gains. The cumulative gross unrealized holding losses were immaterial for 1995. The $5.5 million decrease in 1994 represents cumulative gross unrealized holding gains of $1.9 million, offset by cumulative gross unrealized holding losses of $7.4 million. There was no change in funding requirements of the trusts nor any impact on earnings as a result of the adoption of SFAS 115. PREFERRED STOCK AND LONG-TERM DEBT: The fair value of the system's fixed-rate securities is based upon the quoted market price for those issues or similar issues. Adjustable rate securities are assumed to have a fair value equal to their carrying value. The carrying amounts of the system's financial instruments and the estimated fair values are as follows: - ------------------------------------------------------------------------------ Carrying Fair At December 31, 1995 Amount Value - ------------------------------------------------------------------------------ (Thousands of Dollars) Preferred stock not subject to mandatory redemption. . . . . . . . $ 169,700 $ 136,148 Preferred stock subject to mandatory redemption. . . . . . . . 304,000 313,910 Long-term debt -- First Mortgage Bonds. . . . . . . . 2,234,245 2,283,920 Other long-term debt. . . . . . . . 1,697,529 1,733,816 Monthly Income Preferred Securities. . . . . . . . 100,000 108,520 - ------------------------------------------------------------------------------ - ------------------------------------------------------------------------------ Carrying Fair At December 31, 1995 Amount Value - ------------------------------------------------------------------------------ (Thousands of Dollars) Preferred stock not subject to mandatory redemption . . . . . . . . $ 234,700 $ 179,875 Preferred stock subject to mandatory redemption . . . . . . . . 379,675 370,250 Long-term debt -- First Mortgage Bonds . . . . . . . . 2,291,550 22,151,744 Other long-term debt . . . . . . . . 1,830,400 1,811,627 - ------------------------------------------------------------------------------ The fair values shown above have been reported to meet disclosure requirements and do not purport to represent the amounts at which those obligations would be settled. 9. MONTHLY INCOME PREFERRED SECURITIES OF SUBSIDIARY In January 1995, CL&P Capital, L.P. (CL&P LP) issued $100 million of cumulative 9.3 percent Monthly Income Preferred Securities (MIPS), Series A. CL&P has the sole ownership interest in CL&P LP, as a general partner, and is the guarantor of the MIPS securities. Subsequent to the MIPS issuance, CL&P LP loaned the proceeds of the MIPS issuance, along with CL&P's $3.1 million capital contribution, back to CL&P in the form of an unsecured debenture. CL&P consolidates CL&P LP for financial reporting purposes. Upon consolidation, the unsecured debenture is eliminated, and the MIPS securities are accounted for as a minority interest. CONSOLIDATED STATEMENTS OF QUARTERLY FINANCIAL DATA (UNAUDITED)
QUARTER ENDED (a) 1995 March 31 June 30 September 30 December 31 - ------------------------------------------------------------------------------------------------------------------------------- (Thousands of Dollars, except per share data) Operating Revenues .................................. $944,705 $840,333 $985,092 $978,861 ======== ======== ======== ======== Operating Income..................................... $167,327 $118,410 $162,298 $143,945 ======== ======== ======== ======== Net Income .......................................... $ 86,284 $ 42,398 $ 89,526 $64,226 ======== ======== ======== ======== Earnings Per Common Share............................ $0.69 $0.34 $0.71 $0.50 ======== ======== ======== ======== 1994 - ------------------------------------------------------------------------------------------------------------------------------- Operating Revenues .................................. $966,174 $854,627 $923,708 $898,233 ======== ======== ======== ======== Operating Income..................................... $161,290 $124,988 $137,254 $130,393 ======== ======== ======== ======== Net Income .......................................... $ 95,888 $ 61,145 $ 65,029 $ 64,812 ======== ======== ======== ======== Earnings Per Common Share............................ $0.77 $0.49 $0.52 $0.52 ======== ======== ======== ========
CONSOLIDATED GENERATION STATISTICS
1995 1994 1993 1992(b) 1991 - ------------------------------------------------------------------------------------------------------------------------------- SOURCE OF ELECTRIC ENERGY: (KWH--MILLIONS) Nuclear--Steam (c)................................ 18,235 19,443 22,965 15,520 11,062 Fossil--Steam..................................... 9,162 8,292 7,676 6,784 6,179 Hydro--Conventional............................... 1,099 1,239 1,140 1,076 994 Hydro--Pumped Storage............................. 1,209 1,195 1,269 1,221 1,173 Internal Combustion............................... 37 13 8 9 25 Energy Used for Pumping........................... (1,674) (1,629) (1,749) (1,671) (1,605) ------ ------ ------ ------ ------ Net Generation.................................. 28,068 28,553 31,309 22,939 17,828 Purchased and Net Interchange..................... 14,256 14,028 10,499 14,165 13,430 Company Use and Unaccounted for .................. (2,706) (2,535) (2,591) (2,028) (1,958) ------ ------ ------ ------ ------ Net Energy Sold................................. 39,618 40,046 39,217 35,076 29,300 ====== ====== ====== ====== ====== - ------------------------------------------------------------------------------------------------------------------------------- System Capability-MW (c).............................. 8,394.8 8,494.8 7,795.3 7,823.2 5,916.2 System Peak Demand-MW................................. 6,358.2 6,338.5 6,191.0 5,781.0 4,999.8 Nuclear Capacity-MW (c)............................... 3,239.6 3,272.6 3,110.0 2,981.1 2,380.0 Nuclear Contribution to Total Energy Requirements (%) (c)......................... 52.0 54.0 62.1 48.5 43.5 Nuclear Capacity Factor (%) (d)....................... 69.9 67.5 80.8 63.7 50.6 - ------------------------------------------------------------------------------------------------------------------------------- (a) Reclassifications of prior data have been made to conform with the current presentation. (b) Effective with the June 5, 1992 acquisition of PSNH, the consolidated financial and statistical information of NU includes, on a prospective basis, the operations of PSNH and NAEC. (c) Includes the system's entitlements in regional nuclear generating companies, net of capacity sales and purchases. (d) Represents the average capacity factor for the nuclear units operated by the NU system.
SELECTED CONSOLIDATED FINANCIAL DATA
1995 1994 1993 1992(a) 1991 - ---------------------------------------------------------------------------------------------------------------------------------- (Thousands of Dollars, except percentages and share data) BALANCE SHEET DATA: Net Utility Plant (b)................. $ 7,000,837 $ 7,282,421 $ 7,439,159 $ 7,588,368 $ 5,257,567 Total Assets.......................... 10,544,966 10,584,880 10,668,164 9,724,340 6,781,746 Total Capitalization (c).............. 6,820,624 7,035,989 7,309,898 7,421,592 5,138,426 Obligations Under Capital Leases (c).. 230,482 239,121 243,760 266,100 279,729 - ---------------------------------------------------------------------------------------------------------------------------------- INCOME DATA: Operating Revenues.................... $ 3,748,991 $ 3,642,742 $ 3,629,093 $ 3,216,874 $ 2,753,803 Net Income ........................ 282,434 286,874 249,953(d) 256,054 236,709 Earnings per Common Share............. $2.24 $2.30 $2.02(d) $2.02 $2.12 - ---------------------------------------------------------------------------------------------------------------------------------- COMMON SHARE DATA: Earnings per Share.................... $2.24 $2.30 $2.02(d) $2.02 $2.12 Dividends per Share................... $1.76 $1.76 $1.76 $1.76 $1.76 Payout Ratio (%)...................... 78.6 76.5 87.1 87.1 83.0 Number of Shares Outstanding--Average................ 126,083,645 124,678,192 123,947,631(e) 130,403,488 111,453,550 Market Price--High.................... $25 3/8 $25 3/4 $28 7/8 $26 3/4 $24 3/8 Market Price--Low..................... $21 $20 3/8 $22 $22 1/2 $19 Market Price--Closing Price........... (end of year)....................... $24 1/4 $21 5/8 $23 3/4 $26 1/2 $23 5/8 Book Value per Share (end of year)... $19.08 $18.47 $17.89 $16.24 $15.73 Rate of Return Earned on Average Common Equity (%)................. 12.0 12.7 11.4 12.7 13.0 Dividend Yield (end of year) (%)...... 7.3 8.1 7.4 6.6 7.4 Cash Coverage of Common Dividends..... 4.2 4.0 3.3 2.6 2.4 Market-to-Book Ratio (end of year).... 1.3 1.2 1.3 1.6 1.5 Price-Earnings Ratio (end of year).... 10.8 9.4 11.8 13.1 11.1 - ---------------------------------------------------------------------------------------------------------------------------------- CAPITALIZATION: Common Shareholders' Equity........... 36% 33% 30% 29% 37% Preferred Stock (c)(f)................ 7 9 9 9 11 Long-term Debt (c).................... 57 58 61 62 52 ---------- ----------- ----------- ----------- ----------- Total Capitalization.................. 100% 100% 100% 100% 100% ========== =========== =========== =========== =========== - ---------------------------------------------------------------------------------------------------------------------------------- (a) Effective with the June 5, 1992 acquisition of PSNH, the consolidated financial and statistical information of NU includes, on a prospective basis, the operations of PSNH and NAEC. (b) Includes reclassification of the unamortized PSNH acquisition costs to net utility plant. (c) Includes portions due within one year. (d) Includes the cumulative effect of change in accounting for municipal property tax expense, which increased earnings for common shares and earnings per common share by $51.7 million and $0.42, respectively. (e) Decrease in the number of shares results from a change in accounting for ESOP shares. (f) Excludes $100 million of Monthly Income Preferred Securities.
CONSOLIDATED SALES STATISTICS
1995 1994(a) 1993 1992(b) 1991 - ------------------------------------------------------------------------------------------------------------------------------ REVENUES: (THOUSANDS) Residential....................... $1,469,988 $1,430,239 $1,385,818 $1,213,140 $995,098 Commercial........................ 1,230,608 1,173,808(c) 1,043,125 943,832 828,117 Industrial........................ 583,204 559,801(c) 649,876 554,587 419,003 Other Utilities................... 303,004 330,801 383,129 346,791 366,231 Streetlighting and Railroads...... 47,510 45,943 45,480 43,296 38,656 Miscellaneous..................... 48,784 44,140 60,008 59,465 49,539 ---------- ---------- ---------- ---------- ---------- Total Electric.................. 3,683,098 3,584,732 3,567,436 3,161,111 2,696,644 Other............................. 65,893 58,010 61,657 55,763 57,159 ---------- ---------- ---------- ---------- ---------- Total........................... $3,748,991 $3,642,742 $3,629,093 $3,216,874 $2,753,803 ========== ========== ========== ========== ========== - ------------------------------------------------------------------------------------------------------------------------------ SALES: (KWH--MILLIONS) Residential....................... 12,005 12,231 11,988 10,839 9,518 Commercial........................ 11,737 11,649(c) 10,304 9,608 8,900 Industrial........................ 6,842 6,729(c) 7,572 6,593 5,208 Other Utilities................... 8,718 9,123 9,046 7,733 5,388 Streetlighting and Railroads...... 316 314 307 303 286 ---------- ---------- ---------- ---------- ---------- Total........................... 39,618 40,046 39,217 35,076 29,300 ========== ========== ========== ========== ========== - ------------------------------------------------------------------------------------------------------------------------------ CUSTOMERS: (AVERAGE) Residential....................... 1,526,127 1,513,987 1,503,182 1,351,019 1,150,357 Commercial........................ 156,652 154,703(c) 155,487 132,680 102,867 Industrial........................ 7,861 7,813(c) 6,272 5,774 5,067 Other............................. 3,878 3,818 3,793 3,581 3,305 ---------- ---------- ---------- ---------- ---------- Total......................... 1,694,518 1,680,321 1,668,734 1,493,054 1,261,596 ========== ========== ========== ========== ========== - ------------------------------------------------------------------------------------------------------------------------------ AVERAGE ANNUAL USE PER RESIDENTIAL CUSTOMER (KWH)................. 7,917 8,152 7,987 8,129 8,285 - ------------------------------------------------------------------------------------------------------------------------------ AVERAGE ANNUAL BILL PER RESIDENTIAL CUSTOMER....................... $969.41 $953.23 $923.32 $909.80 $866.20 - ------------------------------------------------------------------------------------------------------------------------------ AVERAGE REVENUE PER KWH:(in cents) Residential....................... 12.24 11.69 11.56 11.19 10.45 Commercial........................ 10.49 10.08 10.12 9.82 9.30 Industrial........................ 8.52 8.32 8.58 8.41 8.05 - ------------------------------------------------------------------------------------------------------------------------------ (a) Effective January 1, 1994, the accounting for unbilled revenues was revised to report unbilled revenues by customer class. (b) Effective with the June 5, 1992 acquisition of PSNH, the consolidated financial and statistical information of NU includes, on a prospective basis, the operations of PSNH and NAEC. (c) Effective January 1, 1994, approximately 1,300 customers previously classified as commercial customers were reclassified to industrial customers.
EX-13.2 17 ANNUAL REPORT OF CL&P EXHIBIT 13.2 1995 Annual Report The Connecticut Light and Power Company and Subsidiaries Index Contents Page - -------- ---- Consolidated Balance Sheets................................. 2-3 Consolidated Statements of Income........................... 4 Consolidated Statements of Cash Flows....................... 5 Consolidated Statements of Common Stockholder's Equity...... 6 Notes to Consolidated Financial Statements.................. 7 Report of Independent Public Accountants.................... 28 Management's Discussion and Analysis of Financial Condition and Results of Operations....................... 29 Selected Financial Data..................................... 35 Statements of Quarterly Financial Data...................... 35 Statistics.................................................. 36 Preferred Stockholder and Bondholder Information............ Back Cover THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS
- ------------------------------------------------------------------------------------ At December 31, 1995 1994 - ------------------------------------------------------------------------------------ (Thousands of Dollars) ASSETS - ------ Utility Plant, at original cost: Electric................................................ $6,147,961 $6,063,179 Less: Accumulated provision for depreciation......... 2,418,557 2,194,314 ----------- ----------- 3,729,404 3,868,865 Construction work in progress........................... 103,026 99,993 Nuclear fuel, net....................................... 138,203 164,795 ----------- ----------- Total net utility plant............................. 3,970,633 4,133,653 ----------- ----------- Other Property and Investments: Nuclear decommissioning trusts, at market............... 238,023 171,950 Investments in regional nuclear generating companies, at equity................................... 54,624 54,952 Other, at cost.......................................... 14,821 14,742 ----------- ----------- 307,468 241,644 ----------- ----------- Current Assets: Cash and special deposits (Note 1N)................ 1,757 2,017 Receivables, less accumulated provision for uncollectible accounts of $10,567,000 in 1995 and $12,778,000 in 1994................................ 231,574 192,926 Accounts receivable from affiliated companies........... 3,069 9,367 Accrued utility revenues................................ 91,157 90,475 Fuel, materials, and supplies, at average cost.......... 68,482 64,003 Recoverable energy costs, net--current portion.......... 78,108 10,561 Prepayments and other................................... 42,894 43,654 ----------- ----------- 517,041 413,003 ----------- ----------- Deferred Charges: Regulatory assets (Note 1G)........................ 1,210,384 1,410,334 Unamortized debt expense................................ 14,977 8,396 Other................................................... 10,232 10,427 ----------- ----------- 1,235,593 1,429,157 ----------- ----------- Total Assets........................................ $6,030,735 $6,217,457 =========== ===========
The accompanying notes are an integral part of these financial statements. THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS
- ---------------------------------------------------------------------------------- At December 31, 1995 1994 - ---------------------------------------------------------------------------------- (Thousands of Dollars) CAPITALIZATION AND LIABILITIES - ------------------------------ Capitalization: Common stock--$10 par value--authorized 24,500,000 shares; outstanding 12,222,930 shares in 1995 and 1994.............................. $ 122,229 $ 122,229 Capital surplus, paid in.............................. 637,981 632,117 Retained earnings..................................... 785,476 765,724 ----------- ----------- Total common stockholder's equity............ 1,545,686 1,520,070 Cumulative preferred stock-- $50 par value - authorized 9,000,000 shares; outstanding 5,424,000 shares in 1995 and 1994 $25 par value - authorized 8,000,000 shares; outstanding no shares in 1995 and 5,000,000 shares in 1994 Not subject to mandatory redemption................. 116,200 166,200 Subject to mandatory redemption..................... 155,000 226,250 Long-term debt........................................ 1,812,646 1,815,579 ----------- ----------- Total capitalization......................... 3,629,532 3,728,099 ----------- ----------- Minority Interest in Consolidated Subsidiary (Note 13)............................. 100,000 - ----------- ----------- Obligations Under Capital Leases........................ 108,408 120,268 ----------- ----------- Current Liabilities: Notes payable to banks................................ 41,500 76,000 Notes payable to affiliated company................... 10,250 92,750 Commercial paper...................................... - 10,000 Long-term debt and preferred stock--current portion.............................................. 9,372 11,861 Obligations under capital leases--current portion.............................................. 63,856 55,701 Accounts payable...................................... 110,798 102,837 Accounts payable to affiliated companies.............. 44,677 43,033 Accrued taxes......................................... 52,268 26,413 Accrued interest...................................... 30,854 30,682 Other................................................. 20,027 22,828 ----------- ----------- 383,602 472,105 ----------- ----------- Deferred Credits: Accumulated deferred income taxes (Note 1H)...... 1,486,873 1,544,021 Accumulated deferred investment tax credits........... 142,447 150,087 Deferred contractual obligation....................... 65,847 100,003 Other................................................. 114,026 102,874 ----------- ----------- 1,809,193 1,896,985 ----------- ----------- Commitments and Contingencies (Note 10) Total Capitalization and Liabilities......... $6,030,735 $6,217,457 =========== ===========
The accompanying notes are an integral part of these financial statements. THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME
- ------------------------------------------------------------------------------------- For the Years Ended December 31, 1995 1994 1993 - ------------------------------------------------------------------------------------- (Thousands of Dollars) Operating Revenues................................ $2,386,107 $2,328,052 $2,366,050 ----------- ----------- ---------- Operating Expenses: Operation -- Fuel, purchased and net interchange power.... 608,600 568,394 657,121 Other........................................ 613,420 593,851 641,402 Maintenance..................................... 192,607 207,003 180,403 Depreciation.................................... 242,496 231,155 219,776 Amortization of regulatory assets, net.......... 54,217 77,384 112,353 Federal and state income taxes (Note 8)..... 178,346 190,249 142,987 Taxes other than income taxes................... 172,395 173,068 170,353 ----------- ----------- ---------- Total operating expenses.................. 2,062,081 2,041,104 2,124,395 ----------- ----------- ---------- Operating Income.................................. 324,026 286,948 241,655 ----------- ----------- ---------- Other Income: Deferred nuclear plants return--other funds..... 4,683 13,373 23,537 Equity in earnings of regional nuclear generating companies.......................... 6,545 7,453 6,193 Other, net...................................... 1,170 5,136 (1,044) Income taxes.................................... (2,978) 4,248 3,299 ----------- ----------- ---------- Other income, net......................... 9,420 30,210 31,985 ----------- ----------- ---------- Income before interest charges............ 333,446 317,158 273,640 ----------- ----------- ---------- Interest Charges: Interest on long-term debt...................... 124,350 119,927 134,263 Other interest.................................. 5,596 6,378 9,654 Deferred nuclear plants return--borrowed funds.. (1,716) (7,435) (13,979) ----------- ----------- ---------- Interest charges, net..................... 128,230 118,870 129,938 ----------- ----------- ---------- Income before cumulative effect of accounting change............................... 205,216 198,288 143,702 Cumulative effect of accounting change (Note 1A).................................. - - 47,747 ----------- ----------- ---------- Net Income........................................ $ 205,216 $ 198,288 $ 191,449 =========== =========== ==========
The accompanying notes are an integral part of these financial statements. THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS
- -------------------------------------------------------------------------------------------------- For the Years Ended December 31, 1995 1994 1993 - -------------------------------------------------------------------------------------------------- (Thousands of Dollars) Operating Activities: Net Income.................................................. $ 205,216 $ 198,288 $ 191,449 Adjustments to reconcile to net cash from operating activities: Depreciation.............................................. 242,496 231,155 219,776 Deferred income taxes and investment tax credits, net..... 49,520 37,664 (20,188) Deferred nuclear plants return............................ (6,399) (20,808) (37,516) Amortization of deferred nuclear plants return............ 101,958 103,459 96,256 Recoverable energy costs, net of amortization............. (33,769) 3,975 125,579 Deferred cogeneration costs............................... (55,341) (36,821) - Other sources of cash..................................... 65,597 43,138 80,831 Other uses of cash........................................ (36,435) (9,388) (47,499) Changes in working capital: Receivables and accrued utility revenues.................. (33,032) 45,386 (9,370) Fuel, materials, and supplies............................. (4,479) (3,756) 11,951 Accounts payable.......................................... 9,605 (24,167) 5,433 Accrued taxes............................................. 25,855 (9,726) (82,018) Other working capital (excludes cash)..................... (1,869) (18,403) 9,754 ----------- ----------- ----------- Net cash flows from operating activities...................... 528,923 539,996 544,438 ----------- ----------- ----------- Financing Activities: Issuance of long-term debt.................................. - 535,000 740,500 Issuance of preferred stock................................. - - 80,000 Issuance of Monthly Income Preferred Securities (Note 13)........................ 100,000 - - Net (decrease) increase in short-term debt.................. (127,000) 82,500 (109,490) Reacquisitions and retirements of long-term debt............ (10,866) (774,020) (771,973) Reacquisitions and retirements of preferred stock........... (125,000) - (114,996) Cash dividends on preferred stock........................... (21,185) (23,895) (29,182) Cash dividends on common stock.............................. (164,154) (159,388) (160,365) ----------- ----------- ----------- Net cash flows used for financing activities.................. (348,205) (339,803) (365,506) ----------- ----------- ----------- Investment Activities: Investment in plant: Electric utility plant.................................... (131,858) (149,889) (149,308) Nuclear fuel.............................................. (1,543) (20,905) (13,658) ----------- ----------- ----------- Net cash flows used for investments in plant................ (133,401) (170,794) (162,966) Other investment activities, net............................ (47,577) (29,722) (25,787) ----------- ----------- ----------- Net cash flows used for investments........................... (180,978) (200,516) (188,753) ----------- ----------- ----------- Net Decrease In Cash For The Period........................... (260) (323) (9,821) Cash and special deposits - beginning of period............... 2,017 2,340 12,161 ----------- ----------- ----------- Cash and special deposits - end of period..................... $ 1,757 $ 2,017 $ 2,340 =========== =========== =========== Supplemental Cash Flow Information: Cash paid during the year for: Interest, net of amounts capitalized........................ $ 117,074 $ 115,120 $ 130,592 =========== =========== =========== Income taxes................................................ $ 137,706 $ 161,513 $ 149,056 =========== =========== =========== Increase in obligations: Niantic Bay Fuel Trust...................................... $ 33,537 $ 52,353 $ 40,140 =========== =========== ===========
The accompanying notes are an integral part of these financial statements. THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
- ------------------------------------------------------------------------------------ Capital Retained Common Surplus, Earnings Stock Paid In (a) Total - ------------------------------------------------------------------------------------ (Thousands of Dollars) Balance at January 1, 1993.......... $122,229 $634,851 $ 748,817 $1,505,897 Net income for 1993............. 191,449 191,449 Cash dividends on preferred stock......................... (29,182) (29,182) Cash dividends on common stock.. (160,365) (160,365) Capital stock expenses, net..... (4,580) (4,580) --------- --------- ---------- ----------- Balance at December 31, 1993........ 122,229 630,271 750,719 1,503,219 Net income for 1994............. 198,288 198,288 Cash dividends on preferred stock......................... (23,895) (23,895) Cash dividends on common stock.. (159,388) (159,388) Capital stock expenses, net..... 1,846 1,846 --------- --------- ---------- ----------- Balance at December 31, 1994........ 122,229 632,117 765,724 1,520,070 Net income for 1995............. 205,216 205,216 Cash dividends on preferred stock......................... (21,185) (21,185) Cash dividends on common stock.. (164,154) (164,154) Loss on the retirement of preferred stock............... (125) (125) Capital stock expenses, net..... 5,864 5,864 --------- --------- ---------- ----------- Balance at December 31, 1995........ $122,229 $637,981 $ 785,476 $1,545,686 ========= ========= ========== ===========
(a) The company has dividend restrictions imposed by its long-term debt agreements. At December 31, 1995, these restrictions totaled approximately $540 million. The accompanying notes are an integral part of these financial statements. The Connecticut Light and Power Company and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - ---------------------------------------------------------------------- 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES A. PRESENTATION The consolidated financial statements of The Connecticut Light and Power Company and Subsidiaries (the company or CL&P) include the accounts of all wholly owned subsidiaries. Significant intercompany transactions have been eliminated in consolidation. CL&P, Western Massachusetts Electric Company (WMECO), Holyoke Water Power Company (HWP), Public Service Company of New Hampshire (PSNH), and North Atlantic Energy Corporation (NAEC) are the operating subsidiaries comprising the Northeast Utilities system (the system) and are wholly owned by Northeast Utilities (NU). The system furnishes retail electric service in Connecticut, New Hampshire, and western Massachusetts through CL&P, PSNH, WMECO, and HWP. A fifth subsidiary, NAEC, sells all of its capacity to PSNH. In addition to its retail service, the system furnishes firm and other wholesale electric services to various municipalities and other utilities. The system serves about 30 percent of New England's electric needs and is one of the 20 largest electric utility systems in the country as measured by revenues. Other wholly owned subsidiaries of NU provide substantial support services to the system. Northeast Utilities Service Company (NUSCO) supplies centralized accounting, administrative, data processing, engineering, financial, legal, operational, planning, purchasing, and other services to the system companies. Northeast Nuclear Energy Company (NNECO) acts as agent for system companies in operating the Millstone nuclear generating facilities. North Atlantic Energy Service Corporation (NAESCO) acts as agent for CL&P and NAEC in operating the Seabrook 1 nuclear facility. All transactions among affiliated companies are on a recovery of cost basis which may include amounts representing a return on equity, and are subject to approval by various federal and state regulatory agencies. 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 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. Certain reclassifications of prior years' data have been made to conform with the current year's presentation. Property Taxes: CL&P changed its method of accounting for municipal property tax expense for its respective Connecticut properties during 1993. This one-time change increased 1993 net income by approximately $47.7 million. B. FUTURE ACCOUNTING STANDARD The Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of, in March 1995. SFAS 121 became effective January 1, 1996, and establishes accounting standards for evaluating and recording asset impairment. SFAS 121 requires the evaluation of long-lived assets for impairment when certain events occur or conditions exist that indicate the carrying amounts of assets may not be recoverable. Refer to Note 1G, "Regulatory Accounting," for further information on the regulatory impacts of the company's adoption of SFAS 121. C. INVESTMENTS AND JOINTLY OWNED ELECTRIC UTILITY PLANT Regional Nuclear Generating Companies: CL&P owns common stock of four regional nuclear generating companies (Yankee companies). The Yankee companies, with the company's ownership interests, are: Connecticut Yankee Atomic Power Company (CY) ...... 34.5% Yankee Atomic Electric Company (YAEC) ............. 24.5 Maine Yankee Atomic Power Company (MY) ............ 12.0 Vermont Yankee Nuclear Power Corporation (VY) ..... 9.5 CL&P's investments in the Yankee companies are accounted for on the equity basis due to the company's ability to exercise significant influence over their operating and financial policies. The electricity produced by the facilities that are operating is committed substantially on the basis of ownership interests and is billed pursuant to contractual agreements. Under ownership agreements with the Yankee companies, CL&P may be asked to provide direct or indirect financial support for one or more of the companies. For more information on these agreements, see Note 10E, "Commitments and Contingencies - Long-Term Contractual Arrangements." YAEC's nuclear power plant was shut down permanently on February 26, 1992. For more information on the Yankee companies, see Note 3, ``Nuclear Decommissioning.'' Millstone 1: CL&P has an 81.0 percent joint-ownership interest in Millstone 1, a 660-megawatt (MW) nuclear generating unit. As of December 31, 1995 and 1994, plant-in-service included approximately $372.6 million and $370.9 million, respectively, and the accumulated provision for depreciation included approximately $148.4 million and $135.0 million, respectively, for CL&P's share of Millstone 1. CL&P's share of Millstone 1 expenses is included in the corresponding operating expenses on the accompanying Consolidated Statements of Income. Millstone 2: CL&P has an 81.0 percent joint-ownership interest in Millstone 2, an 870-MW nuclear generating unit. As of December 31, 1995 and 1994, plant-in-service included approximately $684.5 million and $680.5 million, respectively, and the accumulated provision for depreciation included approximately $198.5 million and $175.2 million, respectively, for CL&P's share of Millstone 2. CL&P's share of Millstone 2 expenses is included in the corresponding operating expenses on the accompanying Consolidated Statements of Income. Millstone 3: CL&P has a 52.93 percent joint-ownership interest in Millstone 3, a 1,154-MW nuclear generating unit. As of December 31, 1995 and 1994, plant-in-service included approximately $1.9 billion, and the accumulated provision for depreciation included approximately $455.1 million and $418.5 million, respectively, for CL&P's share of Millstone 3. CL&P's share of Millstone 3 expenses is included in the corresponding operating expenses on the accompanying Consolidated Statements of Income. Seabrook 1: CL&P has a 4.06 percent joint-ownership interest in Seabrook 1, a 1,148-MW nuclear generating unit. As of December 31, 1995 and 1994, plant-in-service included approximately $173.3 million and $173.2 million, respectively, and the accumulated provision for depreciation included approximately $24.8 million and $20.1 million, respectively, for CL&P's share of Seabrook 1. CL&P's share of Seabrook 1 expenses is included in the corresponding operating expenses on the accompanying Consolidated Statements of Income. D. DEPRECIATION The provision for depreciation is calculated using the straight-line method based on estimated remaining lives of depreciable utility plant- in-service, adjusted for salvage value and removal costs, as approved by the appropriate regulatory agency. Except for major facilities, depreciation factors are applied to the average plant-in-service during the period. Major facilities are depreciated from the time they are placed in service. When plant is retired from service, the original cost of plant, including costs of removal, less salvage, is charged to the accumulated provision for depreciation. The depreciation rates for the several classes of electric plant-in-service are equivalent to a composite rate of 4.0 percent in 1995, 3.9 percent in 1994, and 3.8 percent in 1993. See Note 3, ``Nuclear Decommissioning,'' for information on nuclear plant decommissioning. E. PUBLIC UTILITY REGULATION NU is registered with the Securities and Exchange Commission (SEC) as a holding company under the Public Utility Holding Company Act of 1935 (1935 Act), and it and its subsidiaries, including the company, are subject to the provisions of the 1935 Act. Arrangements among the system companies, outside agencies, and other utilities covering interconnections, interchange of electric power, and sales of utility property are subject to regulation by the Federal Energy Regulatory Commission (FERC) and/or the SEC. The company is subject to further regulation for rates, accounting, and other matters by the FERC and/or the Connecticut Department of Public Utility Control (DPUC). F. REVENUES Other than revenues under fixed-rate agreements negotiated with certain wholesale, industrial, and commercial customers, utility revenues are based on authorized rates applied to each customer's use of electricity. In general, rates can be changed only through a formal proceeding before the appropriate regulatory commission. At the end of each accounting period, CL&P accrues an estimate for the amount of energy delivered but unbilled. G. REGULATORY ACCOUNTING The accounting policies of CL&P and the accompanying consolidated financial statements conform to generally accepted accounting principles applicable to rate-regulated enterprises and reflect the effects of the ratemaking process in accordance with SFAS 71, Accounting for the Effects of Certain Types of Regulation. Assuming a cost-of-service based regulatory structure, regulators may permit incurred costs, normally treated as expenses, to be deferred and recovered in future revenues. Through their actions, regulators may also reduce or eliminate the value of an asset, or create a liability. If any portion of the company's operations were no longer subject to the provisions of SFAS 71 as a result of a change in the cost-of-service based regulatory structure or the effects of competition, the company would be required to write off related regulatory assets and liabilities. The company would also be required to determine any impairment to other assets, and write down these assets to fair value. Based on current regulation and recent regulatory decisions, and initiatives relating to competition in the system's markets, the company believes that its use of regulatory accounting remains appropriate. SFAS 121 requires that any assets, including regulatory assets, which are no longer probable of recovery through future revenues, be revalued based on estimated future cash flows. If the revaluation is less than the book value of the asset, an impairment loss would be charged to earnings. As noted above, based on the current regulatory environment in the company's service area, it is not expected that SFAS 121 will have a material impact on the company's financial position or results of operations upon adoption. This conclusion may change in the future as competitive factors influence wholesale and retail pricing in the electric utility industry or if the cost-of-service based regulatory structure were to change. For further information on the company's regulatory environment, refer to Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A). The components of regulatory assets are as follows: At December 31, 1995 1994 ---------------------------------------------------------------------- (Thousands of Dollars) Income taxes, net (Note 1H) ........... $ 863,521 $ 949,134 Deferred demand-side management costs (Note 1I) 117,070 116,133 Cogeneration costs (Note 1J) .......... 92,162 36,821 Unrecovered contractual obligation (Note 3) 65,847 100,003 Recoverable energy costs, net (Note 1K) 27,262 61,040 Deferred costs-nuclear plants ........ 6,170 101,632 Other ................................. 38,352 45,571 ----------------------- $1,210,384 $1,410,334 ======================= H. INCOME TAXES The tax effect of temporary differences (differences between the periods in which transactions affect income in the financial statements and the periods in which they affect the determination of income subject to tax) is accounted for in accordance with the ratemaking treatment of the applicable regulatory commissions. The adoption of SFAS 109, Accounting for Income Taxes, in 1993 increased the company's net deferred tax obligation. As it is probable that the increase in deferred tax liabilities will be recovered from customers through rates, CL&P established a regulatory asset. See Note 8, "Income Tax Expense" for the components of income tax expense. The tax effect of temporary differences, including timing differences accrued under previously approved accounting standards, which give rise to the accumulated deferred tax obligation is as follows: At December 31, 1995 1994 -------------------------------------------------------------------- (Thousands of Dollars) Accelerated depreciation and other plant-related differences ............ $1,074,242 $1,063,823 Regulatory assets - income tax gross up 347,673 402,685 Other .................................. 64,958 77,513 ------------- ----------- $1,486,873 $1,544,021 ========== ========== I. DEMAND-SIDE MANAGEMENT (DSM) CL&P's DSM costs are recovered in base rates through a Conservation Adjustment Mechanism (CAM). As of December 31, 1995, these costs will be recovered by 2000. During October 1995, CL&P filed its 1996 DSM program and forecasted CAM for 1996 with the DPUC. The filing proposes expenditures of $37.1 million in 1996, with recovery over 2.4 years and a zero CAM rate. J. COGENERATION COSTS In accordance with its three-year rate plan that began in July 1993, CL&P was required to defer approximately $72 million and $36 million of cogeneration expense in years two and three, respectively, of the rate plan. CL&P is allowed to defer these costs with carrying charges, and will begin amortization of these costs over a five-year period beginning July 1, 1996. On June 30, 1995, CL&P terminated its existing agreement to purchase power from the O'Brien EPA cogeneration facility and entered into an agreement to purchase an equivalent amount of power from Citizens Lehman Power LP, at a cost below the O'Brien EPA rates. CL&P has applied the resulting savings to the amortization of the cogeneration deferral. K. RECOVERABLE ENERGY COSTS Under the Energy Policy Act of 1992 (Energy Act), CL&P is assessed for its proportionate share of the costs of decontaminating and decommissioning uranium enrichment plants owned by the United States Department of Energy (D&D assessment). The Energy Act requires that regulators treat D&D assessments as a reasonable and necessary current cost of fuel, to be fully recovered in rates, like any other fuel cost. CL&P is currently recovering these costs through rates. As of December 31, 1995, the company's total D&D deferrals were approximately $48.8 million. Retail electric rates include a fuel adjustment clause (FAC) under which fossil-fuel prices above or below base-rate levels are charged or credited to customers. Monthly FAC rates are also subject to quarterly retroactive regulatory review and appropriate adjustments. CL&P also utilizes a generation utilization adjustment clause (GUAC), which defers the effect on fuel costs caused by variations from a specified composite nuclear generation capacity factor embedded in base rates. The company is currently recovering $80 million of its GUAC balance over 18 months. The company set aside $19 million of its 1994-1995 GUAC year request pending the resolution of the company's appeals associated with the two prior GUAC periods. At December 31, 1995, CL&P's net recoverable energy costs, excluding current recoverable energy costs, were approximately $27.3 million. For additional information, see Note 10B, "Commitments and Contingencies - Nuclear Performance." L. SPENT NUCLEAR FUEL DISPOSAL COSTS Under the Nuclear Waste Policy Act of 1982, CL&P must pay the United States Department of Energy (DOE) for the disposal of spent nuclear fuel and high-level radioactive waste. Fees for nuclear fuel burned on or after April 7, 1983 are billed currently to customers and paid to the DOE on a quarterly basis. For nuclear fuel used to generate electricity prior to April 7, 1983 (prior-period fuel), payment may be made anytime prior to the first delivery of spent fuel to the DOE, which may be as early as 1998. Until such payment is made, the outstanding balance will continue to accrue interest at the three-month Treasury Bill Yield Rate. At December 31, 1995, fees due to the DOE for the disposal of prior- period fuel were approximately $150.0 million, including interest costs of $83.5 million. As of December 31, 1995, all fees have been collected through rates. M. DERIVATIVE FINANCIAL INSTRUMENTS The company utilizes interest-rate caps and fuel swaps to manage well- defined interest-rate and fuel-price risks. Premiums paid for purchased interest-rate cap agreements are amortized to interest expense over the terms of the caps. Unamortized premiums are included in deferred charges. Amounts receivable under cap agreements are accrued and offset against interest expense. Amounts receivable or payable under fuel-swap agreements are recognized in income when realized. Any material unrealized gains or losses on fuel swaps and interest-rate caps will be deferred until realized. For further information on derivatives, see Note 11, ``Derivative Financial Instruments.'' N. CASH AND SPECIAL DEPOSITS Cash and special deposits at December 31, 1995, include $1.4 million of special deposits. These funds, which are held by a trustee, represent the proceeds from the sale of the company's land or property, which was subject to the lien of its First Mortgage Bond indenture. The proceeds are held in trust pursuant to the terms of the company's First Mortgage Bond indentures. 2. LEASES CL&P and WMECO finance up to $475 million of nuclear fuel for Millstone 1 and 2 and their respective shares of the nuclear fuel for Millstone 3 under the Niantic Bay Fuel Trust (NBFT) capital lease agreement. CL&P and WMECO make quarterly lease payments for the cost of nuclear fuel consumed in the reactors, based on a units-of-production method at rates which reflect estimated kilowatt-hours of energy provided, plus financing costs associated with the fuel in the reactors. Upon permanent discharge from the reactors, ownership of the nuclear fuel transfers to CL&P and WMECO. CL&P has also entered into lease agreements, some of which are capital leases, for the use of data processing and office equipment, vehicles, nuclear control room simulators, and office space. The provisions of these lease agreements generally provide for renewal options. The following rental payments have been charged to operating expense: Year Capital Leases Operating Leases ---- -------------- ---------------- 1995...................... $56,307,000 $23,793,000 1994...................... 60,975,000 24,192,000 1993...................... 76,606,000 24,355,000 Interest included in capital lease rental payments was $10,587,000 in 1995, $10,228,000 in 1994, and $11,298,000 in 1993. Substantially all of the capital lease rental payments were made pursuant to the nuclear fuel lease agreement. Future minimum lease payments under the nuclear fuel capital lease cannot be reasonably estimated on an annual basis due to variations in the usage of nuclear fuel. Future minimum rental payments, excluding annual nuclear fuel lease payments and executory costs, such as property taxes, state use taxes, insurance, and maintenance, under long-term noncancelable leases, as of December 31, 1995 are: Year Capital Leases Operating Leases ---- -------------- ---------------- (Thousands of Dollars) 1996...................... $ 2,800 $ 19,000 1997...................... 2,700 17,500 1998...................... 2,700 12,600 1999...................... 2,700 10,900 2000...................... 2,500 9,900 After 2000................ 39,600 53,700 -------- ---------- Future minimum lease payments 53,000 $123,600 ======== Less amount representing interest 33,600 -------- Present value of future minimum lease payments for other than nuclear fuel 19,400 Present value of future nuclear fuel lease payments............ 152,900 -------- Total..................... $172,300 ======== 3. NUCLEAR DECOMMISSIONING CL&P's nuclear power plants have service lives that are expected to end during the years 2010 through 2026. Upon retirement, these units must be decommissioned. The company's 1992 decommissioning study concluded that complete and immediate dismantlement at retirement continues to be the most viable and economic method of decommissioning the three Millstone units. A 1994 Seabrook decommissioning study also confirmed that complete and immediate dismantlement at retirement is the most viable and economic method of decommissioning Seabrook 1. Decommissioning studies are reviewed and updated periodically to reflect changes in decommissioning requirements, costs, technology, and inflation. The estimated cost of decommissioning CL&P's ownership share of Millstone 1 and 2, in year-end 1995 dollars, is $300.3 million and $265.8 million, respectively. CL&P's ownership share of the estimated cost of decommissioning Millstone 3 and Seabrook 1 in year-end 1995 dollars, is $232.1 million and $17.2 million, respectively. These estimated costs assume levelized collections for the Millstone units and escalated collections for Seabrook, and after-tax earnings on the Millstone and Seabrook decommissioning funds of 6.5 percent and 6.1 percent, respectively. The Millstone units and Seabrook 1 decommissioning costs will be increased annually by their respective escalation rates. Nuclear decommissioning costs are accrued over the expected service life of the units and are included in depreciation expense on the Consolidated Statements of Income. Nuclear decommissioning costs amounted to $30.5 million in 1995, $25.6 million in 1994, and $21.9 million in 1993. Nuclear decommissioning, as a cost of removal, is included in the accumulated provision for depreciation on the Consolidated Balance Sheets. At December 31, 1995, the balance in the accumulated reserve for decommissioning amounted to $270.0 million. See `Nuclear Decommissioning'' in the MD&A for a discussion of changes being considered by the FASB related to accounting for closure and removal of long-lived assets (including nuclear decommissioning). CL&P has established external decommissioning trusts through a trustee for its portion of the costs of decommissioning Millstone 1, 2, and 3. CL&P's portion of the cost of decommissioning Seabrook 1 is paid to an independent decommissioning financing fund managed by the state of New Hampshire. As of December 31, 1995, CL&P has collected, through rates, $203.5 million, toward the future decommissioning costs of its share of the Millstone units, of which $171.8 million has been transferred to external decommissioning trusts. As of December 31, 1995, CL&P has paid approximately $1.9 million into Seabrook 1's decommissioning financing fund. Earnings on the decommissioning trusts and financing fund increase the decommissioning trust balance and the accumulated reserve for decommissioning. Unrealized gains and losses associated with the decommissioning trusts and financing fund also impact the balance of the trusts and financing fund and the accumulated reserve for decommissioning. Changes in requirements or technology, the timing of funding or dismantling, or adoption of a decommissioning method other than immediate dismantlement would change decommissioning cost estimates and the amounts required to be recovered. CL&P attempts to recover sufficient amounts through its allowed rates to cover its expected decommissioning costs. Only the portion of currently estimated total decommissioning costs that has been accepted by the regulatory agencies is reflected in CL&P's rates. Based on present estimates and assuming its nuclear units operate to the end of their respective license periods, CL&P expects that the decommissioning trusts and financing fund will be substantially funded when the units are retired from service. CL&P, along with other New England utilities, has equity investments in the four Yankee companies. Each Yankee company owns a single nuclear generating unit with service lives that are expected to end during the years 2007 through 2012. The estimated cost, in year-end 1995 dollars, of decommissioning CL&P's ownership share of units owned and operated by CY, MY, and VY is $133.0 million, $42.4 million, and $33.0 million, respectively. Under the terms of the contracts with the Yankee companies, the shareholders-sponsors are responsible for their proportionate share of the operating costs of each unit, including decommissioning. The nuclear decommissioning costs of the Yankee companies are included as part of the cost of power purchased by CL&P. YAEC is in the process of dismantling its nuclear facility. Accelerated decommissioning of that unit has been delayed because of litigation over the Nuclear Regulatory Commission's (NRC) approval of YAEC's decommissioning plan. Effective November 1995, YAEC began billing its sponsors, including CL&P, amounts based on a revised estimate approved by the FERC that assumes decommissioning of the plant by the year 2000. This revised decommissioning estimate was based on access to the Barnwell, South Carolina low-level radioactive waste facility, changes in assumptions about earnings in decommissioning trust investments, and changes in other decommissioning cost assumptions. At December 31, 1995, the estimated remaining costs, including decommissioning, amounted to $268.8 million of which CL&P's share was approximately $65.8 million. Management expects that CL&P will continue to be allowed to recover such FERC-approved costs from its customers. Accordingly, CL&P has recognized these costs as a regulatory asset, with the corresponding obligation, on its Consolidated Balance Sheets. 4. SHORT-TERM DEBT NU, CL&P, WMECO, HWP, NNECO, and The Rocky River Realty Company (RRR) have established a revolving-credit facility with a group of 15 banks. Under this facility, the participating companies may borrow up to an aggregate of $343 million. Individual borrowing limits as of January 1, 1996 were $150 million for NU parent, $325 million for CL&P, $60 million for WMECO, $5 million for HWP, $50 million for NNECO, and $22 million for RRR. The system companies may borrow funds on a short-term revolving basis using either fixed-rate loans or standby loans. Fixed rates are set using competitive bidding. Standby-loan rates are based upon several alternative variable rates. The system companies are obligated to pay a facility fee of 0.15 percent per annum of each bank's total commitment under the three- year portion of the facility, representing 75 percent of the total facility, plus 0.10 percent per annum of each bank's total commitment under the 364-day portion of the facility, representing 25 percent of the total facility. At December 31, 1995 and 1994, there were $42.5 million and $30 million of borrowings, respectively, under the facility. At December 31, 1995, CL&P had $10 million in borrowings outstanding under the facility. The weighted average interest rate on notes payable to banks outstanding at December 31, 1995 was 6.0 percent. The weighted average interest rates on notes payable to banks and commercial paper outstanding at December 31, 1994 were 6.2 percent and 6.4 percent, respectively. Certain subsidiaries of NU, including CL&P, are members of the Northeast Utilities System Money Pool (Pool). The Pool provides a more efficient use of the cash resources of the system, and reduces outside short-term borrowings. NUSCO administers the Pool as agent for the member companies. Short-term borrowing needs of the member companies are first met with available funds of other member companies, including funds borrowed by NU parent. NU parent may lend to the Pool but may not borrow. Funds may be withdrawn from or repaid to the Pool at any time without prior notice. Investing and borrowing subsidiaries receive or pay interest based on the average daily Federal Funds rate. However, borrowings based on loans from NU parent bear interest at NU parent's cost and must be repaid based upon the terms of NU parent's original borrowing. At December 31, 1995 and 1994, CL&P had $10.3 million and $92.8 million, respectively, of borrowings outstanding from the Pool. The interest rates on borrowings from the Pool at December 31, 1995 and 1994 were 4.7 percent and 4.9 percent, respectively. Maturities of CL&P's short-term debt obligations are for periods of three months or less. The amount of short-term borrowings that may be incurred by CL&P is subject to periodic approval by the SEC under the 1935 Act. In addition, the charter of CL&P contains provisions restricting the amount of short-term borrowings. Under the SEC and/or charter restrictions, the company was authorized, as of January 1, 1995, to incur short-term borrowings up to a maximum of $325 million. 5. PREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION Details of preferred stock not subject to mandatory redemption are: December 31, Shares 1995 Outstanding Redemption December 31, December 31, ------------------------- Description Price 1995 1995 1994 1993 - ---------------------------------------------------------------------------- (Thousands of Dollars) $1.90 Series of 1947 $52.50 163,912 $ 8,196 $ 8,196 $ 8,196 $2.00 Series of 1947 54.00 336,088 16,804 16,804 16,804 $2.04 Series of 1949 52.00 100,000 5,000 5,000 5,000 $2.06 Series E of 1954 51.00 200,000 10,000 10,000 10,000 $2.09 Series F of 1955 51.00 100,000 5,000 5,000 5,000 $2.20 Series of 1949 52.50 200,000 10,000 10,000 10,000 $3.24 Series G of 1968 51.84 300,000 15,000 15,000 15,000 3.90% Series of 1949 50.50 160,000 8,000 8,000 8,000 4.50% Series of 1956 50.75 104,000 5,200 5,200 5,200 4.50% Series of 1963 50.50 160,000 8,000 8,000 8,000 4.96% Series of 1958 50.50 100,000 5,000 5,000 5,000 5.28% Series of 1967 51.43 200,000 10,000 10,000 10,000 6.56% Series of 1968 51.44 200,000 10,000 10,000 10,000 1989 Adjustable Rate DARTS - - - 50,000 50,000 ------- -------- -------- Total preferred stock not subject to mandatory redemption $116,200 $166,200 $166,200 ============================= All or any part of each outstanding series of such preferred stock may be redeemed by the company at any time at established redemption prices plus accrued dividend to the date of redemption. 6. PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION Details of preferred stock subject to mandatory redemption are: December 31, Shares 1995 Outstanding Redemption December 31, December 31, --------------------------- Description Price* 1995 1995 1994 1993 - ---------------------------------------------------------------------------- (Thousands of Dollars) 9.00% Series of 1989 - - $ - $ 75,000 $ 75,000 7.23% Series of 1992 $52.41 1,500,000 75,000 75,000 75,000 5.30% Series of 1993 $51.00 1,600,000 80,000 80,000 80,000 --------- --------- -------- 155,000 230,000 230,000 Less preferred stock to be redeemed within one year.... - 3,750 - --------- --------- -------- Total preferred stock subject to mandatory redemption $ 155,000 $ 226,250 $ 230,000 ========= ========= ========= *Each of these series is subject to certain refunding limitations for the first five years after they were issued. Redemption prices reduce in future years. The following table details redemption and sinking fund activity for preferred stock subject to mandatory redemption: Minimum Annual Sinking-Fund Shares Reacquired Series Requirement 1995 1994 1993 ------------------------------------------------------------------- (Thousands of Dollars) 9.10% Series of 1987 $ - - - 2,000,000 9.00% Series of 1989 - 3,000,000 - - 7.23% Series of 1992 (1) 3,750 - - - 5.30% Series of 1993 (2) 16,000 - - - (1) Sinking fund requirements commence September 1, 1998. (2) Sinking fund requirements commence October 1, 1999. The minimum sinking-fund provisions of the series subject to mandatory redemption, for the years 1996 through 2000, aggregate approximately $0 in 1996 and 1997, $3.8 million in 1998, and $19.8 million in 1999 and 2000. In case of default on sinking-fund payments or the payment of dividends, no payments may be made on any junior stock by way of dividends or otherwise (other than in shares of junior stock) so long as the default continues. If the company is in arrears in the payment of dividends on any outstanding shares of preferred stock, the company would be prohibited from redemption or purchase of less than all of the preferred stock outstanding. All or part of each of the series named above may be redeemed by the company at any time at established redemption prices plus accrued dividends to the date of redemption, subject to certain refunding limitations. 7. LONG-TERM DEBT Details of long-term debt outstanding are: December 31, ---------------------- 1995 1994 ------------------------------------------------------------------- (Thousands of Dollars) First Mortgage Bonds: 7 5/8% Series UU ............due 1997 $ 197,245 $ 200,000 6 1/2% Series T .............due 1998 20,000 20,000 7 1/4% Series VV ............due 1999 100,000 100,000 5 1/2% Series A .............due 1999 140,000 140,000 5 3/4% Series XX ............due 2000 200,000 200,000 6 1/8% Series B .............due 2004 140,000 140,000 7 3/8% Series TT ............due 2019 20,000 20,000 7 1/2% Series YY ............due 2023 100,000 100,000 8 1/2% Series C .............due 2024 115,000 115,000 7 7/8% Series D .............due 2024 140,000 140,000 7 3/8% Series ZZ ............due 2025 125,000 125,000 --------- --------- Total First Mortgage Bonds ........ 1,297,245 1,300,000 Pollution Control Notes: Variable rate, due 2016-2022.......... 46,400 46,400 Tax exempt, due 2028.................. 315,500 315,500 Fees and interest due for spent fuel disposal costs (Note 1L) .... 149,978 141,694 Other................................. 20,286 28,398 Less amounts due within one year...... 9,372 8,111 Unamortized premium and discount, net. (7,391) (8,302) ----------- ---------- Long-term debt, net.................. $1,812,646 $1,815,579 =========== ========== Long-term debt and cash sinking-fund requirements on debt outstanding at December 31, 1995 for the years 1996 through 2000 are approximately $9.4 million, $208.1 million, $20.0 million, $240.0 million, and $200.0 million, respectively. In addition, there are annual one-percent sinking- and improvement-fund requirements, currently amounting to $13.0 million for 1996 and 1997, $11.0 million for 1998, $10.8 million for 1999, and $8.4 million for 2000. Such sinking- and improvement-fund requirements may be satisfied by the deposit of cash or bonds or by certification of property additions. All or any part of each outstanding series of first mortgage bonds may be redeemed by the company at any time at established redemption prices plus accrued interest to the date of redemption, except certain series which are subject to certain refunding limitations during their respective initial five-year redemption periods. Essentially all of the company's utility plant is subject to the lien of its first mortgage bond indenture. As of December 31, 1995 and 1994, the company has secured $315.5 million of pollution control notes with second mortgage liens on Millstone 1, junior to the lien of its first mortgage bond indenture. The average effective interest rate on the variable-rate pollution control notes ranged from 3.8 percent to 4.0 percent for 1995 and from 2.7 percent to 3.3 percent for 1994. 8. INCOME TAX EXPENSE The components of the federal and state income tax provisions are: For the Years Ended December 31, 1995 1994 1993 ------------------------------------------------------------------------- (Thousands of Dollars) Current income taxes: Federal..................... $ 93,906 $108,371 $115,403 State....................... 37,898 39,966 44,473 --------- -------- -------- Total current............. 131,804 148,337 159,876 --------- -------- -------- Deferred income taxes, net: Federal..................... 52,075 44,180 3,808 State...................... 5,085 842 (12,987) --------- -------- --------- Total deferred............ 57,160 45,022 ( 9,179) Investment tax credits ....... (7,640) (7,358) (11,009) --------- -------- --------- Total income tax expense.. $181,324 $186,001 $139,688 ======== ======== ======== The components of total income tax expense are classified as follows: Income taxes charged to operating expenses $178,346 $190,249 $142,987 Other income taxes............ 2,978 (4,248) (3,299) -------- --------- ---------- Total income tax expense...... $181,324 $186,001 $139,688 ======== ======== ======== Deferred income taxes are comprised of the tax effects of temporary differences as follows: For the Years Ended December 31, 1995 1994 1993 - -------------------------------------------------------------------------- (Thousands of Dollars) Depreciation, leased nuclear fuel, settlement credits,and disposal costs $44,278 $ 38,874 $ 43,663 Energy adjustment clauses............ 23,302 14,465 (52,189) Demand-side management............... 1,310 203 9,156 Nuclear plant deferrals.............. (8,055) (20,452) (13,979) Bond redemptions..................... (2,255) 6,826 6,935 Contractual settlements.............. (9,496) 109 (308) Other................................ 8,076 4,997 (2,457) -------- --------- --------- Deferred income taxes, net........... $57,160 $ 45,022 $ (9,179) ======== ========= ========= A reconciliation between income tax expense and the expected tax expense at the applicable statutory rate is as follows: For the Years Ended December 31, 1995 1994 1993 - -------------------------------------------------------------------------- (Thousands of Dollars) Expected federal income tax at 35 percent of pretax income........ $135,289 $134,501 $115,898 Tax effect of differences: State income taxes, net of federal benefit 27,939 26,526 20,466 Depreciation....................... 23,517 18,602 19,264 Deferred nuclear plants return..... (1,639) (4,681) (8,294) Amortization of deferred nuclear plants return 20,218 19,755 18,648 Property tax....................... (159) 5,286 (12,320) Investment tax credit amortization. (7,640) (7,358) (11,009) Adjustment for prior years' taxes.. (10,442) (2,706) (2,330) Other, net......................... (5,759) (3,924) (635) --------- --------- --------- Total income tax expense............. $181,324 $186,001 $139,688 ========= ========= ========= 9. EMPLOYEE BENEFITS A. PENSION BENEFITS The company participates in a uniform noncontributory-defined benefit retirement plan covering all regular system employees. Benefits are based on years of service and employees' highest eligible compensation during five consecutive years of employment. The company's direct portion of the system's pension (income)/cost, part of which was (credited)/charged to utility plant, approximated $(10.4) million in 1995, $(2.3) million in 1994, and $7.6 million in 1993. The company's pension costs for 1995, 1994, and 1993 include approximately $0.1 million, $4.8 million, and $13.1 million, respectively, related to workforce-reduction programs. Currently, the company funds annually an amount at least equal to that which will satisfy the requirements of the Employee Retirement Income Security Act and the Internal Revenue Code. Pension costs are determined using market-related values of pension assets. Pension assets are invested primarily in domestic and international equity securities and bonds. The components of net pension cost for CL&P are: For the Years Ended December 31, 1995 1994 1993 ------------------------------------------------------------------ (Thousands of Dollars) Service cost.................. $ 7,543 $ 13,072 $ 21,907 Interest cost................. 37,110 36,103 35,055 Return on plan assets......... (138,582) 1,020 (80,615) Net amortization.............. 83,516 (52,536) 31,254 ---------- --------- --------- Net pension (income)/cost..... $(10,413) $ (2,341) $ 7,601 ========== ========= ========= For calculating pension cost, the following assumptions were used: For the Years Ended December 31, 1995 1994 1993 ------------------------------------------------------------------- Discount rate................. 8.25% 7.75% 8.00% Expected long-term rate of return 8.50 8.50 8.50 Compensation/progression rate. 5.00 4.75 5.00 The following table represents the plan's funded status reconciled to the Consolidated Balance Sheets: At December 31, 1995 1994 ----------------------------------------------------------------- (Thousands of Dollars) Accumulated benefit obligation, including vested benefits at December 31, 1995 and 1994 of $404,540,000 and $374,109,000, respectively $432,987 $401,889 ======== ======== Projected benefit obligation............. $515,121 $471,079 Market value of plan assets.............. 668,929 568,294 --------- -------- Market value in excess of projected benefit obligation 153,808 97,215 Unrecognized transition amount........... (8,285) (9,204) Unrecognized prior service costs......... 1,293 1,420 Unrecognized net gain.................... (135,817) (88,845) --------- --------- Prepaid pension asset.................... $ 10,999 $ 586 ========== ========= ------------------------------------------------------------------ The following actuarial assumptions were used in calculating the plan's year-end funded status: At December 31, 1995 1994 ------------------------------------------------------------------ Discount rate............................ 7.50% 8.25% Compensation/progression rate............ 4.75 5.00 B. POSTRETIREMENT BENEFITS OTHER THAN PENSIONS The company provides certain health care benefits, primarily medical and dental, and life insurance benefits through a benefit plan to retired employees (referred to as SFAS 106 benefits). These benefits are available for employees retiring from the company who have met specified service requirements. For current employees and certain retirees, the total SFAS 106 benefit is limited to two times the 1993 per-retiree health care costs. The SFAS 106 obligation has been calculated based on this assumption. CL&P's direct portion of SFAS 106 health care and life insurance costs, part of which were deferred or charged to utility plant, approximated $20.7 million in 1995, $22.3 million in 1994, and $23.2 million in 1993. During 1995 and 1994, the company funded SFAS 106 postretirement costs through external trusts. During 1993, the company did not fund SFAS 106 postretirement costs through external trusts. The company is funding, on an annual basis, amounts that have been rate-recovered and which also are tax-deductible under the Internal Revenue Code. The trust assets are invested primarily in equity securities and bonds. The components of health care and life insurance cost are: For the Years Ended December 31, 1995 1994 1993 ------------------------------------------------------------------------- (Thousands of Dollars) Service cost .................... $ 2,248 $ 2,371 $ 3,397 Interest cost ................... 11,510 12,157 12,091 Return on plan assets ........... (1,015) 2 - Amortization of unrecognized transition obligation 7,344 7,344 7,682 Other amortization, net ......... 602 430 - -------- -------- ------- Net health care and life insurance costs $20,689 $22,304 $23,170 ======= ======= ======= ------------------------------------------------------------------------- For calculating SFAS 106 benefits cost, the following assumptions were used: For the Years Ended December 31, 1995 1994 1993 ------------------------------------------------------------------------- Discount rate ................... 8.00% 7.75% 7.75% Long-term rate of return: Health assets, net of tax ..... 5.00 5.00 5.00 Life assets ................... 8.50 8.50 8.50 The following table represents the plan's funded status reconciled to the Consolidated Balance Sheets: At December 31, 1995 1994 --------------------------------------------------------------------- (Thousands of Dollars) Accumulated postretirement benefit obligation of: Retirees .................................. $126,624 $129,111 Fully eligible active employees ........... 198 241 Active employees not eligible to retire ... 29,798 25,203 -------- -------- Total accumulated postretirement benefit obligation 156,620 154,555 Market value of plan assets ................ 11,378 167 -------- -------- Accumulated postretirement benefit obligation in excess of plan assets ................. (145,242) (154,388) Unrecognized transition amount ............. 124,850 132,194 Unrecognized net loss ...................... 1,260 192 -------- -------- Accrued postretirement benefit liability ... $(19,132) $(22,002) ======== ========= The following actuarial assumptions were used in calculating the plan's year-end funded status: At December 31, 1995 1994 -------------------------------------------------------------------- Discount rate .............................. 7.50% 8.00% Health care cost trend rate (a) ............ 8.40 10.20 (a) The annual growth in per capita cost of covered health care benefits was assumed to decrease to 5.4 percent by 2001. The effect of increasing the assumed health-care-cost trend rate by one percentage point in each year would increase the accumulated postretirement benefit obligation as of December 31, 1995 by $8.5 million and the aggregate of the service and interest cost components of net periodic postretirement benefit cost for the year then ended by $0.7 million. The trust holding the plan assets is subject to federal income taxes at a 35 percent tax rate. CL&P is currently recovering SFAS 106 costs, including amounts previously deferred. 10.COMMITMENTS AND CONTINGENCIES A. CONSTRUCTION PROGRAM The construction program is subject to periodic review and revision. CL&P currently forecasts construction expenditures of approximately $776.3 million for the years 1996-2000, including $154.6 million for 1996. In addition, the company estimates that nuclear fuel requirements, including nuclear fuel financed through the NBFT, will be approximately $240.4 million for the years 1996-2000, including $35.1 million for 1996. See Note 2, ``Leases,'' for additional information about the financing of nuclear fuel. B. NUCLEAR PERFORMANCE Outages that occurred over the period October 1990 through February 1992 at the Millstone nuclear units have been the subject of five ongoing prudence reviews in Connecticut. CL&P has received final decisions on each of the reviews. Three of these prudence reviews are either on appeal or still pending at the DPUC. The exposure under these three dockets is approximately $92 million. On April 10, 1995, the DPUC initiated a proceeding to investigate the prudence of a Millstone 2 extended outage, which ended June 1994. Approximately $13 million of costs are at issue. In October 1994, Millstone 2 began a planned refueling and maintenance outage that was originally scheduled for 63 days. The outage encountered several unexpected difficulties which extended the duration of the outage until August 4, 1995. Total replacement power costs attributable to the extension of the outage for CL&P were approximately $69 million. Operation and maintenance (O&M) costs incurred during the outage were approximately $57 million, an increase of $30 million as a result of the outage extension. O&M costs associated with the refueling outage are deferred and amortized through rates. The recovery of replacement power and O&M costs is subject to refund pending a prudence review in Connecticut. Management does not believe the outcome of the prudence reviews discussed above will have a material adverse impact on the company's financial position and results of operations. In November 1995, Millstone 1 began a planned refueling and maintenance outage that was originally scheduled for 49 days. The outage has encountered several unexpected difficulties which has lengthened the duration of the outage. The impact of the outage extension is currently under review, but the unit is not expected to return to service until the mid-to-late part of the second quarter of 1996. The estimated costs attributable to this outage extension are replacement-power costs of $5.2 million per month and O&M costs of approximately $16.2 million. Recovery of the costs related to this outage is subject to prudence reviews by the DPUC. On January 31, 1996, the NRC announced that the three Millstone nuclear power plants operated by NNECO have been placed on its "watch list" because of long standing performance concerns. The NRC cited a number of operational problems which have arisen since 1990 at the Millstone plants. The NRC recognized that there are significant current variations in the performance of the three units. The performance concerns cited by the NRC, combined with NU's failure to maintain previous performance improvements, have resulted in the NRC requiring close monitoring of Millstone unit operations and the implementation of a corrective action program. While the NRC has not specifically restricted operations at the Millstone site, the company expects that there will be costs associated with the NRC's actions that cannot be accurately estimated at this time. C. ENVIRONMENTAL MATTERS CL&P is subject to regulation by federal, state, and local authorities with respect to air and water quality, handling the disposal of toxic substances and hazardous and solid wastes, and the handling and use of chemical products. CL&P has an active environmental auditing and training program and believes that it is in substantial compliance with current environmental laws and regulations. Environmental requirements could hinder the construction of new generating units, transmission and distribution lines, substations, and other facilities. The cumulative long-term, cost impact of increasingly stringent environmental requirements cannot accurately be estimated. Changing environmental requirements could also require extensive and costly modifications to CL&P's existing generating units, and transmission and distribution systems, and could raise operating costs significantly. As a result, CL&P may incur significant additional environmental costs, greater than amounts included in cost of removal and other reserves, in connection with the generation and transmission of electricity and the storage, transportation, and disposal of by- products and wastes. CL&P may also encounter significantly increased costs to remedy the environmental effects of prior waste handling activities. CL&P has recorded a liability for what it believes, based upon information currently available, are its estimated environmental remediation costs for waste disposal sites. In most cases, additional future environmental cleanup costs are not reasonably estimable due to a number of factors, including the unknown magnitude of possible contamination, the appropriate remediation methods, the possible effects of future legislation or regulation, and the possible effects of technological changes. At December 31, 1995, the net liability recorded by CL&P for its estimated environmental remediation costs, excluding any possible insurance recoveries or recoveries from third parties, amounted to approximately $7.4 million, which management has determined to be the most probable amount within the range of $7.4 million to $9.8 million. CL&P cannot estimate the potential liability for future claims, including environmental remediation costs, that may be brought against it. However, considering known facts, existing laws, and regulatory practices, management does not believe the matters disclosed above will have a material effect on CL&P's financial position or future results of operations. D. NUCLEAR INSURANCE CONTINGENCIES Under certain circumstances, in the event of a nuclear incident at one of the nuclear facilities covered by the federal government's third- party liability indemnification program, the company could be assessed in proportion to its ownership interest in each nuclear unit up to $75.5 million not to exceed $10 million per nuclear unit in any one year. The maximum assessment is to be adjusted at least every five years for inflationary changes. Based on the ownership interest in Millstone 1, 2, and 3 and in Seabrook 1, CL&P's maximum liability, including any additional potential assessments, would be $173.6 million per incident. In addition, through power purchase contracts with the three operating Yankee regional nuclear generating companies, CL&P would be responsible for up to an additional $44.4 million per incident. Payments for CL&P's ownership interest in nuclear generating facilities would be limited to a maximum of $27.5 million per incident per year. Insurance has been purchased to cover the primary cost of repair, replacement, or decontamination of utility property resulting from insured occurrences. CL&P is subject to retroactive assessments if losses exceed the accumulated funds available to the insurer. The maximum potential assessment against CL&P with respect to losses arising during the current policy year is approximately $12.2 million under the primary property insurance program. Insurance has been purchased to cover certain extra costs incurred in obtaining replacement power during prolonged accidental outages and the excess cost of repair, replacement, or decontamination or premature decommissioning of utility property resulting from insured occurrences. CL&P is subject to retroactive assessments if losses exceed the accumulated funds available to the insurer. The maximum potential assessments against the company with respect to losses arising during current policy years are approximately $8.6 million under the replacement power policies and $31.6 million under the excess property damage, decontamination, and decommissioning policies. The cost of a nuclear incident could exceed available insurance proceeds. Insurance has been purchased aggregating $200 million on a industry basis for coverage of worker claims. All participating reactor operators insured under this coverage are subject to retrospective assessments of $3.0 million per reactor. The maximum potential assessment against CL&P with respect to losses arising during the current policy period is approximately $9.1 million. E. LONG-TERM CONTRACTUAL ARRANGEMENTS Yankee Companies: CL&P, along with PSNH and WMECO, purchased approximately 6.7 percent of their electricity requirements pursuant to long-term contracts with the Yankee companies. Under the terms of their agreements, the companies pay their ownership (or entitlement) shares of generating costs, which include depreciation, O&M expenses, taxes, the estimated cost of decommissioning, and a return on invested capital. These costs are recorded as purchased-power expense and recovered through the companies' rates. CL&P's total cost of purchases under these contracts for the units that are operating amounted to $105.8 million in 1995, $102.1 million in 1994, and $112.3 million in 1993. See Note 1C, ``Summary of Significant Accounting Policies-Investments and Jointly Owned Electric Utility Plant,'' and Note 3, ``Nuclear Decommissioning,'' for more information on the Yankee companies. Nonutility Generators: CL&P has entered into various arrangements for the purchase of capacity and energy from nonutility generators. These arrangements have terms from 10 to 30 years, currently expiring in the years 2001 through 2026, and requires the company to purchase the energy at specified prices or formula rates. For the twelve months ended December 31, 1995, approximately 13 percent of system electricity requirements was met by nonutility generators. CL&P's total cost of purchases under these arrangements amounted to $282.2 million in 1995, $277.4 million in 1994, and $279.8 million in 1993. These costs are eventually recovered through the company's rates. Hydro-Quebec: Along with other New England utilities, CL&P, PSNH, WMECO, and HWP entered into agreements to support transmission and terminal facilities to import electricity from the Hydro-Quebec system in Canada. CL&P is obligated to pay, over a 30-year period ending in 2020, its proportionate share of the annual O&M and capital costs of these facilities. The estimated annual costs of CL&P's significant long-term contractual arrangements are as follows: 1996 1997 1998 1999 2000 ---------------------------------------------------------------------- (Millions of Dollars) Yankee companies $105.8 $103.1 $111.0 $112.9 $120.5 Nonutility generators 269.0 273.5 280.1 290.1 290.9 Hydro-Quebec .. 20.3 19.4 18.7 18.3 18.0 11. DERIVATIVE FINANCIAL INSTRUMENTS The company utilizes derivative financial instruments to manage well- defined interest-rate and fuel-price risks. The company does not use them for trading purposes. Interest-Rate Cap Contracts: CL&P has entered into interest-rate cap contracts with financial institutions in order to reduce a portion of the interest-rate risk associated with certain variable-rate tax-exempt pollution control revenue bonds. During 1995, there was one outstanding contract held by CL&P covering $340 million of variable-rate debt, which expired in January 1996. The contract entitled CL&P to receive from a counterparty the amounts, if any, by which the interest payments on a portion of its variable-rate tax-exempt pollution control revenue bonds exceed the J. J. Kenny High Grade Index. Due to its upcoming expiration, as of December 31, 1995, the total fair market value of the cap was $0. Fuel Swaps: CL&P also uses fuel-swap agreements with financial institutions to hedge against fuel-price risk created by long-term negotiated energy contracts. These fuel swaps minimize exposure associated with rising fuel prices, and effectively fix CL&P's cost of fuel for these negotiated energy contracts. Under the swap agreements, CL&P exchanges monthly payments based on the differential between a fixed and variable price for the associated fuel. As of December 31, 1995, CL&P had outstanding agreements with a total notional value of approximately $249 million, and a negative mark-to-market position of approximately $19 million. When the mark-to-market position for the swap agreements is negative, the profitability of the long-term negotiated energy contracts whose fuel exposure has been hedged increases by a corresponding amount. These swap agreements have been made with various financial institutions, each of which are rated "A" or better by Standard & Poor's rating group. CL&P is exposed to credit risk on the fuel swaps if the counterparties fail to perform their obligations. However, CL&P anticipates that the counterparties will be able to fully satisfy their obligations under the contracts. 12.FAIR VALUE OF FINANCIAL INSTRUMENTS The following methods and assumptions were used to estimate the fair value of each of the following financial instruments: Cash, special deposits, and nuclear decommissioning trusts: The carrying amounts approximate fair value. SFAS 115, Accounting for Certain Investments in Debt and Equity Security, requires investments in debt and equity securities to be presented at fair value and was adopted by the company on a prospective basis as of January 1, 1994. During 1995, the investments held in the company's nuclear decommissioning trusts increased by $14.4 million as of December 31, 1995 and decreased by approximately $3.8 million as of December 31, 1994, with a corresponding offset to the accumulated provision for depreciation. The $14.4 million increase in 1995 represents cumulative gross unrealized holding gains. The cumulative gross unrealized holding losses were immaterial for 1995. The $3.8 million decrease in 1994 represents cumulative gross unrealized holding gains of $1.6 million, offset by cumulative gross unrealized holding losses of $5.4 million. There was no change in funding requirements of the trusts nor any impact on earnings as a result of the adoption of SFAS 115. Preferred stock and long-term debt: The fair value of CL&P's fixed rate securities is based upon the quoted market price for those issues or similar issues. Adjustable rate securities are assumed to have a fair value equal to their carrying value. The carrying amounts of CL&P's financial instruments and the estimated fair values are as follows: Carrying Fair At December 31, 1995 Amount Value -------------------------------------------------------------------------- (Thousands of Dollars) Preferred stock not subject to mandatory redemption $ 116,200 $ 82,448 Preferred stock subject to mandatory redemption 155,000 157,575 Long-term debt - First Mortgage Bonds .... 1,297,245 1,329,549 Other long-term debt ..................... 532,164 532,164 Monthly Income Preferred Securities ...... 100,000 108,520 -------------------------------------------------------------------------- Carrying Fair At December 31, 1994 Amount Value -------------------------------------------------------------------------- (Thousands of Dollars) Preferred stock not subject to mandatory redemption $ 166,200 $ 113,825 Preferred stock subject to mandatory redemption 230,000 218,075 Long-term debt - First Mortgage Bonds .... 1,300,000 1,182,894 Other long-term debt ..................... 531,992 531,992 The fair values shown above have been reported to meet disclosure requirements and do not purport to represent the amounts at which those obligations would be settled. 13.MONTHLY INCOME PREFERRED SECURITIES OF SUBSIDIARY In January 1995, CL&P Capital, LP (CL&P LP) issued $100 million of cumulative 9.3 percent Monthly Income Preferred Securities (MIPS), Series A. CL&P has the sole ownership interest in CL&P LP, as a general partner, and is the guarantor of the MIPS securities. Subsequent to the MIPS issuance, CL&P LP loaned the proceeds of the MIPS issuance, along with CL&P's $3.1 million capital contribution, back to CL&P in the form of an unsecured debenture. CL&P consolidates CL&P LP for financial reporting purposes. Upon consolidation, the unsecured debenture is eliminated, and the MIPS securities are accounted for as a minority interest. THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS - ---------------------------------------------------------------------- To the Board of Directors of The Connecticut Light and Power Company and Subsidiaries: We have audited the accompanying consolidated balance sheets of The Connecticut Light and Power Company and Subsidiaries (a Connecticut corporation and a wholly owned subsidiary of Northeast Utilities) as of December 31, 1995 and 1994, and the related consolidated statements of income, common stockholder's equity, 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 of 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 financial position of The Connecticut Light and Power Company and Subsidiaries 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. As discussed in Note 1A to the Financial Statements, effective January 1, 1993, The Connecticut Light and Power Company and Subsidiaries changed its method of accounting for property taxes. /s/ Arthur Andersen LLP ARTHUR ANDERSEN LLP Hartford, Connecticut February 16, 1996 THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - -------------------------------------------------------------------------------- This section contains management's assessment of CL&P's (the company) financial condition and the principal factors having an impact on the results of operations. The company is a wholly owned subsidiary of Northeast Utilities (NU). This discussion should be read in conjunction with the company's financial statements and footnotes. FINANCIAL CONDITION OVERVIEW Net income was approximately $205 million in 1995, an increase of approximately $7 million, from approximately $198 million in 1994. The 1995 net income was higher primarily due to higher revenues from the final step of the company's three-year rate plan, lower income tax expenses, higher 1995 cogeneration deferrals, and a reduction in maintenance costs. These increases were partially offset by lower wholesale revenues, higher operation costs, and higher fuel and purchased-power costs. Retail kilowatt-hour sales fell by 0.3 percent in 1995, as a result of a flat economy in southern New England and mild weather in the first quarter of 1995. With the southern New England economy not forecasted to grow substantially during 1996, sales levels are expected to remain flat. CL&P acts as both a buyer and a seller of electricity in the highly competitive wholesale electricity market in the Northeast. Increased competition has made the renegotiation of expiring wholesale contracts, as well as the signing of new contracts, financially challenging. As a result, wholesale power revenues fell to approximately $188 million in 1995, from approximately $215 million in 1994. CL&P's efforts to enhance its wholesale revenues resulted in several new contracts in 1995. During 1995, the Federal Energy Regulatory Commission issued a proposal for restructuring the electric-power industry, which calls for open access to transmission facilities, a standard formula for calculating rates, and full recovery of stranded investments. The impact on CL&P of this proposal, which is expected to be finalized in 1996, is not known at this time. During 1995, the Coalition of Northeastern Governors released its report addressing the restructuring of the electric-power industry and its resulting impact on customers and states. The report presented the future as one in which there would be some form of continued regulation for transmission and distribution with fully competitive generation. Also in 1995, the Department of Public Utility Control (DPUC) concluded that while increased competition is in the public interest, electric utilities should have the opportunity to recover "net, nonmitigatable stranded costs" during a transition period to full competition. While such a conclusion is encouraging there is uncertainty with regard to the final regulatory and legislative definitions of terms such as "net, nonmitigatable" and "stranded costs." CL&P is taking a proactive role in the electric-power industry's movement toward competition. In its "Path To A Competitive Future" (the plan), CL&P outlined a comprehensive approach to enhancing customer satisfaction and market efficiency while moving toward full competition in the electricity marketplace. The plan also calls for several significant changes in electricity pricing, the ability to introduce new products and services, the method of rate-setting, and the operation of the New England Power Pool. The plan also calls for the phase-in of supplier choices through the use of pilot programs. Management believes that a fully competitive market for electricity should begin once all issues relating to the transition from traditional utility regulation have been thoroughly addressed. In addition to the formulation of this plan and ongoing meetings with legislators, regulators, and others in the industry, CL&P is moving ahead in other areas, including revenue enhancement initiatives and cost reductions, to better position itself for an increasingly competitive environment. A comprehensive companywide effort, which started in 1994, to reengineer CL&P's business and operating processes continued throughout 1995. CL&P expects that this effort will have significant positive effects on operating costs and customer service. Many of the organizational changes in the operating and service functions announced in 1995 and early 1996 are consistent with the initial recommendations of the reengineering teams. While CL&P's reengineering efforts will be reduced in 1996, implementation costs relating to the previous reengineering efforts are expected to increase. With retail electric revenues accounting for approximately 90 percent of its 1995 revenues, CL&P has continued to develop a number of initiatives to retain and serve its existing customers and to expand its retail customer base. The most visible result of these efforts is the expansion of the Retail Marketing organization. Retail Marketing's mission is to better understand the needs and concerns of CL&P's retail customer and to develop innovative approaches to addressing these issues. These initiatives include providing discounts to certain customers for signing economic development and competitive generation- based contracts, offering demand-side-management services, and providing additional products and services. WORKFORCE REDUCTIONS In January 1996, NU completed its nuclear workforce reduction plan. Approximately 220 positions were eliminated through a combination of early retirements, attrition, and layoffs. The total pretax cost of the workforce reduction to the NU system, which was recognized in 1995, was approximately $9 million. RATE MATTERS CL&P follows accounting principles in accordance with Statement of Financial Accounting Standards (SFAS) 71, "Accounting for the Effects of Certain Types of Regulation" that allows the economic effects of rate regulation to be reflected. Under these principles, regulators may permit incurred costs for certain events or transactions, which would be treated as expenses by nonregulated enterprises, to be deferred as regulatory assets and recovered in revenues at a later date. The creation of these regulatory assets has kept down electric rates in past years, at the expense of having higher rates in the future. At December 31, 1995, CL&P's regulatory assets totaled approximately $1.2 billion. The largest regulatory asset, nearly $864 million, is related to the future recovery of income taxes. The substantial costs of amortizing these regulatory assets would hinder CL&P from competing effectively in an openly competitive electric market if customers are not required to pay such costs. Given the increasingly competitive nature of the industry and increased activity in the regulatory environment, CL&P has made the recovery of regulatory assets one of its central financial strategies, while balancing the customer's pricing needs with NU's shareholder's earnings requirements. Under its existing rate agreement, CL&P is allowed to recover a significant portion of its regulatory assets during the next five years. However, maintaining or increasing the present recovery level is dependent upon the outcome of negotiations between CL&P and the DPUC when its current rate agreement expires. Given that CL&P's current rate agreement expires during 1996, CL&P will actively pursue early negotiations with the DPUC to determine whether, or to what extent, rates should be adjusted going forward. CL&P's strategy during these negotiations will be to maintain stable rates, applying any available earnings that may result to reduce the balance of its regulatory assets. Management is unable to predict the ultimate outcome of these negotiations, which will be subject to DPUC approval. In March 1995, the Financial Accounting Standards Board (FASB) issued SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of." SFAS 121, which was effective January 1, 1996, requires assets, including regulatory assets, that are no longer probable of recovery through future revenues be charged to earnings. If future competition or regulatory actions cause any portion of its operations to no longer be subject to SFAS 71, CL&P would be required to determine the fair value of the related regulatory assets and liabilities and record any necessary write-downs. Additionally, if events create uncertainty about the recoverability of any of CL&P's remaining long-lived assets, a similar analysis would be required for those assets in accordance with SFAS 121. Under its current regulatory environment, CL&P believes that its use of SFAS 71 remains appropriate and that the adoption of SFAS 121 will not have a material impact on its financial position or results of operations. See the Notes to Consolidated Financial Statements," Note 1G, for further details on regulatory accounting. CL&P's retail rates increased by approximately $48 million, or 2.06 percent, in July 1995, representing the final step of a three-year rate plan approved by the DPUC. The 1993 rate decision has been appealed. If this appeal prevails there may be revenues subject to refund, however, management believes it is unlikely that the appeal will prevail. CL&P recovers from, or refunds to, customers certain fuel costs if its nuclear units do not operate at a predetermined capacity factor (currently 72 percent) through a Generation Utilization Adjustment Clause (GUAC). CL&P is currently recovering approximately $80 million of fuel costs for the 1994-1995 GUAC period (net of $19 million of asserted fuel overrecoveries for the period) over 18 months. CL&P has appealed the $19 million that was set aside from its allowed recovery and will seek to join this appeal to appeals currently pending from previous GUAC periods. See the "Notes to Consolidated Financial Statements," Note 10B, for further details on outage deferrals and recoveries. NUCLEAR PERFORMANCE On January 31, 1996, the Nuclear Regulatory Commission (NRC) placed Millstone 1, 2, and 3 (Millstone) on its "watch list." The NRC's action was in response to a number of performance concerns which have arisen since 1990 and a failure to resolve employee safety concerns. The NRC's action will result in close monitoring of programs and performance at Millstone to assure the development and implementation of effective corrective actions. NU's management plans to continue its extensive efforts already under way to address these concerns. Concurrent with the NRC's action, NU provided the NRC with the results of a comprehensive self-assessment review of the employee concern program at Millstone. Additionally, in January 1996, NU announced a reorganization of its nuclear operations which included the creation of a new office of Nuclear Safety and Oversight. Although the start-up of Millstone 1, which is currently in outage, will be affected by its placement on the NRC's "watch list," operations at Millstone 2 and 3 have not been restricted. NU's management expects that the increased NRC attention will inevitably have effects and costs that are not known at this time. In November 1995, Millstone 1 began a planned refueling and maintenance outage. The outage has been extended to allow NU to complete reviews required by the NRC. In response to a request by the NRC, NU is conducting a detailed review of Millstone 1's Final Safety Analysis Report and an assessment of the plant's readiness to ensure that the future operation of the plant will be conducted in accordance with the terms and conditions of its operating license and the NRC's regulations. The outage schedule is currently under review, but the unit is not expected to return to service before the mid-to-late part of the second quarter of 1996. Total replacement-power costs attributable to the Millstone 1 outage extension for CL&P are expected to be approximately $6 million per month. In addition, operation and maintenance costs to be incurred as a result of the extension are estimated to be approximately $16 million. Outage costs are deferred and amortized through rates. The recovery, or refund, of outage costs is subject to prudence reviews. The composite capacity factor of the five nuclear generating units that NU operates-including the Connecticut Yankee nuclear unit-was 69.9 percent in 1995, compared with 67.5 percent for 1994, and a 1995 national average of 77.6 percent. The 1995 capacity factor was impacted by an extended refueling and maintenance outage for Millstone 2. See the "Notes to Consolidated Financial Statements," Note 10B, for further information on outage deferrals and recoveries. ENVIRONMENTAL MATTERS NU devotes substantial resources to identify and comply with the multitude of environmental requirements it faces. NU has active auditing programs addressing a variety of regulatory requirements, including an environmental auditing program to detect and remedy noncompliance with environmental laws or regulations. CL&P is potentially liable for environmental cleanup costs at a number of sites both inside and outside its service territory. To date, the future estimated environmental remediation liability has not been material with respect to the earnings or financial position of CL&P. At December 31, 1995, CL&P had recorded an environmental reserve amounting to approximately $7 million, the minimum amount required under SFAS 5, "Accounting for Contingencies." These costs could be significantly higher if alternative remedies become necessary. In October 1995, the Connecticut Department of Environmental Protection (CDEP) issued a consent order to CL&P and the Long Island Lighting Company (LILCO) requiring those companies to address leaks from the Long Island cable, which is jointly owned by CL&P and LILCO. CL&P will incur additional costs to meet the requirements of the order and to meet any subsequent CDEP requirements resulting from the studies under the consent order, which cannot be estimated at this time. Management also cannot determine at this time whether long-term future operation of the cable will remain cost effective subsequent to any additional CDEP requirements. NUCLEAR DECOMMISSIONING CL&P's estimated cost to decommission its shares of Millstone 1, 2, and 3 and Seabrook 1 is approximately $815 million in year-end 1995 dollars. These costs are being recognized over the lives of the respective units and a portion is being recovered through rates. The FASB is currently reviewing the accounting for closure and removal costs, including decommissioning and similar costs, for long-lived assets. If current electric-power industry accounting practices for such decommissioning costs were changed, annual provisions for decommissioning would increase and the estimated costs for decommissioning would be recorded as a liability rather than as a component of accumulated depreciation. See the "Notes to Consolidated Financial Statements," Note 3, for further information on nuclear decommissioning, including CL&P's share of costs to decommission the regional nuclear generating units. LIQUIDITY AND CAPITAL RESOURCES Cash provided from operations decreased approximately $11 million in 1995, from 1994, primarily due to higher cash operating expenses, partially offset by higher revenues from retail-rate increases and recoveries. Cash used for financing activities increased approximately $8 million in 1995, from 1994, primarily due to a net decrease in short-term debt, partially offset by lower net reacquisitions and retirements of long-term debt. Cash used for investments decreased approximately $20 million in 1995, from 1994, primarily due to lower construction and nuclear fuel expenditures, partially offset by higher investment in the nuclear decommissioning trusts. In 1995, CL&P applied the bulk of its excess cash to reduce debt and preferred stock levels. Although CL&P's long-term debt levels changed little, its short- term debt levels fell from $179 million at the beginning of 1995 to $52 million at the end of the year. CL&P's preferred stock levels were reduced by approximately $121 million. CL&P has entered into interest-rate-cap and fossil- fuel-swap contracts to reduce a portion of its interest-rate and fuel-price risks. See the "Notes to Consolidated Financial Statements," Note 11, for further information on derivative financial instruments and the "Notes to Consolidated Financial Statements," Notes 6, 7, and 10A, for further information on construction and long-term debt funding requirements. RESULTS OF OPERATIONS OPERATING REVENUES The components of the change in operating revenues for the past two years are provided in the table below. Change In Operating Revenues Increase/(Decrease) 1995 vs. 1994 1994 vs. 1993 - -------------------------------------------------------------------------- (Millions of Dollars) Regulatory decisions $61 $38 Fuel and purchased power cost recoveries 25 (45) Sales volume (5) 40 Wholesale revenues (16) (63) Other revenues (7) (8) ---- ----- Total revenue change $58 $(38) ==== ===== Revenues related to regulatory decisions increased, primarily due to the effects of the July 1994 and 1995 retail-rate increases and higher recoveries for demand-side-management costs. Fuel and purchased-power-cost recoveries increased primarily due to higher energy costs and the recovery of GUAC costs. Wholesale revenues decreased primarily due to capacity sales contracts that expired in 1994. Operating revenues decreased approximately $38 million in 1994, from 1993. Revenues related to regulatory decisions increased, primarily due to the effects of the July 1993 and 1994 retail-rate increases, partially offset by lower recoveries for demand-side-management costs. Fuel and purchased-power-cost recoveries decreased primarily due to lower GUAC recoveries. Sales volume increased as a result of higher retail sales from an improved economy. Retail sales increased 3.4 percent in 1994, from 1993 sales levels. Wholesale revenues decreased primarily due to the expiration in late 1994 and 1993 of some significant capacity sales contracts. FUEL, PURCHASED AND NET INTERCHANGE POWER Fuel, purchased and net interchange power expense increased approximately $40 million in 1995, from 1994, primarily due to higher fossil generation and higher priced outside energy purchases from other utilities in 1995. Fuel, purchased and net interchange power decreased approximately $89 million in 1994, from 1993, primarily due to lower recognition of replacement-power fuel costs in 1994, partially offset by a higher level of outside energy purchases from other utilities in 1994. OTHER OPERATION AND MAINTENANCE EXPENSES Other operation and maintenance expenses, net increased approximately $5 million in 1995, from 1994. Operation expenses increased approximately $19 million, primarily due to higher demand-side-management costs, higher rate recovery of postretirement benefit costs, and higher capacity charges from regional nuclear generating units, partially offset by higher nuclear reserves for excess/obsolete inventory in 1994. Maintenance expenses decreased approximately $14 million, primarily due to lower maintenance costs at the fossil units and fossil reserves for excess/obsolete inventory in 1994. Other operation and maintenance expenses, net decreased approximately $21 million in 1994, from 1993, primarily due to higher costs in 1993 associated with early-retirement programs, lower 1994 payroll and benefit costs, lower fossil-unit costs and lower capacity charges from the regional nuclear generating units, partially offset by higher 1994 costs associated with the operation and maintenance activities of the nuclear units and higher reserves for excess/obsolete inventory at the nuclear and fossil units in 1994. DEPRECIATION EXPENSES Depreciation expenses increased approximately $11 million both in 1995, from 1994, and in 1994, from 1993, primarily as a result of higher plant balances and higher decommissioning levels. AMORTIZATION OF REGULATORY ASSETS, NET Amortization of regulatory assets, net decreased approximately $23 million in 1995, from 1994, primarily due to the higher CL&P cogeneration deferrals in 1995, (approximately $18 million), and the completion, during 1994, of the amortization of a 1993 cogeneration buyout, partially offset by higher 1995 amortization of Millstone 3 and Seabrook 1 phase-in costs. Amortization of regulatory assets, net decreased approximately $35 million in 1994, from 1993, primarily due to the deferral of cogeneration expenses beginning in July 1994 as allowed under the 1993 retail-rate decision and lower 1994 expenses associated with the recovery of Hydro-Quebec support payments, partially offset by higher 1994 amortization of Millstone 3 and Seabrook 1 phase-in costs. FEDERAL AND STATE INCOME TAXES Federal and state income taxes decreased approximately $5 million in 1995, from 1994, primarily due to tax benefits from a favorable tax ruling, partially offset by higher taxable income. Federal and state income taxes increased approximately $46 million in 1994, from 1993, primarily due to higher taxable income. DEFERRED NUCLEAR PLANTS RETURN Deferred nuclear plants return decreased approximately $14 million in 1995, from 1994, and approximately $17 million in 1994, from 1993, primarily because additional Millstone 3 investments were phased into rates. OTHER INCOME, NET Other income, net decreased approximately $4 million in 1995, from 1994, and increased approximately $6 million in 1994, from 1993, primarily due to the 1993 property tax accounting change as ordered in the 1993 CL&P rate decision. The allocation of this change to customers occurred in 1994, and amortization began in 1995. INTEREST CHARGES Although the change in 1995, from 1994, was not significant, interest on long- term debt decreased approximately $14 million in 1994, from 1993, primarily due to lower average interest rates as a result of refinancing activities and lower 1994 debt levels. CUMULATIVE EFFECT OF ACCOUNTING CHANGE The cumulative effect of the accounting change of approximately $48 million in 1993 represents the one-time change in the method of accounting for Connecticut municipal property tax expense recognized in the first quarter of 1993. THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES SELECTED FINANCIAL DATA (A) - ------------------------------------------------------------------------------ 1995 1994 1993 1992 1991 - ------------------------------------------------------------------------------ (Thousands of Dollars) Operating Revenues... $2,386,107 $2,328,052 $2,366,050 $2,316,451 $2,275,737 Operating Income..... 324,026 286,948 241,655 288,088 324,428 Net Income........... 205,216 198,288 191,449(b) 206,714 240,818 Cash Dividends on Common Stock 164,154 159,388 160,365 164,277 172,587 Total Assets......... 6,030,735 6,217,457 6,397,405 5,582,831 5,338,466 Long-Term Debt....... 1,822,018 1,823,690 2,057,280 2,087,936 2,023,268 Preferred Stock Not Subject to Mandatory Redemption.... 116,200 166,200 166,200 231,196 306,195 Preferred Stock Subject to Mandatory Redemption(c) 155,000 230,000 230,000 200,000 141,892 Obligations Under Capital Leases(c) 172,264 175,969 177,418 197,404 208,924 STATEMENTS OF QUARTERLY FINANCIAL DATA (Unaudited) - -------------------------------------------------------------------------------- Quarter Ended(a) -------------------------------------------------- 1995 March 31 June 30 September 30 December 31 - -------------------------------------------------------------------------------- Operating Revenues...... $601,194 $525,147 $638,392 $621,374 ======== ======== ======== ======== Operating Income........ $ 96,191 $ 65,867 $ 88,012 $ 73,956 ======== ======== ======== ======== Net Income.............. $ 65,877 $ 38,089 $ 60,462 $ 40,788 ======== ======== ======== ======== 1994 - -------------------------------------------------------------------------------- Operating Revenues...... $619,815 $551,135 $598,706 $558,396 ======== ======== ======== ======== Operating Income........ $ 90,259 $ 59,289 $ 74,771 $ 62,629 ======== ======== ======== ======== Net Income.............. $ 68,590 $ 39,162 $ 50,191 $ 40,345 ======== ======== ======== ======== (a)Reclassifications of prior data have been made to conform with the current presentation. (b)Includes the cumulative effect of change in accounting for municipal property tax expense, which increased earnings for common shares by $47.7 million. (c)Includes portion due within one year. THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES STATISTICS - ------------------------------------------------------------------------- Gross Electric Average Utility Plant Annual December 31, Use Per Electric (Thousands of kWh Sales Residential Customers Employees Dollars) (Millions) Customer (kWh) (Average) (December 31) - ------------------------------------------------------------------------- 1995 $6,389,190 26,366 8,519 1,094,527 2,270 1994 6,327,967 26,975 8,775 1,086,400 2,587 1993 6,214,401 26,107 8,519 1,078,925 2,676 1992 6,100,682 25,809 8,501 1,075,425 3,028 1991 5,986,271 24,992 8,435 1,069,912 3,364 EX-13.3 18 ANNUAL REPORT OF WMECO EXHIBIT 13.3 1995 Annual Report Western Massachusetts Electric Company Index Contents Page - -------- ---- Balance Sheets....................................................... 2-3 Statements of Income................................................. 4 Statements of Cash Flows............................................. 5 Statements of Common Stockholder's Equity............................ 6 Notes to Financial Statements........................................ 7 Report of Independent Public Accountants............................. 26 Management's Discussion and Analysis of Financial Condition and Results of Operations................................ 27 Selected Financial Data.............................................. 33 Statements of Quarterly Financial Data............................... 33 Statistics........................................................... 34 Preferred Stockholder and Bondholder Information..................... Back Cover WESTERN MASSACHUSETTS ELECTRIC COMPANY BALANCE SHEETS
- ------------------------------------------------------------------------------------ At December 31, 1995 1994 - ------------------------------------------------------------------------------------ (Thousands of Dollars) ASSETS - ------ Utility Plant, at original cost: Electric................................................ $1,234,738 $1,214,326 Less: Accumulated provision for depreciation......... 462,872 425,019 ----------- ----------- 771,866 789,307 Construction work in progress........................... 18,957 19,187 Nuclear fuel, net....................................... 31,574 38,000 ----------- ----------- Total net utility plant............................. 822,397 846,494 ----------- ----------- Other Property and Investments: Nuclear decommissioning trusts, at market............... 69,903 56,123 Investments in regional nuclear generating companies, at equity................................... 14,820 14,927 Other, at cost.......................................... 3,979 3,941 ----------- ----------- 88,702 74,991 ----------- ----------- Current Assets: Cash.................................................... 241 105 Notes receivable from affiliated companies.............. - 8,750 Receivables, less accumulated provision for uncollectible accounts of $2,230,000 in 1995 and $2,032,000 in 1994................................ 42,164 35,427 Accounts receivable from affiliated companies........... 951 1,108 Accrued utility revenues................................ 11,119 15,766 Fuel, materials, and supplies, at average cost.......... 5,114 4,829 Prepayments and other................................... 9,176 9,215 ----------- ----------- 68,765 75,200 ----------- ----------- Deferred Charges: Regulatory assets (Note 1G)........................ 160,986 184,226 Unamortized debt expense................................ 1,496 1,733 Other................................................... - 974 ----------- ----------- 162,482 186,933 ----------- ----------- Total Assets........................................ $1,142,346 $1,183,618 =========== ===========
The accompanying notes are an integral part of these financial statements. WESTERN MASSACHUSETTS ELECTRIC COMPANY BALANCE SHEETS
- ------------------------------------------------------------------------------------ At December 31, 1995 1994 - ------------------------------------------------------------------------------------ (Thousands of Dollars) CAPITALIZATION AND LIABILITIES - ------------------------------ Capitalization: Common stock,$25 par value--authorized and outstanding 1,072,471 shares in 1995 and 1994........ $ 26,812 $ 26,812 Capital surplus, paid in................................ 150,182 149,683 Retained earnings....................................... 115,296 111,586 ----------- ----------- Total common stockholder's equity.............. 292,290 288,081 Cumulative preferred stock-- $100 par value--authorized 1,000,000 shares; outstanding 200,000 shares in 1995 and 1994; $25 par value--authorized 3,600,000 shares; outstanding 2,300,000 shares in 1995 2,927,000 shares in 1994 Preferred stock not subject to mandatory redemption..... 53,500 68,500 Preferred stock subject to mandatory redemption......... 22,500 24,000 Long-term debt.......................................... 347,470 345,669 ----------- ----------- Total capitalization........................... 715,760 726,250 ----------- ----------- Obligations Under Capital Leases.......................... 20,855 23,852 ----------- ----------- Current Liabilities: Notes payable to affiliated company..................... 24,050 - Long-term debt and preferred stock--current portion................................................ 1,500 34,975 Obligations under capital leases--current portion................................................ 15,156 12,945 Accounts payable........................................ 14,475 20,396 Accounts payable to affiliated companies................ 11,604 17,352 Accrued taxes........................................... 1,686 5,160 Accrued interest........................................ 5,670 6,702 Other................................................... 7,768 7,584 ----------- ----------- 81,909 105,114 < 1995 Annual Report Western Massachusetts Electric Company Index Contents Page - -------- ---- Balance Sheets....................................................... 2-3 Statements of Income................................................. 4 Statements of Cash Flows............................................. 5 Statements of Common Stockholder's Equity............................ 6 Notes to Financial Statements........................................ 7 Report of Independent Public Accountants............................. 26 Management's Discussion and Analysis of Financial Condition and Results of Operations................................ 27 Selected Financial Data.............................................. 33 Statements of Quarterly Financial Data............................... 33 Statistics........................................................... 34 Preferred Stockholder and Bondholder Information..................... Back Cover WESTERN MASSACHUSETTS ELECTRIC COMPANY BALANCE SHEETS
- ------------------------------------------------------------------------------------ At December 31, 1995 1994 - ------------------------------------------------------------------------------------ (Thousands of Dollars) ASSETS - ------ Utility Plant, at original cost: Electric................................................ $1,234,738 $1,214,326 Less: Accumulated provision for depreciation......... 462,872 425,019 ----------- ----------- 771,866 789,307 Construction work in progress........................... 18,957 19,187 Nuclear fuel, net....................................... 31,574 38,000 ----------- ----------- Total net utility plant............................. 822,397 846,494 ----------- ----------- Other Property and Investments: Nuclear decommissioning trusts, at market............... 69,903 56,123 Investments in regional nuclear generating companies, at equity................................... 14,820 14,927 Other, at cost.......................................... 3,979 3,941 ----------- ----------- 88,702 74,991 ----------- ----------- Current Assets: Cash.................................................... 241 105 Notes receivable from affiliated companies.............. - 8,750 Receivables, less accumulated provision for uncollectible accounts of $2,230,000 in 1995 and $2,032,000 in 1994................................ 42,164 35,427 Accounts receivable from affiliated companies........... 951 1,108 Accrued utility revenues................................ 11,119 15,766 Fuel, materials, and supplies, at average cost.......... 5,114 4,829 Prepayments and other................................... 9,176 9,215 ----------- ----------- 68,765 75,200 ----------- ----------- Deferred Charges: Regulatory assets (Note 1G)........................ 160,986 184,226 Unamortized debt expense................................ 1,496 1,733 Other................................................... - 974 ----------- ----------- 162,482 186,933 ----------- ----------- Total Assets........................................ $1,142,346 $1,183,618 =========== ===========
The accompanying notes are an integral part of these financial statements. WESTERN MASSACHUSETTS ELECTRIC COMPANY BALANCE SHEETS
- ------------------------------------------------------------------------------------ At December 31, 1995 1994 - ------------------------------------------------------------------------------------ (Thousands of Dollars) CAPITALIZATION AND LIABILITIES - ------------------------------ Capitalization: Common stock,$25 par value--authorized and outstanding 1,072,471 shares in 1995 and 1994........ $ 26,812 $ 26,812 Capital surplus, paid in................................ 150,182 149,683 Retained earnings....................................... 115,296 111,586 ----------- ----------- Total common stockholder's equity.............. 292,290 288,081 Cumulative preferred stock-- $100 par value--authorized 1,000,000 shares; outstanding 200,000 shares in 1995 and 1994; $25 par value--authorized 3,600,000 shares; outstanding 2,300,000 shares in 1995 2,927,000 shares in 1994 Preferred stock not subject to mandatory redemption..... 53,500 68,500 Preferred stock subject to mandatory redemption......... 22,500 24,000 Long-term debt.......................................... 347,470 345,669 ----------- ----------- Total capitalization........................... 715,760 726,250 ----------- ----------- Obligations Under Capital Leases.......................... 20,855 23,852 ----------- ----------- Current Liabilities: Notes payable to affiliated company..................... 24,050 - Long-term debt and preferred stock--current portion................................................ 1,500 34,975 Obligations under capital leases--current portion................................................ 15,156 12,945 Accounts payable........................................ 14,475 20,396 Accounts payable to affiliated companies................ 11,604 17,352 Accrued taxes........................................... 1,686 5,160 Accrued interest........................................ 5,670 6,702 Other................................................... 7,768 7,584 ----------- ----------- 81,909 105,114 ----------- ----------- Deferred Credits: Accumulated deferred income taxes (Note 1H)........ 259,595 253,821 Accumulated deferred investment tax credits............. 26,302 27,822 Deferred contractual obligation......................... 18,814 28,572 Other................................................... 19,111 18,187 ----------- ----------- 323,822 328,402 ----------- ----------- Commitments and Contingencies (Note 10) Total Capitalization and Liabilities........... $1,142,346 $1,183,618 =========== ===========
The accompanying notes are an integral part of these financial statements. WESTERN MASSACHUSETTS ELECTRIC COMPANY STATEMENTS OF INCOME
- ------------------------------------------------------------------------------ For the Years Ended December 31, 1995 1994 1993 - ------------------------------------------------------------------------------ (Thousands of Dollars) Operating Revenues.............................. $420,208 $421,477 $415,055 --------- --------- --------- Operating Expenses: Operation -- Fuel, purchased and net interchange power.. 86,738 67,365 67,781 Other...................................... 142,774 130,683 142,273 Maintenance................................... 37,447 35,430 34,259 Depreciation.................................. 37,924 36,885 35,751 Amortization of regulatory assets............. 19,562 29,118 29,700 Federal and state income taxes (Note 8)... 14,060 32,653 27,892 Taxes other than income taxes................. 18,639 18,403 17,051 --------- --------- --------- Total operating expenses................ 357,144 350,537 354,707 --------- --------- --------- Operating Income................................ 63,064 70,940 60,348 --------- --------- --------- Other Income: Equity in earnings of regional nuclear generating companies........................ 1,771 2,031 1,680 Other, net.................................... 1,232 3,687 4,405 Income taxes.................................. 262 (71) 23 --------- --------- --------- Other income, net....................... 3,265 5,647 6,108 --------- --------- --------- Income before interest charges.......... 66,329 76,587 66,456 --------- --------- --------- Interest Charges: Interest on long-term debt.................... 26,840 27,678 29,979 Other interest................................ 356 (548) (195) --------- --------- --------- Interest charges, net................... 27,196 27,130 29,784 --------- --------- --------- Income before cumulative effect of accounting change............................. 39,133 49,457 36,672 Cumulative effect of accounting change (Note 1A)................................ - - 3,922 --------- --------- --------- Net Income...................................... $ 39,133 $ 49,457 $ 40,594 ========= ========= =========
The accompanying notes are an integral part of these financial statements. WESTERN MASSACHUSETTS ELECTRIC COMPANY STATEMENTS OF CASH FLOWS
- -------------------------------------------------------------------------------------------------- For the Years Ended December 31, 1995 1994 1993 - -------------------------------------------------------------------------------------------------- (Thousands of Dollars) Operating Activities: Net Income.................................................. $ 39,133 $ 49,457 $ 40,594 Adjustments to reconcile to net cash from operating activities: Depreciation.............................................. 37,924 36,885 35,751 Deferred income taxes and investment tax credits, net..... 3,418 10,256 918 Deferred Millstone 3 return............................... (190) (1,331) (2,516) Amortization of deferred Millstone 3 return............... 7,336 14,758 14,768 Recoverable energy costs, net of amortization............. (4,715) (8,622) 7,316 Other sources of cash..................................... 29,409 27,553 26,765 Other uses of cash........................................ (8,039) (23,701) (2,698) Changes in working capital: Receivables and accrued utility revenues.................. (1,933) 6,470 (3,728) Fuel, materials, and supplies............................. (285) 2,228 1,944 Accounts payable.......................................... (11,669) 8,239 (2,078) Accrued taxes............................................. (3,474) (1,862) (3,248) Other working capital (excludes cash)..................... 1,256 (2,991) 2,433 ----------- ----------- ----------- Net cash flows from operating activities...................... 88,171 117,339 116,221 ----------- ----------- ----------- Financing Activities: Issuance of long-term debt.................................. - 90,000 113,800 Net increase (decrease) in short-term debt.................. 24,050 (6,000) (35,500) Reacquisitions and retirements of long-term debt............ (34,550) (104,169) (114,270) Reacquisitions and retirements of preferred stock........... (15,675) (7,325) (1,500) Cash dividends on preferred stock........................... (4,944) (5,897) (5,259) Cash dividends on common stock.............................. (30,223) (29,514) (28,785) ----------- ----------- ----------- Net cash flows used for financing activities.................. (61,342) (62,905) (71,514) ----------- ----------- ----------- Investment Activities: Investment in plant: Electric utility plant.................................... (27,084) (32,680) (34,592) Nuclear fuel.............................................. 75 (4,928) (2,926) ----------- ----------- ----------- Net cash flows used for investments in plant................ (27,009) (37,608) (37,518) NU System Money Pool........................................ 8,750 (8,750) - Other investment activities, net............................ (8,434) (8,156) (7,169) ----------- ----------- ----------- Net cash flows used for investments........................... (26,693) (54,514) (44,687) ----------- ----------- ----------- Net Increase (Decrease) In Cash For The Period................ 136 (80) 20 Cash - beginning of period.................................... 105 185 165 ----------- ----------- ----------- Cash - end of period.......................................... $ 241 $ 105 $ 185 =========== =========== =========== Supplemental Cash Flow Information: Cash paid during the year for: Interest, net of amounts capitalized........................ $ 25,551 $ 25,174 $ 27,277 =========== =========== =========== Income taxes................................................ $ 14,385 $ 30,040 $ 21,200 =========== =========== =========== Increase in obligations: Niantic Bay Fuel Trust...................................... $ 7,851 $ 12,237 $ 9,369 =========== =========== =========== /Table> The accompanying notes are an integral part of these financial statements. WESTERN MASSACHUSETTS ELECTRIC COMPANY STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
- --------------------------------------------------------------------------------------- Capital Retained Common Surplus, Earnings Stock Paid In (a) Total - --------------------------------------------------------------------------------------- (Thousands of Dollars) Balance at January 1, 1993............... $26,812 $149,026 $ 91,077 $266,915 Net income for 1993.................. 40,594 40,594 Cash dividends on preferred stock.............................. (5,259) (5,259) Cash dividends on common stock....... (28,785) (28,785) Capital stock expenses, net.......... 293 293 -------- --------- --------- --------- Balance at December 31, 1993............. 26,812 149,319 97,627 273,758 Net income for 1994.................. 49,457 49,457 Cash dividends on preferred stock.............................. (5,897) (5,897) Cash dividends on common stock....... (29,514) (29,514) Loss on the retirement of preferred stock.............................. (87) (87) Capital stock expenses, net.......... 364 364 -------- --------- --------- --------- Balance at December 31, 1994............. 26,812 149,683 111,586 288,081 Net income for 1995.................. 39,133 39,133 Cash dividends on preferred stock.............................. (4,944) (4,944) Cash dividends on common stock....... (30,223) (30,223) Loss on retirement of preferred stock.............................. (256) (256) Capital stock expenses, net.......... 499 499 -------- --------- --------- --------- Balance at December 31, 1995............. $26,812 $150,182 $115,296 $292,290 ======== ========= ========= =========
(a) The company has dividend restrictions imposed by its long-term debt agreements. At December 31, 1995, these restrictions totaled approximately $21.5 million. The accompanying notes are an integral part of these financial statements. Western Massachusetts Electric Company NOTES TO FINANCIAL STATEMENTS - ---------------------------------------------------------------------- 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES A. PRESENTATION Western Massachusetts Electric Company (WMECO or the company), The Connecticut Light and Power Company (CL&P), Holyoke Water Power Company (HWP), Public Service Company of New Hampshire (PSNH), and North Atlantic Energy Corporation (NAEC) are the operating subsidiaries comprising the Northeast Utilities system (the system) and are wholly owned by Northeast Utilities (NU). The system furnishes retail electric service in Connecticut, New Hampshire, and western Massachusetts through CL&P, PSNH, WMECO, and HWP. A fifth subsidiary, NAEC, sells all of its capacity to PSNH. In addition to its retail service, the system furnishes firm and other wholesale electric services to various municipalities and other utilities. The system serves about 30 percent of New England's electric needs and is one of the 20 largest electric utility systems in the country as measured by revenues. Other wholly owned subsidiaries of NU provide substantial support services to the system. Northeast Utilities Service Company (NUSCO) supplies centralized accounting, administrative, data processing, engineering, financial, legal, operational, planning, purchasing, and other services to the system companies. Northeast Nuclear Energy Company (NNECO) acts as agent for system companies in operating the Millstone nuclear generating facilities. All transactions among affiliated companies are on a recovery of cost basis which may include amounts representing a return on equity, and are subject to approval by various federal and state regulatory agencies. 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 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. Certain reclassifications of prior years' data have been made to conform with the current year's presentation. Property Taxes: WMECO changed its method of accounting for municipal property tax expense for its respective Connecticut properties during 1993. This one-time change increased 1993 net income by approximately $3.9 million. B. FUTURE ACCOUNTING STANDARD The Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of, in March 1995. SFAS 121 became effective January 1, 1996, and establishes accounting standards for evaluating and recording asset impairment. SFAS 121 requires the evaluation of long-lived assets for impairment when certain events occur or conditions exist that indicate the carrying amounts of assets may not be recoverable. Refer to Note 1G, "Regulatory Accounting," for further information on the regulatory impacts of the company's adoption of SFAS 121. C. INVESTMENTS AND JOINTLY OWNED ELECTRIC UTILITY PLANT Regional Nuclear Generating Companies: WMECO owns common stock of four regional nuclear generating companies (Yankee companies). The Yankee companies, with the company's ownership interests, are: Connecticut Yankee Atomic Power Company (CY) ........ 9.5% Yankee Atomic Electric Company (YAEC) ............... 7.0 Maine Yankee Atomic Power Company (MY) .............. 3.0 Vermont Yankee Nuclear Power Corporation (VY) ....... 2.5 WMECO's investments in the Yankee companies are accounted for on the equity basis due to the company's ability to exercise significant influence over their operating and financial policies. The electricity produced by the facilities that are operating is committed substantially on the basis of ownership interests and is billed pursuant to contractual agreements. Under ownership agreements with the Yankee companies, WMECO may be asked to provide direct or indirect financial support for one or more of the companies. For more information on these agreements, see Note 10E, "Commitments and Contingencies - Long-Term Contractual Arrangements." YAEC's nuclear power plant was shut down permanently on February 26, 1992. For more information on the Yankee companies, see Note 3, "Nuclear Decommissioning." Millstone 1: WMECO has a 19 percent joint-ownership interest in Millstone 1, a 660-megawatt (MW) nuclear generating unit. As of December 31, 1995 and 1994, plant-in-service included approximately $87.4 million and $87.0 million, respectively, and the accumulated provision for depreciation included approximately $34.5 million and $31.4 million, respectively, for WMECO's share of Millstone 1. WMECO's share of Millstone 1 expenses is included in the corresponding operating expenses on the accompanying Statements of Income. Millstone 2: WMECO has a 19 percent joint-ownership interest in Millstone 2, an 870-MW nuclear generating unit. As of December 31, 1995 and 1994, plant-in-service included approximately $160.0 million and $159.2 million, respectively, and the accumulated provision for depreciation included approximately $45.8 million and $40.4 million, respectively, for WMECO's share of Millstone 2. WMECO's share of Millstone 2 expenses is included in the corresponding operating expenses on the accompanying Statements of Income. Millstone 3: WMECO has a 12.24 percent joint-ownership interest in Millstone 3, a 1,154-MW nuclear generating unit. As of December 31, 1995 and 1994, plant-in-service included approximately $377.7 million and $376.1 million, respectively, and the accumulated provision for depreciation included approximately $90.6 million and $83.2 million, respectively, for WMECO's share of Millstone 3. WMECO's share of Millstone 3 expenses is included in the corresponding operating expenses on the accompanying Statements of Income. D. DEPRECIATION The provision for depreciation is calculated using the straight-line method based on estimated remaining lives of depreciable utility plant-in-service, adjusted for salvage value and removal costs, as approved by the appropriate regulatory agency. Except for major facilities, depreciation factors are applied to the average plant-in-service during the period. Major facilities are depreciated from the time they are placed in service. When plant is retired from service, the original cost of plant, including costs of removal, less salvage, is charged to the accumulated provision for depreciation. The depreciation rates for the several classes of electric plant-in-service are equivalent to a composite rate of 3.1 percent in 1995, 1994, and 1993. See Note 3, "Nuclear Decommissioning," for information on nuclear plant decommissioning. E. PUBLIC UTILITY REGULATION NU is registered with the Securities and Exchange Commission (SEC) as a holding company under the Public Utility Holding Company Act of 1935 (1935 Act), and it and its subsidiaries, including the company, are subject to the provisions of the 1935 Act. Arrangements among the system companies, outside agencies, and other utilities covering inter- connections, interchange of electric power, and sales of utility property are subject to regulation by the Federal Energy Regulatory Commission (FERC) and/or the SEC. The company is subject to further regulation for rates, accounting, and other matters by the FERC and/or the Massachusetts Department of Public Utilities (DPU). F. REVENUES Other than revenues under fixed-rate agreements negotiated with certain wholesale, industrial, and commercial customers, utility revenues are based on authorized rates applied to each customer's use of electricity. In general, rates can be changed only through a formal proceeding before the appropriate regulatory commission. At the end of each accounting period, WMECO accrues an estimate for the amount of energy delivered but unbilled. G. REGULATORY ACCOUNTING The accounting policies of WMECO and the accompanying financial statements conform to generally accepted accounting principles applicable to rate-regulated enterprises and reflect the effects of the ratemaking process in accordance with SFAS 71, Accounting for the Effects of Certain Types of Regulation. Assuming a cost-of-service based regulatory structure, regulators may permit incurred costs, normally treated as expenses, to be deferred and recovered in future revenues. Through their actions, regulators may also reduce or eliminate the value of an asset, or create a liability. If any portion of the company's operations were no longer subject to the provisions of SFAS 71, as a result of a change in the cost-of-service based regulatory structure or the effects of competition, the company would be required to write off related regulatory assets and liabilities. The company would also be required to determine any impairment to other assets and write down these assets to fair value. Based on current regulation and recent regulatory decisions, and initiatives relating to competition in the system's market, the company believes that its use of regulatory accounting remains appropriate. SFAS 121 requires that any assets, including regulatory assets, which are no longer probable of recovery through future revenues, be revalued based on estimated future cash flows. If the revaluation is less than the book value of the asset, an impairment loss would be charged to earnings. As noted above, based on the current regulatory environment in the company's service area, it is not expected that SFAS 121 will have a material impact on the company's financial position or results of operations upon adoption. This conclusion may change in the future as competitive factors influence wholesale and retail pricing in the electric utility industry, or if the cost-of-service based regulatory structure were to change. For further information on the company's regulatory environment, refer to Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A). The components of regulatory assets are as follows: At December 31, 1995 1994 ----------------------------------------------------------------------- (Thousands of Dollars) Income taxes, net (Note 1H) ..................... $ 87,829 $ 86,357 Unrecovered contractual obligation (Note 3) ... 18,814 28,572 Amortizable property investment - Millstone 3 ... 5,600 16,800 Recoverable energy costs (Note 1I) .............. 10,974 8,324 Deferred costs - Millstone 3 .................... - 7,836 Other ........................................... 37,769 36,337 --------- --------- $ 160,986 $ 184,226 ========= ========= H. INCOME TAXES The tax effect of temporary differences (differences between the periods in which transactions affect income in the financial statements and the periods in which they affect the determination of income subject to tax) is accounted for in accordance with the ratemaking treatment of the applicable regulatory commissions. The adoption of SFAS 109, Accounting for Income Taxes, in 1993 increased the company's net deferred tax obligation. As it is probable that the increase in deferred tax liabilities will be recovered from customers through rates, WMECO established a regulatory asset. See Note 8, "Income Tax Expense" for the components of income tax expense. The tax effect of temporary differences, including timing differences accrued under previously approved accounting standards, which give rise to the accumulated deferred tax obligation are as follows: At December 31, 1995 1994 -------------------------------------------------------------------- (Thousands of Dollars) Accelerated depreciation and other plant-related differences ........... $222,520 $214,485 Regulatory assets - income tax gross up 34,540 34,084 Other ................................. 2,535 5,252 ---------- ---------- $259,595 $253,821 ======== ======== I. RECOVERABLE ENERGY COSTS Under the Energy Policy Act of 1992 (Energy Act), WMECO is assessed for its proportionate share of the costs of decontaminating and decommissioning uranium enrichment plants owned by the United States Department of Energy (D&D assessment). The Energy Act requires that regulators treat D&D assessments as a reasonable and necessary current cost of fuel, to be fully recovered in rates, like any other fuel cost. WMECO is currently recovering these costs through rates. As of December 31, 1995, the company's total D&D deferrals were approximately $11.0 million. J. SPENT NUCLEAR FUEL DISPOSAL COSTS Under the Nuclear Waste Policy Act of 1982, WMECO must pay the United States Department of Energy (DOE) for the disposal of spent nuclear fuel and high-level radioactive waste. Fees for nuclear fuel burned on or after April 7, 1983 are billed currently to customers and paid to the DOE on a quarterly basis. For nuclear fuel used to generate electricity prior to April 7, 1983 (prior-period fuel), payment may be made anytime prior to the first delivery of spent fuel to the DOE, which may be as early as 1998. Until such payment is made, the outstanding balance will continue to accrue interest at the three-month Treasury Bill Yield Rate. At December 31, 1995, fees due to the DOE for the disposal of prior- period fuel were approximately $35.2 million, including interest costs of $19.6 million. As of December 31, 1995, all fees have been collected through rates. K. DERIVATIVE FINANCIAL INSTRUMENTS The company utilizes an interest-rate cap to manage well-defined interest-rate risk. Premiums paid for purchased interest-rate cap agreements are amortized to interest expense over the terms of the cap. Unamortized premiums are included in deferred charges. Amounts receivable under cap agreements are accrued and offset against interest expense. Any material unrealized gains or losses on interest-rate caps will be deferred until realized. For further information on derivatives, see Note 11, "Derivative Financial Instruments." 2. LEASES WMECO and CL&P finance up to $475 million of nuclear fuel for Millstone 1 and 2 and their respective shares of the nuclear fuel for Millstone 3 under the Niantic Bay Fuel Trust (NBFT) capital lease agreement. WMECO and CL&P make quarterly lease payments for the cost of nuclear fuel consumed in the reactors (based on a units-of-production method at rates which reflect estimated kilowatt-hours of energy provided) plus financing costs associated with the fuel in the reactors. Upon permanent discharge from the reactors, ownership of the nuclear fuel transfers to WMECO and CL&P. WMECO has also entered into lease agreements for the use of data processing and office equipment, vehicles, nuclear control room simulators, and office space. The provisions of these lease agreements generally provide for renewal options. The following rental payments have been charged to operating expense: Year Capital Leases Operating Leases ---- -------------- ---------------- 1995...................... $12,553,000 $6,398,000 1994...................... 13,594,000 6,485,000 1993...................... 17,280,000 6,367,000 Interest included in capital lease rental payments was $1,954,000 in 1995, $1,845,000 in 1994, and $2,090,000 in 1993. Substantially all of the capital lease rental payments were made pursuant to the nuclear fuel lease agreement. Future minimum lease payments under the nuclear fuel capital lease cannot be reasonably estimated on an annual basis due to variations in the usage of nuclear fuel. Future minimum rental payments, excluding annual nuclear fuel lease payments and executory costs, such as property taxes, state use taxes, insurance, and maintenance, under long-term noncancelable leases, as of December 31, 1995 are: Year Operating Leases ---- ---------------- (Thousands of Dollars) 1996 ............................ $ 4,600 1997 ............................ 4,300 1998 ............................ 3,300 1999 ............................ 3,100 2000 ............................ 2,900 After 2000 ...................... 12,200 ------- Future minimum lease payments ... $30,400 ======= 3. NUCLEAR DECOMMISSIONING WMECO's nuclear power plants have service lives that are expected to end during the years 2010 through 2025. Upon retirement, these units must be decommissioned. The company's 1992 decommissioning study concluded that complete and immediate dismantlement at retirement continues to be the most viable and economic method of decommissioning the three Millstone units. Decommissioning studies are reviewed and updated periodically to reflect changes in decommissioning requirements, costs, technology, and inflation. The estimated cost of decommissioning WMECO's ownership share of Millstone 1, 2, and 3, in year-end 1995 dollars, is $70.4 million, $62.3 million, and $53.7 million, respectively. These estimated costs assumed levelized collections and after-tax earnings on the Millstone decommissioning funds of 6.5 percent. The Millstone units decommissioning costs will be increased annually by escalation rates. Nuclear decommissioning costs are accrued over the expected service life of the units and are included in depreciation expense on the Statements of Income. Nuclear decommissioning costs amounted to $5.0 million in 1995, $4.8 million in 1994, and $4.6 million in 1993. Nuclear decommissioning, as a cost of removal, is included in the accumulated provision for depreciation on the Balance Sheets. At December 31, 1995, the balance in the accumulated reserve for decommissioning amounted to $69.9 million. See "Nuclear Decommissioning" in the MD&A for a discussion of changes being considered by the FASB relating to accounting for closure and removal of long-lived assets (including nuclear decommissioning). WMECO has established external decommissioning trusts through a trustee for its portion of the costs of decommissioning Millstone 1, 2, and 3. As of December 31, 1995, WMECO has collected, through rates, $47.4 million toward the future decommissioning costs of its share of the Millstone units, all of which has been transferred to external decommissioning trusts. Earnings on the decommissioning trusts increase the decommissioning trust balance and the accumulated reserve for decommissioning. Unrealized gains and losses associated with the decommissioning trusts also impact the balance of the trusts and the accumulated reserve for decommissioning. Changes in requirements or technology, the timing of funding or dismantling, or adoption of a decommissioning method other than immediate dismantlement would change decommissioning cost estimates and the amounts required to be recovered. WMECO attempts to recover sufficient amounts through its allowed rates to cover its expected decommissioning costs. Only the portion of currently estimated total decommissioning costs that has been accepted by regulatory agencies is reflected in rates of the company. Based on present estimates and assuming its nuclear units operate to the end of their respective license periods, the company expects that the decommissioning trusts will be substantially funded when the units are retired from service. WMECO, along with other New England utilities, has equity investments in the four Yankee companies. Each Yankee company owns a single nuclear generating unit with service lives that are expected to end during the years 2007 through 2012. The estimated cost, in year-end 1995 dollars, of decommissioning WMECO's ownership share of units owned and operated by CY, MY, and VY is $36.6 million, $10.6 million, and $8.7 million, respectively. Under the terms of the contracts with the Yankee companies, the shareholders-sponsors are responsible for their proportionate share of the operating costs of each unit, including decommissioning. The nuclear decommissioning costs of the Yankee companies are included as part of the cost of power purchased by WMECO. YAEC is in the process of dismantling its nuclear facility. Accelerated decommissioning of that unit has been delayed because of litigation over the Nuclear Regulatory Commission's (NRC) approval of YAEC's decommissioning plan. Effective November 1995, YAEC began billing its sponsors, including WMECO, amounts based on a revised estimate approved by the FERC that assumes decommissioning of the plant by the year 2000. This revised decommissioning estimate was based on access to the Barnwell, South Carolina low-level radioactive waste facility, changes in assumptions about earnings in decommissioning trust investments, and changes in other decommissioning cost assumptions. At December 31, 1995, the estimated remaining costs, including decommissioning, amounted to $268.8 million of which WMECO's share was approximately $18.8 million. Management expects that WMECO will continue to be allowed to recover such FERC-approved costs from its customers. Accordingly, WMECO has recognized these costs as regulatory assets, with corresponding obligations, on its Balance Sheets. 4. SHORT-TERM DEBT NU, CL&P, WMECO, HWP, NNECO, and The Rocky River Realty Company (RRR) have established a revolving-credit facility with a group of 15 banks. Under this facility, the participating companies may borrow up to an aggregate of $343 million. Individual borrowing limits as of January 1, 1996 were $150 million for NU parent, $325 million for CL&P, $60 million for WMECO, $5 million for HWP, $50 million for NNECO, and $22 million for RRR. The system companies may borrow funds on a short-term revolving basis using either fixed-rate loans or standby loans. Fixed rates are set using competitive bidding. Standby-loan rates are based upon several alternative variable rates. The system companies are obligated to pay a facility fee of 0.15 percent per annum of each bank's total commitment under the three-year portion of the facility, representing 75 percent of the total facility, plus 0.10 percent per annum of each bank's total commitment under the 364-day portion of the facility, representing 25 percent of the total facility. At December 31, 1995 and 1994, there were $42.5 million and $30 million of borrowings, respectively, under the facility, all of which had been borrowed by other system companies. Certain subsidiaries of NU, including WMECO, are members of the Northeast Utilities System Money Pool (Pool). The Pool provides a more efficient use of the cash resources of the system, and reduces outside short-term borrowings. NUSCO administers the Pool as agent for the member companies. Short-term borrowing needs of the member companies are first met with available funds of other member companies, including funds borrowed by NU parent. NU parent may lend to the Pool but may not borrow. Funds may be withdrawn from or repaid to the Pool at any time without prior notice. Investing and borrowing subsidiaries receive or pay interest based on the average daily Federal Funds rate. However, borrowings based on loans from NU parent bear interest at NU parent's cost and must be repaid based upon the terms of NU parent's original borrowing. At December 31, 1995, WMECO had $24.1 million of borrowings outstanding from the Pool. At December 31, 1994, WMECO had no borrowings from the Pool. The interest rate on borrowings from the Pool at December 31, 1995 was 4.7 percent. Maturities of WMECO's short-term debt obligations are for periods of three months or less. The amount of short-term borrowings that may be incurred by WMECO is subject to periodic approval by the SEC under the 1935 Act. In addition, the charter of WMECO contains provisions restricting the amount of short-term borrowings. Under the SEC and/or charter restrictions, the company was authorized, as of January 1, 1995, to incur short-term borrowings up to a maximum of $60 million. 5. PREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION Details of preferred stock not subject to mandatory redemptions are: December 31, Shares 1995 Outstanding Redemption December 31, December 31, ------------------------- Description Price 1995 1995 1994 1993 ------------------------------------------------------------------------ (Thousands of Dollars) 7.72% Series B of 1971 $103.51 200,000 $20,000 $20,000 $20,000 1988 Adjustable Rate DARTS .... 25.00 1,340,000 33,500 48,500 53,500 ------- ------- ------- Total preferred stock not subject to mandatory redemption .... $53,500 $68,500 $73,500 ======= ======= ======= All or any part of each outstanding series of preferred stock may be redeemed by the company at any time at established redemption prices plus accrued dividends to the date of redemption. 6. PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION Details of preferred stock subject to mandatory redemption are: December 31 Shares 1995 Outstanding Redemption December 31, December 31, ------------------------- Description Price* 1995 1995 1994 1993 ------------------------------------------------------------------------ (Thousands of Dollars) 7.60% Series of 1987 $25.89 960,000 $24,000 $24,675 $27,000 Less preferred stock to be redeemed within one year, net of reacquired stock .......... 60,000 1,500 675 1,500 ------- ------- ------ Total preferred stock subject to mandatory redemption ..... $22,500 $24,000 $25,500 ======= ======= ======= *Redemption price reduces in future years. The minimum sinking-fund provisions of the 1987 Series subject to mandatory redemption at December 31, 1995, for the years 1996 through 2000, are $1.5 million per year. In case of default on sinking-fund payments, no payments may be made on any junior stock by way of dividends or otherwise (other than in shares of junior stock) so long as the default continues. If the company is in arrears in the payment of dividends on any outstanding shares of preferred stock, the company would be prohibited from redemption or purchase of less than all of the preferred stock outstanding. All or part of the 7.60% Series of 1987 may be redeemed by the company at any time at an established redemption price plus accrued dividends to the date of redemption subject to certain refunding limitations. 7. LONG-TERM DEBT Details of long-term debt outstanding are: December 31, -------------------- 1995 1994 ----------------------------------------------------------------- (Thousands of Dollars) First Mortgage Bonds: 9 1/4% Series U, due 1995 $ - $ 34,300 5 3/4% Series F, due 1997 14,700 14,850 6 3/4% Series G, due 1998 9,800 9,900 6 1/4% Series X, due 1999 40,000 40,000 6 7/8% Series W, due 2000 60,000 60,000 7 3/4% Series V, due 2002 85,000 85,000 7 3/4% Series Y, due 2024 50,000 50,000 ------ ------ Total First Mortgage Bonds 259,500 294,050 Pollution Control Notes: Tax Exempt Series A, due 2028 53,800 53,800 Fees and interest due for spent fuel disposal costs (Note 1J) 35,180 33,239 Less: Amounts due within one year - 34,300 Unamortized premium and discount, net (1,010) (1,120) -------- ---------- Long-term debt, net $347,470 $345,669 ======== ======== Long-term debt maturities and cash sinking-fund requirements on debt outstanding at December 31, 1995 for the years 1996 through 2000 are approximately $0.0, $14.7 million, $9.8 million, $40.0 million and $60.0 million, respectively. In addition, there are annual one-percent sinking- and improvement-fund requirements, currently amounting to $2.6 million for 1996 and 1997, $2.4 million for 1998 and 1999, and $2.0 million for 2000. Such sinking- and improvement-fund requirements may be satisfied by the deposit of cash or bonds by certification of property additions. All or any part of each outstanding series of first mortgage bonds may be redeemed by the company at any time at established redemption prices plus accrued interest to the date of redemption, except certain series which are subject to certain refunding limitations during their respective initial five-year redemption periods. Essentially all of the company's utility plant is subject to the lien of its first mortgage bond indenture. As of December 31, 1995 and 1994, the company has secured $53.8 million of pollution control notes with second mortgage liens on Millstone 1, junior to the liens of its first mortgage bond indenture. The average effective interest rate on the variable-rate pollution control notes was 3.7 percent for 1995 and 2.7 percent for 1994. 8. INCOME TAX EXPENSE The components of the federal and state income tax provisions are: For the Years Ended December 31, 1995 1994 1993 --------------------------------------------------------------- (Thousands of Dollars) Current income taxes: Federal..................... $ 7,419 $18,358 $22,239 State....................... 2,961 4,110 4,712 -------- ------- -------- Total current............. 10,380 22,468 26,951 ------- ------- ------- Deferred income taxes, net: Federal..................... 4,130 9,697 1,683 State...................... 1,003 2,267 664 -------- --------- --------- Total deferred............ 5,133 11,964 2,347 -------- ------- -------- Investment tax credits, net... (1,715) (1,708) (1,429) -------- -------- -------- Total income tax expense...... $13,798 $32,724 $27,869 ======= ======= ======= The components of total income tax expense are classified as follows: Income taxes charged to operating expenses......... $14,060 $32,653 $27,892 Other income taxes ........... (262) 71 (23) ------- ------- ------- Total income tax expense...... $13,798 $32,724 $27,869 ======= ======= ======= Deferred income taxes are comprised of the tax effects of temporary differences as follows: For the Years Ended December 31, 1995 1994 1993 - -------------------------------------------------------------------- (Thousands of Dollars) Depreciation, leased nuclear fuel, settlement credits and disposal costs $9,066 $7,016 $6,852 Energy adjustment clause............. (1,549) 3,598 (2,627) Nuclear plant deferrals.............. 2,468 (1,802) (1,778) Bond redemptions..................... (572) 1,535 1,200 Other................................ (4,280) 1,617 (1,300) ------ ------ -------- Deferred income taxes, net........... $5,133 $11,964 $ 2,347 ====== ======= ======= A reconciliation between income tax expense and the expected tax expense at the applicable statutory rate is as follows: For the Years Ended December 31, 1995 1994 1993 - -------------------------------------------------------------------- (Thousands of Dollars) Expected federal income tax at 35 percent of pretaxincome for................. $18,526 $28,763 $23,962 Tax effect of differences: Depreciation....................... 2,173 1,740 1,784 Amortization of deferred Millstone 3 return............... 1,665 3,347 3,341 Investment tax credit amortization. (1,715) (1,708) (1,429) State income taxes, net of federal benefit.................. 2,577 4,144 3,494 Adjustment for prior years' taxes.. (7,702) (825) - Other, net......................... (1,726) (2,737) (3,283) -------- -------- ------- Total income tax expense............. $13,798 $32,724 $27,869 ======= ======= ======= 9. EMPLOYEE BENEFITS A. PENSION BENEFITS The company participates in a uniform noncontributory-defined benefit retirement plan covering all regular system employees. Benefits are based on years of service and employees' highest eligible compensation during five consecutive years of employment. The company's direct portion of the system's pension (income)/cost, part of which was charged to utility plant, approximated $(2.7) million in 1995, $(1.0) million in 1994, and $1.2 million in 1993. The company's pension costs for 1994 and 1993 included approximately $0.8 million and $2.7 million, respectively, related to workforce-reduction programs. Currently, the company funds annually an amount at least equal to that which will satisfy the requirements of the Employee Retirement Income Security Act and the Internal Revenue Code. Pension costs are determined using market-related values of pension assets. Pension assets are invested primarily in domestic and international equity securities and bonds. The components of net pension cost for WMECO are: For the Years Ended December 31, 1995 1994 1993 ----------------------------------------------------------- (Thousand of Dollars) Service cost................... $ 1,645 $ 2,720 $ 4,702 Interest cost.................. 7,757 7,655 7,527 Return on plan assets.......... (29,798) 221 (17,272) Net amortization............... 17,669 (11,635) 6,246 ------ -------- --------- Net pension (income)/cost...... $(2,727)$ (1,039) $ 1,203 ======= ======== ======== ----------------------------------------------------------- For calculating pension cost, the following assumptions were used: For the Years Ended December 31, 1995 1994 1993 ------------------------------------------------------------------ Discount rate.................. 8.25% 7.75% 8.00% Expected long-term rate of return 8.50 8.50 8.50 Compensation/progression rate.. 5.00 4.75 5.00 The following table represents the plan's funded status reconciled to the Balance Sheets: At December 31, 1995 1994 ----------------------------------------------------------------- (Thousands of Dollars) Accumulated benefit obligation, including vested benefits at December 31, 1995 and 1994 of $84,943,000 and $80,159,000, respectively................... $ 90,154 $ 85,193 ======== ======== Projected benefit obligation..... $107,527 $ 99,667 Market value of plan assets...... 143,632 122,813 -------- -------- Market value in excess of projected benefit obligation............. 36,105 23,146 Unrecognized transition amount... (2,198) (2,433) Unrecognized prior service costs. (525) (560) Unrecognized net gain............ (32,570) (22,068) -------- --------- Prepaid/(Accrued) pension liability $ 812 $ (1,915) ========== ====== The following actuarial assumptions were used in calculating the plan's year-end funded status: At December 31, 1995 1994 ----------------------------------------------------------------- Discount rate............................ 7.50% 8.25% Compensation/progression rate............ 4.75 5.00 B. POSTRETIREMENT BENEFITS OTHER THAN PENSIONS The company provides certain health care benefits, primarily medical and dental, and life insurance benefits through a benefit plan to retired employees (referred to as SFAS 106 benefits). These benefits are available for employees retiring from the company who have met specified service requirements. For current employees and certain retirees, the total SFAS 106 benefit is limited to two times the 1993 per-retiree health care costs. The SFAS 106 obligation has been calculated based on this assumption. WMECO's direct portion of health care and life insurance costs, part of which were deferred or charged to utility plant, approximated $4.4 million in 1995 and $5.0 million in both 1994 and 1993. During 1994, the company began funding SFAS 106 postretirement costs through external trusts. The company, is funding on an annual basis, amounts that have been rate recovered and which also are tax- deductible under the Internal Revenue Code. The trust assets are invested primarily in equity securities and bonds. The components of health care and life insurance costs are: For the Years Ended December 31, 1995 1994 1993 -------------------------------------------------------------- (Thousands of Dollars) Service cost................... $ 490 $ 519 $ 659 Interest cost.................. 2,544 2,703 2,676 Return on plan assets.......... (718) 19 - Amortization of unrecognized transition obligation........ 1,641 1,641 1,703 Other amortization, net........ 473 76 - ------ ------- ------- Net health care and life insurance costs.............. $4,430 $4,958 $5,038 ====== ====== ====== ------------------------------------------------------------ For calculating WMECO's SFAS 106 benefits cost, the following assumptions were used: For the Years Ended December 31, 1995 1994 1993 ------------------------------------------------------------ Discount rate.................. 8.00% 7.75% 7.75% Long-term rate of return - Health assets, net of tax.... 5.00 5.00 5.00 Life assets.................. 8.50 8.50 8.50 The following table represents the plan's funded status reconciled to the Balance Sheets: At December 31, 1995 1994 ------------------------------------------------------------ (Thousands of Dollars) Accumulated postretirement benefit obligation of: Retirees................................$28,787 $29,619 Fully eligible active employees......... 28 28 Active employees not eligible to retire. 5,847 4,823 ------- ------- Total accumulated postretirement benefit obligation..................... 34,662 34,470 ======= ======= Market value of plan assets.............. 5,339 2,026 -------- ------- Accumulated postretirement benefit obligation in excess of plan assets... (29,323) (32,444) Unrecognized transition amount........... 27,901 29,542 Unrecognized net gain.................... (1,399) (477) ------- ------- Accrued postretirement benefit liability.$(2,821) $(3,379) ======= ======= The following actuarial assumptions were used in calculating the plan's year-end funded status: At December 31, 1995 1994 ----------------------------------------------------------------- Discount rate............................ 7.50% 8.00% Health care cost trend rate (a).......... 8.40 10.20 (a)The annual growth in per capita cost of covered health care benefits was assumed to decrease to 5.4 percent by 2001. The effect of increasing the assumed health-care-cost trend rates by one percentage point in each year would increase the accumulated postretirement benefit obligation as of December 31, 1995 by $2.0 million and the aggregate of the service and interest cost components of net periodic postretirement benefit cost for the year then ended by $0.2 million. The trust holding the plan assets is subject to federal income taxes at a 35 percent tax rate. WMECO is currently recovering SFAS 106 costs, including amounts previously deferred. 10. COMMITMENTS AND CONTINGENCIES A. CONSTRUCTION PROGRAM The construction program is subject to periodic review and revision. WMECO currently forecasts construction expenditures of approximately $184.7 million for the years 1996-2000, including $30.4 million for 1996. In addition, the company estimates that nuclear fuel requirements, including nuclear fuel financed through the NBFT, will be approximately $54.9 million for the years 1996-2000, including $8.1 million for 1996. See Note 2, "Leases" for additional information about the financing of nuclear fuel. B. NUCLEAR PERFORMANCE In October 1994, Millstone 2 began a planned refueling and maintenance outage that was originally scheduled for 63 days. The outage encountered several unexpected difficulties which extended the duration of the outage until August 4, 1995. Total replacement power costs attributable to the extension of the outage for WMECO were approximately $16 million. Operation and maintenance (O&M) costs incurred during the outage were approximately $13 million, an increase of $5 million as a result of the outage extension. O&M costs associated with the refueling outage are deferred and amortized through rates for WMECO. The recovery of replacement power and O&M costs is subject to refund pending a prudence review in Massachusetts. Management does not believe the outcome of the prudence review will have a material adverse impact on the company's financial position and results of operations. In November 1995, Millstone 1 began a planned refueling and maintenance outage that was originally scheduled for 49 days. The outage has encountered several unexpected difficulties which has lengthened the duration of the outage. The impact of the outage extension is currently under review, but the unit is not expected to return to service until the mid to late part of the second quarter of 1996. The estimated costs attributable to this outage extension are replacement-power costs of $1.3 million per month and O&M costs of approximately $3.8 million. Recovery of the costs related to this outage is subject to prudence reviews by the DPU. On January 31, 1996, the NRC announced that the three Millstone nuclear power plants operated by NNECO had been placed on its "watch list" because of long-standing performance concerns. The NRC cited a number of operational problems which have arisen since 1990 at the Millstone plants. The NRC recognized that there are significant current variations in the performance of the three units. The performance concerns cited by the NRC, combined with NU's failure to maintain previous performance improvements, have resulted in the NRC requiring close monitoring of Millstone unit operations and the implementation of a corrective action program. While the NRC has not specifically restricted operations at the Millstone site, the company expects that there will be costs associated with the NRC's actions that cannot accurately be estimated at this time. C. ENVIRONMENTAL MATTERS WMECO is subject to regulation by federal, state, and local authorities with respect to air and water quality, handling the disposal of toxic substances and hazardous and solid wastes, and the handling and use of chemical products. WMECO has an active environmental auditing and training program and believes that it is in substantial compliance with current environmental laws and regulations. Environmental requirements could hinder the construction of new generating units, transmission and distribution lines, substations, and other facilities. The cumulative long-term cost impact of increasingly stringent environmental requirements cannot accurately be estimated. Changing environmental requirements could also require extensive and costly modifications to WMECO's existing generating units, and transmission and distribution systems, and could raise operating costs significantly. As a result, WMECO may incur significant additional environmental costs, greater than amounts included in cost of removal and other reserves, in connection with the generation and transmission of electricity and the storage, transportation, and disposal of by-products and wastes. WMECO may also encounter significantly increased costs to remedy the environmental effects of prior waste handling activities. WMECO has recorded a liability for what it believes, based upon information currently available, are its estimated environmental remediation costs for waste disposal sites. In most cases, additional future environmental cleanup costs are not reasonably estimable due to a number of factors, including the unknown magnitude of possible contamination, the appropriate remediation methods, the possible effects of future legislation or regulation, and the possible effects of technological changes. At December 31, 1995, the liability recorded by WMECO for its estimated environmental remediation costs, excluding any possible insurance recoveries or recoveries from third parties, amounted to approximately $1.1 million, which management has determined to be the most probable amount within the range of $1.1 million to $2.9 million. WMECO cannot estimate the potential liability for future claims, including environmental remediation costs, that may be brought against it. However, considering known facts, existing laws, and regulatory practices, management does not believe the matters disclosed above will have a material effect on WMECO's financial position or future results of operations. D. NUCLEAR INSURANCE CONTINGENCIES Under certain circumstances, in the event of a nuclear incident at one of the nuclear facilities covered by the federal government's third- party liability indemnification program, the company could be assessed in proportion to its ownership interest in each nuclear unit up to $75.5 million not to exceed $10 million per nuclear unit in any one year. The maximum assessment is to be adjusted at least every five years for inflationary changes. Based on the ownership interest in Millstone 1, 2, and 3, WMECO's maximum liability, including any additional potential assessments, would be $39.8 million per incident. In addition, through power purchase contracts with the three operating Yankee regional nuclear generating companies, WMECO would be responsible for up to an additional $11.9 million per incident. Payments for WMECO's ownership interest in nuclear generating facilities would be limited to a maximum of $6.5 million per incident per year. Insurance has been purchased to cover the primary cost of repair, replacement, or decontamination of utility property resulting from insured occurrences. WMECO is subject to retroactive assessments if losses exceed the accumulated funds available to the insurer. The maximum potential assessment against WMECO with respect to losses arising during the current policy year is approximately $2.9 million under the primary property insurance program. Insurance has been purchased to cover certain extra costs incurred in obtaining replacement power during prolonged accidental outages and the excess cost of repair, replacement, or decontamination or premature decommissioning of utility property resulting from insured occurrences. WMECO is subject to retroactive assessments if losses exceed the accumulated funds available to the insurer. The maximum potential assessments against the system with respect to losses arising during current policy years are approximately $2.0 million under the replacement power policies and $7.6 million under the excess property damage, decontamination, and decommissioning policies. The cost of a nuclear incident could exceed available insurance proceeds. Insurance has been purchased aggregating $200 million on a industry basis for coverage of worker claims. All participating reactor operators insured under this coverage are subject to retrospective assessments of $3.0 million per reactor. The maximum potential assessment against WMECO with respect to losses arising during the current policy period is approximately $2.2 million. E. LONG-TERM CONTRACTUAL ARRANGEMENTS Yankee Companies: WMECO, along with CL&P and PSNH, purchased approximately 6.7 percent of their electricity requirements pursuant to long-term contracts with the Yankee companies. Under the terms of their agreements, the companies pay their ownership (or entitlement) shares of generating costs, which include depreciation, O&M expenses, taxes, the estimated cost of decommissioning, and a return on invested capital. These costs are recorded as purchased-power expense and recovered through the companies' rates. WMECO's total cost of purchases under these contracts for the units that are operating amounted to $28.9 million in 1995, $28.8 million in 1994, and $30.2 million in 1993. See Note 1C, "Summary of Significant Accounting Policies-Investments and Jointly Owned Electric Utility Plant," and Note 3, "Nuclear Decommissioning," for more information on the Yankee companies. Nonutility Generators: WMECO has entered into two arrangements for the purchase of capacity and energy from nonutility generators. These arrangements have terms of 15 and 25 years, currently expiring in the years 2008 and 2013, and require WMECO to purchase the energy at specified prices or formula rates. For the twelve months ended December 31, 1995, approximately 13 percent of system electricity requirements was met by nonutility generators. WMECO's total cost of purchases under these arrangements amounted to $28.6 million in 1995, $27.5 million in 1994, and $13.6 million in 1993. These costs are eventually recovered through the company's rates. For additional information, see Note 1I, "Summary of Significant Accounting Policies-Recoverable Energy Costs." Hydro-Quebec: Along with other New England utilities, WMECO, CL&P, PSNH, and HWP entered into agreements to support transmission and terminal facilities to import electricity from the Hydro-Quebec system in Canada. WMECO is obligated to pay, over a 30-year period ending in 2020, its proportionate share of the annual O&M and capital costs of these facilities. The estimated annual costs of the WMECO's significant long-term contractual arrangements are as follows: 1996 1997 1998 1999 2000 ------------------------------------------------------------ (Millions of Dollars) Yankee companies..... $28.8 $27.9 $30.2 $30.7 $32.8 Nonutility generators 30.9 32.5 34.1 35.8 38.5 Hydro-Quebec......... 4.1 3.9 3.8 3.7 3.7 11. DERIVATIVE FINANCIAL INSTRUMENTS The company utilizes derivative financial instruments to manage well- defined interest-rate risk. The company does not use them for trading purposes. WMECO has entered into an interest-rate cap contract with a financial institution in order to reduce a portion of the interest-rate risk associated with its variable-rate tax-exempt pollution control revenue bond. During 1995, there was one outstanding contract held by WMECO, covering $52 million of its pollution control bond, which expired in January 1996. The contract entitled WMECO to receive from its counterparty the amount, if any by which the interest payments on a portion of its variable-rate tax-exempt pollution control revenue bond exceeds the J. J. Kenny High Grade Index. Due to its upcoming expiration, as of December 31, 1995, the total fair market value of this cap was zero. 12. FAIR VALUE OF FINANCIAL INSTRUMENTS The following methods and assumptions were used to estimate the fair value of each of the following financial instruments: Cash and nuclear decommissioning trusts: The carrying amounts approximate fair value. SFAS 115, Accounting for Certain Investments in Debt and Equity Securities, requires investments in debt and equity securities to be presented at fair value and was adopted by the company on a prospective basis as of January 1, 1994. During 1995, the investments held in the company's nuclear decommissioning trusts increased by $4.5 million as of December 31, 1995 and decreased by approximately $0.8 million as of December 31, 1994, with a corresponding offset to the accumulated provision for depreciation. The $4.5 million increase in 1995 represents cumulative gross unrealized holding gains. The cumulative gross unrealized holding losses were immaterial for 1995. The $0.8 million decrease for 1994 represents cumulative gross unrealized holding gains of $0.3 million, offset by cumulative gross unrealized holding losses of $1.1 million. There was no change in funding requirements of the trusts nor any impact on earnings as a result of the adoption of SFAS 115. Preferred stock and long-term debt: The fair value of WMECO's fixed-rate securities is based upon the quoted market price for those issues or similar issues. WMECO's adjustable rate preferred stock is assumed to have a fair value equal to its carrying value. The carrying amount of WMECO's financial instruments and the estimated fair values are as follows: Carrying Fair At December 31, 1995 Amount Value -------------------------------------------------------------- (Thousands of Dollars) Preferred stock not subject to mandatory redemption.................. $ 53,500 $ 53,700 Preferred stock subject to mandatory redemption............................ 24,000 25,085 Long-term debt - First Mortgage Bonds... 259,500 265,280 Other long-term debt.................... 88,980 88,980 - ------------------------------------------------------------------- Carrying Fair At December 31, 1994 Amount Value -------------------------------------------------------------- (Thousands of Dollars) Preferred stock not subject to mandatory redemption.................. $ 68,500 $ 66,050 Preferred stock subject to mandatory redemption............................ 24,675 24,675 Long-term debt - First Mortgage Bonds... 294,050 274,469 Other long-term debt.................... 87,039 87,039 The fair values shown above have been reported to meet the disclosure requirements and do not purport to represent the amounts at which those obligations would be settled. To the Board of Directors of Western Massachusetts Electric Company We have audited the accompanying balance sheets of Western Massachusetts Electric Company (a Massachusetts corporation and a wholly owned subsidiary of Northeast Utilities) as of December 31, 1995 and 1994, and the related statements of income, common stockholder's equity, 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 Western Massachusetts Electric 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. As discussed in Note 1A to the Financial Statements, effective January 1, 1993, Western Massachusetts Electric Company changed its method of accounting for property taxes. /s/ Arthur Andersen LLP ARTHUR ANDERSEN LLP Hartford, Connecticut February 16, 1996 WESTERN MASSACHUSETTS ELECTRIC COMPANY MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - ---------------------------------------------------------------------- This section contains management's assessment of WMECO's (the company) financial condition and the principal factors having an impact on the results of opera- tions. The company is a wholly owned subsidiary of Northeast Utilities (NU). This discussion should be read in conjunction with the company's financial statements and footnotes. FINANCIAL CONDITION OVERVIEW Net income was approximately $39 million in 1995, a decrease of approximately $10 million, from approximately $49 million in 1994. The 1995 net income was lower as a result of higher fuel and purchased power costs and higher operation expenses, partially offset by lower income tax expense and lower amortization of regulatory assets due to the completion of the Millstone 3 phase-in costs. Retail kilowatt-hour sales fell by 0.1 percent in 1995 as a result of a flat economy in New England and mild weather in the first quarter of 1995. With the New England economy not forecasted to grow substantially during 1996, sales levels are expected to remain flat. WMECO acts as both a buyer and a seller of electricity in the highly competitive wholesale electricity market in the Northeast. Increased competition has made the renegotiation of expiring wholesale contracts, as well as the signing of new contracts, financially challenging. In the last few years WMECO has entered into several smaller long-term sales contracts which will continue through approximately the year 2005. During 1995, the Federal Energy Regulatory Commission issued a proposal for restructuring the electric-power industry, which calls for open access to transmission facilities, a standard formula for calculating rates, and full recovery of stranded investments. The impact on WMECO of this proposal, which is expected to be finalized in 1996, is not known at this time. During 1995, a Massachusetts Senate Committee and the Coalition of Northeastern Governors released their reports addressing the restructuring of the electric- power industry and its resulting impact on customers and states. Both of these reports presented the future as one in which there would be some form of continued regulation for transmission and distribution with fully competitive generation. Also in 1995, the Massachusetts Department of Public Utilities (DPU) concluded that while increased competition is in the public interest, electric utilities should have the opportunity to recover "net, nonmitigatable stranded costs" during a transition period to full competition. While such a conclusion is encouraging, there is uncertainty with regard to the final regulatory and legislative definitions of terms such as "net, nonmitigatable" and "stranded costs." WMECO is taking a proactive role in the electric-power industry's movement toward competition. In its "Customers First" plan (the plan), which was filed with the DPU in February 1996, WMECO outlined a comprehensive approach to enhancing customer satisfaction and market efficiency while moving toward full competition in the electricity marketplace. The plan calls for several significant changes in electricity pricing, the ability to introduce new products and services, the method of rate-setting, and the operation of the New England Power Pool. The plan also calls for the phase-in of supplier choices through the use of pilot programs. Management believes that a fully competitive market for electricity should begin once all issues relating to the transition from traditional utility regulation have been thoroughly addressed. In addition to the formulation of this plan and ongoing meetings with legislators, regulators and others in the industry, WMECO is moving ahead in other areas, including revenue enhancement initiatives and cost reductions, to better position itself for an increasingly competitive environment. A comprehensive companywide effort, which started in 1994, to reengineer WMECO's business and operating processes continued throughout 1995. WMECO expects that this effort will have significant positive effects on operating costs and customer service. Many of the organizational changes in the operating and service functions announced in 1995 and early 1996 are consistent with the initial recommendations of the reengineering teams. While WMECO's reengineering efforts will be reduced in 1996, implementation costs relating to the previous reengineering efforts are expected to increase. With retail electric revenues accounting for approximately 90 percent of its 1995 revenues, WMECO has continued to develop a number of initiatives to retain and serve its existing customers and to expand its retail customer base. The most visible result of these efforts is the expansion of the Retail Marketing organization. Retail Marketing's mission is to better understand the needs and concerns of WMECO's retail customer and to develop innovative approaches to addressing these issues. These initiatives include providing discounts to certain customers for signing economic development and competitive generation- based contracts, offering demand-side-management services, and providing additional products and services. WORKFORCE REDUCTIONS In January 1996, NU completed its nuclear workforce reduction plan. Approximately 220 positions were eliminated through a combination of early retirements, attrition, and layoffs. The total pretax cost of the workforce reduction to the NU system, which was recognized in 1995, was approximately $9 million. RATE MATTERS WMECO follows accounting principles in accordance with Statement of Financial Accounting Standards (SFAS) 71, "Accounting for the Effects of Certain Types of Regulation" that allows the economic effects of rate regulation to be reflected. Under these principles, regulators may permit incurred costs for certain events or transactions, which would be treated as expenses by nonregulated enterprises, to be deferred as regulatory assets and recovered in revenues at a later date. The creation of these regulatory assets has kept down electric rates in past years, at the expense of having higher rates in the future. At December 31, 1995, WMECO's regulatory assets totaled approximately $161 million. The largest regulatory assets are related to the future recovery of income taxes, nearly $88 million, and payments to the United States Department of Energy for fuel disposal, approximately $35 million. The substantial costs of amortizing these regulatory assets would hinder WMECO from competing effectively in an openly competitive electric market if customers are not required to pay such costs. Given the increasingly competitive nature of the industry and increased activity in the regulatory environment, WMECO has made the recovery of regulatory assets one of its central financial strategies, while balancing the customer's pricing needs with NU's shareholder's earnings requirements. Under its proposed settlement with the DPU (see discussion below), WMECO will be allowed to recover a significant portion of its regulatory assets during the next five years. In March 1995, the Financial Accounting Standards Board (FASB) issued SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of." SFAS 121, which was effective January 1, 1996, requires assets, including regulatory assets, that are no longer probable of recovery through future revenues be charged to earnings. If future competition or regulatory actions cause any portion of its operations to no longer be subject to SFAS 71, WMECO would be required to determine the fair value of the related regulatory assets and liabilities and record any necessary write-downs. Additionally, if events create uncertainty about the recoverability of any of WMECO's remaining long-lived assets, a similar analysis would be required for those assets in accordance with SFAS 121. Under its current regulatory environment, WMECO believes that its use of SFAS 71 remains appropriate and that the adoption of SFAS 121 will not have a material impact on its financial position or results of operations. See the "Notes to Financial Statements," Note 1G, for further details on regulatory accounting. In February 1996, WMECO and the Massachusetts Attorney General proposed a settlement with the DPU, which, if approved, would continue the 2.4-percent rate reduction instituted in June 1994. The reduction would remain in effect through February 1998. Additionally, the settlement would terminate WMECO's pending reviews of its generating plant performance, any potential reviews associated with Millstone 2's 1994-1995 extended outage, and accelerate its recovery of generation assets by approximately $6 million and $10 million in 1996 and 1997, respectively. The settlement does not address the issues discussed above related to the restructuring of the electric-power industry. NUCLEAR PERFORMANCE On January 31, 1996, the Nuclear Regulatory Commission (NRC) placed Millstone 1, 2, and 3 (Millstone) on its "watch list." The NRC's action was in response to a number of performance concerns which have arisen since 1990 and a failure to resolve employee safety concerns. The NRC's action will result in close monitoring of programs and performance at Millstone to assure the development and implementation of effective corrective actions. NU's management plans to continue its extensive efforts already under way to address these concerns. Concurrent with the NRC's action, NU provided the NRC with the results of a comprehensive self-assessment review of the employee concern program at Millstone. Additionally, in January 1996, NU announced a reorganization of its nuclear operations which included the creation of a new office of Nuclear Safety and Oversight. Although the start-up of Millstone 1, which is currently in outage, will be affected by its placement on the NRC's "watch list," operations at Millstone 2 and 3 have not been restricted. NU's management expects that the increased NRC attention will inevitably have effects and costs that are not known at this time. In November 1995, Millstone 1 began a planned refueling and maintenance outage. The outage has been extended to allow NU to complete reviews required by the NRC. In response to a request by the NRC, NU is conducting a detailed review of Millstone 1's Final Safety Analysis Report and an assessment of the plant's readiness to ensure that the future operation of the plant will be conducted in accordance with the terms and conditions of its operating license and the NRC's regulations. The outage schedule is currently under review, but the unit is not expected to return to service before the mid-to-late part of the second quarter of 1996. Total replacement-power costs attributable to the Millstone 1 outage extension for WMECO are expected to be approximately $1 million per month. In addition, operation and maintenance (O&M) costs to be incurred as a result of the extension are estimated to be approximately $4 million. Replacement-power costs are recovered currently through rates. Nuclear outage O&M costs are deferred and amortized through rates. The recovery, or refund, of outage costs is subject to prudence reviews. The composite capacity factor of the five nuclear generating units that NU operates-including the Connecticut Yankee nuclear unit-was 69.9 percent in 1995, compared with 67.5 percent for 1994, and a 1995 national average of 77.6 percent. The 1995 capacity factor was impacted by an extended refueling and maintenance outage for Millstone 2. See the "Notes to Financial Statements," Note 10B, for further information on outage deferrals and recoveries. ENVIRONMENTAL MATTERS NU devotes substantial resources to identify and comply with the multitude of environmental requirements it faces. NU has active auditing programs addressing a variety of regulatory requirements, including an environmental auditing program to detect and remedy noncompliance with environmental laws or regulations. WMECO is potentially liable for environmental cleanup costs at a number of sites both inside and outside its service territory. To date, the future estimated environmental remediation liability has not been material with respect to the earnings or financial position of WMECO. At December 31, 1995, WMECO had recorded an environmental reserve amounting to approximately $1 million, the minimum amount required under SFAS 5, "Accounting for Contingencies." These costs could be significantly higher if alternative remedies become necessary. NUCLEAR DECOMMISSIONING WMECO's estimated cost to decommission its shares of Millstone 1, 2, and 3 is approximately $186 million in year-end 1995 dollars. These costs are being recognized over the lives of the respective units and a portion is being recovered through rates. The FASB is currently reviewing the accounting for closure and removal costs, including decommissioning and similar costs, for long-lived assets. If current electric-power industry accounting practices for such decommissioning costs were changed, annual provisions for decommissioning would increase and the estimated costs for decommissioning would be recorded as a liability rather than as a component of accumulated depreciation. See the "Notes to Financial Statements," Note 3, for further information on nuclear decommissioning, including WMECO's share of costs to decommission the regional nuclear generating units. LIQUIDITY AND CAPITAL RESOURCES Cash provided from operations decreased approximately $29 million in 1995, from 1994, primarily due to higher cash payments for energy, operation, and maintenance costs, and lower working capital. Cash used for financing activities was relatively flat in 1995, from 1994. Cash used for investments decreased approximately $28 million in 1995, from 1994, primarily due to a decrease in loans to other system companies under the NU system Money Pool, lower construction expenditures, and lower nuclear fuel expenditures. WMECO has entered into interest-rate-cap contracts to reduce a portion of its interest-rate risk See the "Notes to Financial Statements," Note 11, for further information on derivative financial instruments and the "Notes to Financial Statements," Notes 6, 7 and 10A, for further information on construction and long-term debt funding requirements. RESULTS OF OPERATIONS OPERATING REVENUES The components of the change in operating revenues for the past two years are provided in the table below. Change In Operating Revenues Increase/(Decrease) 1995 vs. 1994 1994 vs. 1993 - -------------------------------------------------------------------- (Millions of Dollars) Regulatory decisions $(2) $(4) Fuel and purchased power cost recoveries 7 13 Sales volume (1) (2) Other revenues (5) (1) --- --- Total revenue change $(1) $6 ==== == Revenues related to regulatory decisions decreased, primarily due to the effects of the June 1994 retail-rate reduction, partially offset by higher recoveries for demand-side-management costs. Fuel and purchased-power cost recoveries increased primarily due to higher energy costs, partially offset by lower interchange revenues. Other includes higher price discounts to customers in 1995. Operating revenues increased approximately $6 million in 1994, from 1993. Revenues related to regulatory decisions decreased, primarily due to the effects of the June 1994 retail-rate reduction, and lower recoveries for demand-side management-costs, partially offset by the July 1993 retail-rate increase. Fuel and purchased-power cost recoveries increased primarily due to higher energy interchange revenues in 1994. FUEL, PURCHASED AND NET INTERCHANGE POWER Fuel, purchased and net interchange power expense increased approximately $19 million in 1995, from 1994, primarily due to a one-time benefit in May 1994 from a rate case settlement agreement and higher energy costs in 1995 as a result of the extended Millstone 2 outage. The change in 1994, from 1993, was not significant. OTHER OPERATION AND MAINTENANCE EXPENSES Other operation and maintenance expense increased approximately $14 million in 1995, from 1994, primarily due to higher capacity charges from the regional nuclear units primarily due to Maine Yankee which was in an extended refueling outage throughout 1995, higher benefit costs, higher demand-side-management costs, higher 1995 storm costs, higher costs associated with a work stoppage, and higher outside services employed, partially offset by lower reserves for excess/obsolete inventory in 1995, and lower maintenance costs at the company's fossil units. Other operation and maintenance expenses decreased approximately $10 million in 1994, from 1993, primarily due to higher costs in 1993 associated with early- retirement programs, lower 1994 payroll and benefit costs, lower fossil-unit costs, and lower capacity charges from the regional nuclear generating units, partially offset by higher 1994 costs associated with the operation and maintenance activities of the nuclear units, higher reserves for excess/obsolete inventory at the nuclear and fossil units in 1994, and higher outside services primarily related to companywide process reengineering. AMORTIZATION OF REGULATORY ASSETS, NET Amortization of regulatory assets, net decreased approximately $10 million in 1995, from 1994, primarily due to the completion of the company's amortization of Millstone 3 phase-in costs in 1995. The change in 1994, from 1993, was not significant. FEDERAL AND STATE INCOME TAXES Federal and state income taxes decreased approximately $19 million in 1995, from 1994, primarily due to tax benefits from a favorable tax ruling, the expiration of the federal statute of limitations for 1991, and lower taxable income. Federal and state income taxes increased approximately $5 million in 1994, from 1993, primarily due to higher taxable income. OTHER INCOME, NET Other income, net decreased by approximately $2 million in 1995, from 1994, primarily because additional Millstone 3 investments were phased into rates. The change in 1994, from 1993, was not significant. INTEREST CHARGES Although the change in 1995, from 1994, was not significant, interest on long- term debt decreased approximately $2 million in 1994, from 1993, primarily due to lower average interest rates as a result of refinancing activities and lower 1994 debt levels. CUMULATIVE EFFECT OF ACCOUNTING CHANGE The cumulative effect of the accounting change of approximately $4 million in 1993 represents the one-time change in the method of accounting for Connecticut municipal property tax expense recognized in the first quarter of 1993. WESTERN MASSACHUSETTS ELECTRIC COMPANY SELECTED FINANCIAL DATA (a) 1995 1994 1993 1992 1991 - ------------------------------------------------------------------------------- (Thousands of Dollars) Operating Revenues........ $ 420,208 $ 421,477 $ 415,055 $ 410,720 $ 409,840 Operating Income.......... 63,064 70,940 60,348 60,563 59,833 Net Income................ 39,133 49,457 40,594(b) 37,022 34,637 Cash Dividends on Common Stock............ 30,223 29,514 28,785 29,536 31,499 Total Assets.............. 1,142,346 1,183,618 1,204,642 1,130,684 1,119,593 Long-Term Debt*........... 347,470 379,969 393,232 392,976 401,095 Preferred Stock Not Subject to Mandatory Redemption.... 53,500 68,500 73,500 73,500 88,500 Preferred Stock Subject to Mandatory Redemption(c). 24,000 24,675 27,000 28,500 28,502 Obligations Under Capital Leases(c)............... 36,011 36,797 36,902 41,509 44,134 (a) Reclassifications of prior years' data have been made to conform with the current year's presentation. (b) Includes the cumulative effect of change in accounting for municipal property tax expense, which increased earnings for common shares by $3.9 million. (c)Includes portion due within one year. STATEMENTS OF QUARTERLY FINANCIAL DATA (Unaudited) - -------------------------------------------------- Quarter Ended (a) -------------------------------------------- 1995 March 31 June 30 September 30 December 31 - -------------------------------------------------------------------------- Operating Revenues........ $106,684 $100,593 $107,960 $104,971 ======== ======== ======== ======== Operating Income.......... $ 18,085 $ 8,977 $ 19,799 $ 16,203 ======== ======== ======== ======== Net Income................ $ 12,076 $ 3,289 $ 14,141 $ 9,627 ======== ======== ======== ======== 1994 - --------------------------------------------------------------------------- Operating Revenues........ $112,984 $101,188 $102,597 $104,708 ======== ======== ======== ======== Operating Income.......... $ 19,732 $ 21,466 $ 11,596 $ 18,146 ======== ======== ======== ======== Net Income................ $ 13,961 $ 16,035 $ 6,395 $ 13,066 ======== ======== ======== ======== (a)Reclassifications of prior period data have been made to conform with the current presentation. WESTERN MASSACHUSETTS ELECTRIC COMPANY STATISTICS - ------------------------------------------------------------------------- Gross Electric Average Utility Plant Annual December 31, Use Per Electric (Thousands of kWh Sales Residential Customers Employees Dollars) (Millions) Customer (kWh) (Average) (December 31) - ------------------------------------------------------------------------- 1995 $1,285,269 4,846 7,243 193,964 527 1994 1,271,513 4,978 7,433 193,187 617 1993 1,242,927 4,715 7,351 192,542 657 1992 1,214,386 4,155 7,433 191,920 739 1991 1,199,362 3,780 7,494 191,692 797 EX-13.4 19 ANNUAL REPORT OF PSNH EXHIBIT 13.4 1995 Annual Report Public Service Company of New Hampshire Index Contents Page - -------- ---- Balance Sheets.............................................. 2-3 Statements of Income........................................ 4 Statements of Cash Flows.................................... 5 Statements of Common Stockholder's Equity................... 6 Notes to Financial Statements............................... 7 Report of Independent Public Accountants.................... 25 Management's Discussion and Analysis of Financial Condition and Results of Operations....................... 26 Selected Financial Data..................................... 32 Statistics.................................................. 34 Statements of Quarterly Financial Data...................... 34 Preferred Stockholder and Bondholder Information............ Back Cover PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE BALANCE SHEETS
- ------------------------------------------------------------------------------------- At December 31, 1995 1994 - ------------------------------------------------------------------------------------- (Thousands of Dollars) ASSETS - ------ Utility Plant, at cost: Electric................................................ $2,109,590 $2,038,625 Less: Accumulated provision for depreciation......... 513,244 474,129 ----------- ----------- 1,596,346 1,564,496 Unamortized acquisition costs (Note 1H)............ 588,910 678,974 Construction work in progress........................... 15,975 17,781 Nuclear fuel, net....................................... 1,585 2,248 ----------- ----------- Total net utility plant............................. 2,202,816 2,263,499 ----------- ----------- Other Property and Investments: Nuclear decommissioning trusts, at market............... 2,436 1,815 Investments in regional nuclear generating companies and subsidiary company, at equity............ 19,300 19,551 Other, at cost.......................................... 764 394 ----------- ----------- 22,500 21,760 ----------- ----------- Current Assets: Cash.................................................... 456 322 Notes receivable from affiliated companies.............. 19,100 35,000 Receivables, less accumulated provision for uncollectible accounts of $1,582,000 in 1995 and of $2,015,000 in 1994............................. 91,535 76,173 Accounts receivable from affiliated companies........... 1,486 3,779 Accrued utility revenues................................ 33,984 36,547 Fuel, materials, and supplies, at average cost.......... 41,717 37,453 Prepayments and other................................... 11,196 20,829 ----------- ----------- 199,474 210,103 ----------- ----------- Deferred Charges: Regulatory assets (Note 1G)........................ 434,001 292,531 Deferred receivable from affiliated company............. 33,284 33,284 Unamortized debt expense................................ 14,165 17,064 Other................................................... 3,396 7,726 ----------- ----------- 484,846 350,605 ----------- ----------- Total Assets........................................ $2,909,636 $2,845,967 =========== ===========
The accompanying notes are an integral part of these financial statements. PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE BALANCE SHEETS
- -------------------------------------------------------------------------------------- At December 31, 1995 1994 - -------------------------------------------------------------------------------------- (Thousands of Dollars) CAPITALIZATION AND LIABILITIES - ------------------------------ Capitalization: Common stock, $1 par value--authorized and outstanding 1,000 shares in 1995 and 1994........... $ 1 $ 1 Capital surplus, paid in................................. 422,385 421,784 Retained earnings........................................ 143,039 125,034 ----------- ----------- Total common stockholder's equity............... 565,425 546,819 Cumulative preferred stock subject to mandatory redemption-- $25 par value--authorized 25,000,000 shares; outstanding 5,000,000 shares in 1995 and 1994...... 125,000 125,000 Long-term debt........................................... 686,485 905,985 ----------- ----------- Total capitalization............................ 1,376,910 1,577,804 ----------- ----------- Obligations Under Seabrook Power Contracts and Other Capital Leases.................................. 874,292 849,776 ----------- ----------- Current Liabilities: Long-term debt--current portion.......................... 172,500 94,000 Obligations under Seabrook Power Contracts and other capital leases--current portion......................... 40,996 38,191 Accounts payable......................................... 39,012 45,984 Accounts payable to affiliated companies................. 26,656 17,309 Accrued taxes............................................ 798 4,304 Accrued interest......................................... 9,648 10,496 Accrued pension benefits................................. 38,606 36,269 Other.................................................... 19,077 20,350 ----------- ----------- 347,293 266,903 ----------- ----------- Deferred Credits: Accumulated deferred income taxes (Note 1J)......... 229,057 62,080 Accumulated deferred investment tax credits.............. 5,060 5,614 Deferred contractual obligation.......................... 18,814 28,572 Deferred revenue from affiliated company................. 33,284 33,284 Other.................................................... 24,926 21,934 ----------- ----------- 311,141 151,484 ----------- ----------- Commitments and Contingencies (Note 10) Total Capitalization and Liabilities............ $2,909,636 $2,845,967 =========== ===========
The accompanying notes are an integral part of these financial statements PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE STATEMENTS OF INCOME
- --------------------------------------------------------------------------------- For the Years Ended December 31, 1995 1994 1993 - --------------------------------------------------------------------------------- (Thousands of Dollars) Operating Revenues.............................. $ 979,590 $ 922,039 $ 864,415 ---------- ---------- ---------- Operating Expenses: Operation -- Fuel, purchased and net interchange power.. 257,008 222,801 208,023 Other...................................... 313,390 303,271 301,534 Maintenance................................... 42,244 43,725 35,427 Depreciation.................................. 44,337 38,703 38,580 Amortization of regulatory assets, net........ 55,547 55,319 67,379 Federal and state income taxes (Note 8)... 69,758 68,088 54,087 Taxes other than income taxes................. 41,786 38,046 34,675 ---------- ---------- ---------- Total operating expenses................ 824,070 769,953 739,705 ---------- ---------- ---------- Operating Income................................ 155,520 152,086 124,710 ---------- ---------- ---------- Other Income: Equity in earnings of regional nuclear generating companies and subsidiary company.. 1,645 2,079 1,777 Other, net.................................... 3,329 629 635 Income taxes.................................. (829) (546) 3,868 ---------- ---------- ---------- Other income, net....................... 4,145 2,162 6,280 ---------- ---------- ---------- Income before interest charges.......... 159,665 154,248 130,990 ---------- ---------- ---------- Interest Charges: Interest on long-term debt.................... 76,320 76,410 77,842 Other interest................................ 90 394 911 ---------- ---------- ---------- Interest charges, net................... 76,410 76,804 78,753 ---------- ---------- ---------- Net Income...................................... $ 83,255 $ 77,444 $ 52,237 ========== ========== ==========
The accompanying notes are an integral part of these financial statements. PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE STATEMENTS OF CASH FLOWS
- -------------------------------------------------------------------------------------------------- For the Years Ended December 31, 1995 1994 1993 - -------------------------------------------------------------------------------------------------- (Thousands of Dollars) Operating Activities: Net Income.................................................. $ 83,255 $ 77,444 $ 52,237 Adjustments to reconcile to net cash from operating activities: Depreciation.............................................. 44,337 38,703 38,580 Deferred income taxes and investment tax credits, net..... 69,986 67,047 50,027 Recoverable energy costs, net of amortization............. (15,266) (81,206) (39,654) Amortization of acquisition costs......................... 55,547 55,319 67,379 Other sources of cash..................................... 15,973 3,213 30,001 Other uses of cash........................................ - (4,456) (4,394) Changes in working capital: Receivables and accrued utility revenues.................. (10,506) (3,205) (3,161) Fuel, materials, and supplies............................. (4,264) 3,734 3,936 Accounts payable.......................................... 2,375 18,598 (2,894) Accrued taxes............................................. (3,506) 4,182 (1,602) Other working capital (excludes cash)..................... 16 742 (2,224) ----------- ----------- ----------- Net cash flows from operating activities...................... 237,947 180,115 188,231 ----------- ----------- ----------- Financing Activities: Issuance of long-term debt.................................. - - 44,800 Net decrease in short-term debt............................. - (2,500) (41,000) Reacquisitions and retirements of long-term debt............ (141,000) (94,000) (138,800) Cash dividends on preferred stock........................... (13,250) (13,250) (13,250) Cash dividends on common stock.............................. (52,000) - - ----------- ----------- ----------- Net cash flows used for financing activities.................. (206,250) (109,750) (148,250) ----------- ----------- ----------- Investment Activities: Investment in plant: Electric utility plant.................................... (46,672) (39,721) (35,360) Nuclear fuel.............................................. (184) (1,249) (614) ----------- ----------- ----------- Net cash flows used for investments in plant................ (46,856) (40,970) (35,974) NU System Money Pool........................................ 15,900 (35,000) - Other investment activities, net............................ (607) (68) (340) ----------- ----------- ----------- Net cash flows used for investments........................... (31,563) (76,038) (36,314) ----------- ----------- ----------- Net Increase (Decrease) in Cash For The Period................ 134 (5,673) 3,667 Cash - beginning of period.................................... 322 5,995 2,328 ----------- ----------- ----------- Cash - end of period.......................................... $ 456 $ 322 $ 5,995 =========== =========== =========== Supplemental Cash Flow Information: Cash paid during the year for: Interest, net of amounts capitalized........................ $ 74,543 $ 74,507 $ 75,609 =========== =========== =========== Income taxes................................................ $ 1,369 $ 167 $ 2,390 =========== =========== =========== Increase in obligations: Seabrook Power Contracts and other capital leases........... $ 28,028 $ 53,266 $ 89,492 =========== =========== ===========
The accompanying notes are an integral part of these financial statements. PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
- --------------------------------------------------------------------------------------- Capital Common Surplus, Retained Stock Paid In Earnings Total - --------------------------------------------------------------------------------------- (Thousands of Dollars) Balance at January 1, 1993............... $ 1 $420,762 $ 21,853 $442,616 Net income for 1993.................. 52,237 52,237 Cash dividends on preferred stock.... (13,250) (13,250) Capital stock expenses, net.......... 483 483 -------- --------- --------- --------- Balance at December 31, 1993............. 1 421,245 60,840 482,086 Net income for 1994.................. 77,444 77,444 Cash dividends on preferred stock.... (13,250) (13,250) Capital stock expenses, net.......... 539 539 -------- --------- --------- --------- Balance at December 31, 1994............. 1 421,784 125,034 546,819 Net income for 1995.................. 83,255 83,255 Cash dividends on preferred stock.... (13,250) (13,250) Cash dividends on common stock....... (52,000) (52,000) Capital stock expenses, net.......... 601 601 -------- --------- --------- --------- Balance at December 31, 1995............. $ 1 $422,385 $143,039 $565,425 ======== ========= ========= =========
The accompanying notes are an integral part of these financial statements. Public Service Company of New Hampshire NOTES TO FINANCIAL STATEMENTS - ---------------------------------------------------------------------- 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES A. PRESENTATION Public Service Company of New Hampshire (PSNH or the company), The Connecticut Light and Power Company (CL&P), Western Massachusetts Electric Company (WMECO), North Atlantic Energy Corporation (NAEC), and Holyoke Water Power Company (HWP) are the operating subsidiaries comprising the Northeast Utilities (NU) system (the system) and are wholly owned by NU. The system furnishes retail electric service in Connecticut, New Hampshire, and western Massachusetts through CL&P, PSNH, WMECO, and HWP. A fifth subsidiary, NAEC, sells all of its capacity to PSNH. In addition to its retail service, the system furnishes firm and other wholesale electric services to various municipalities and other utilities. The system serves about 30 percent of New England's electric needs and is one of the 20 largest electric utility systems in the country as measured by revenues. Other wholly owned subsidiaries of NU provide substantial support services to the system. Northeast Utilities Service Company (NUSCO) supplies centralized accounting, administrative, data processing, engineering, financial, legal, operational, planning, purchasing, and other services to the system companies. North Atlantic Energy Service Corporation acts as agent for CL&P and NAEC in operating the Seabrook 1 nuclear facility. Northeast Nuclear Energy Company (NNECO) acts as agent for the system companies in operating the Millstone nuclear generating facilities. All transactions among affiliated companies are on a recovery of cost basis which may include amounts representing a return on equity, and are subject to approval by various federal and state regulatory agencies. 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 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. Certain reclassifications of prior years' data have been made to conform with the current year's presentation. B. FUTURE ACCOUNTING STANDARD The Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of, in March 1995. SFAS 121 became effective January 1, 1996, and establishes accounting standards for evaluating and recording asset impairment. SFAS 121 requires the evaluation of long-lived assets for impairment when certain events occur or conditions exist that indicate the carrying amounts of assets may not be recoverable. Refer to Note 1G, "Regulatory Accounting," for further information on the regulatory impacts of the company's adoption of SFAS 121. C. INVESTMENTS AND JOINTLY OWNED ELECTRIC UTILITY PLANT Regional Nuclear Generating Companies: PSNH owns common stock of four regional nuclear generating companies (Yankee companies). The Yankee companies, with PSNH's ownership interests, are: Connecticut Yankee Atomic Power Company (CY) ........ 5.0% Yankee Atomic Electric Company (YAEC) ............... 7.0 Maine Yankee Atomic Power Company (MY) .............. 5.0 Vermont Yankee Nuclear Power Corporation (VY) ....... 4.0 PSNH's investments in the Yankee companies are accounted for on the equity basis due to the company's ability to exercise significant influence over their operating and financial policies. The electricity produced by the facilities that are operating is committed substantially on the basis of ownership interests and is billed pursuant to contractual agreements. Under ownership agreements with the Yankee companies, PSNH may be asked to provide direct or indirect financial support for one or more of the companies. For more information on these agreements, see Note 10E, "Commitments and Contingencies - Long-term Contractual Arrangements." YAEC's nuclear power plant was shut down permanently on February 26, 1992. For more information on the Yankee companies, see Note 4, "Nuclear Decommissioning." Millstone 3: PSNH has a 2.85 percent joint-ownership interest in Millstone 3, a 1,154-megawatt (MW) nuclear generating unit. As of December 31, 1995 and 1994, plant-in-service included approximately $118.6 million and $118.3 million, respectively, and the accumulated provision for depreciation included approximately $26.5 million and $24.2 million, respectively, for PSNH's share of Millstone 3. PSNH's share of Millstone 3 expenses is included in the corresponding operating expenses on the accompanying Statements of Income. Wyman Unit 4: PSNH has a 3.14 percent ownership-interest in Wyman Unit 4 (Wyman), a 632-MW oil-fired generating unit. At December 31, 1995 and 1994, plant-in-service included approximately $6.0 million and the accumulated provision for depreciation included approximately $3.5 million and $3.3 million, respectively, for PSNH's share of Wyman. PSNH's share of Wyman expenses is included in the corresponding operating expenses on the accompanying Statements of Income. D. DEPRECIATION The provision for depreciation is calculated using the straight-line method based on estimated remaining lives of depreciable utility plant-in-service, adjusted for salvage value and removal costs, as approved by the New Hampshire Public Utilities Commission (NHPUC). Except for major facilities, depreciation factors are applied to the average plant-in-service during the period. Major facilities are depreciated from the time they are placed in service. When plant is retired from service, the original cost of plant, including costs of removal, less salvage, is charged to the accumulated provision for depreciation. The depreciation rates for the several classes of electric plant-in-service are equivalent to a composite rate of 3.8 percent for the year ended December 31, 1995 and 3.6 percent for the years ended December 31, 1994 and 1993. See Note 4, "Nuclear Decommissioning," for information on nuclear plant decommissioning. E. PUBLIC UTILITY REGULATION NU is registered with the Securities and Exchange Commission (SEC) as a holding company under the Public Utility Holding Company Act of 1935 (1935 Act), and it and its subsidiaries, including the company, are subject to the provisions of the 1935 Act. Arrangements among the system companies, outside agencies, and other utilities covering inter- connections, interchange of electric power, and sales of utility property are subject to regulation by the Federal Energy Regulatory Commission (FERC) and/or the SEC. The company is subject to further regulation for rates, accounting, and other matters by the FERC and/or the NHPUC. F. REVENUES Other than recovery under fixed-rate agreements negotiated with certain wholesale, industrial, and commercial customers, utility revenues are based on authorized rates applied to each customer's use of electricity. In general, rates can be changed only through a formal proceeding before the appropriate regulatory commission. At the end of each accounting period, PSNH accrues an estimate for the amount of energy delivered but unbilled. G. REGULATORY ACCOUNTING The accounting policies of PSNH and the accompanying financial statements conform to generally accepted accounting principles applicable to rate-regulated enterprises and reflect the effects of the ratemaking process in accordance with SFAS 71, Accounting for the Effects of Certain Types of Regulation. Assuming a cost-of-service based regulatory structure, regulators may permit incurred costs, normally treated as expenses, to be deferred and recovered in future revenues. Through their actions, regulators may also reduce or eliminate the value of an asset, or create a liability. If any portion of the company's operations were no longer subject to the provisions of SFAS 71, as a result of a change in the cost-of-service based regulatory structure or the effects of competition, the company would be required to write off related regulatory assets and liabilities. The company would also be required to determine any impairment to other assets and write down these assets to fair value. Based on current regulation and recent regulatory decisions and initiatives relating to competition in the system's markets, the company believes that its use of regulatory accounting remains appropriate. SFAS 121 requires that any assets, including regulatory assets, which are no longer probable of recovery through future revenues, be revalued based on estimated future cash flows. If the revaluation is less than the book value of the asset, an impairment loss would be charged to earnings. As noted above, based on the current regulatory environment in the company's service area, it is not expected that SFAS 121 will have material impact on the company's financial position or results of operations upon adoption. This conclusion may change in the future as competitive factors influence wholesale and retail pricing in the electric utility industry or if the cost-of-service based regulatory structure were to change. For further information on the company's regulatory environment, refer to Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A). The components of regulatory assets are as follows: At December 31, 1995 1994 --------------------------------------------------------------- (Thousands of Dollars) Recoverable energy costs (Note 1I) ... $220,093 $194,994 Income taxes, net (Note 1J) .......... 192,690 66,466 Unrecovered contractual obligation (Note 4) 18,814 28,572 Other ................................ 2,404 2,499 ---------- ---------- $434,001 $292,531 ======== ======== H. UNAMORTIZED ACQUISITION COSTS The unamortized acquisition costs represent the aggregate value placed by the 1989 rate agreement with the state of New Hampshire (Rate Agreement) on PSNH's assets in excess of the net book value of PSNH's non-Seabrook assets plus the $700-million value assigned to Seabrook by the Rate Agreement, as part of the bankruptcy resolution, on June 5, 1992 (Acquisition Date). The Rate Agreement provides for the recovery, through rates, with a return, of the amortization of the unamortized acquisition costs. The Rate Agreement provides that $425 million of the unamortized acquisition costs be amortized over the first seven years after PSNH's May 16, 1991 reorganization from bankruptcy (Reorganization Date), with the remaining amount to be amortized over the 20-year period after the Reorganization Date. As of December 31, 1995, approximately $411.8 million of acquisition costs have been collected through rates. I. RECOVERABLE ENERGY COSTS Under the Energy Policy Act of 1992 (Energy Act), PSNH is assessed for its proportionate share of the costs of decontaminating and decommissioning uranium enrichment plants owned by the United States Department of Energy (D&D assessment). The Energy Act requires that regulators treat D&D assessments as a reasonable and necessary current cost of fuel, to be fully recovered in rates, like any other fuel cost. PSNH is currently recovering these costs through rates. The Rate Agreement includes a comprehensive fuel and purchased power adjustment clause (FPPAC) permitting PSNH to pass through to retail customers, for a ten-year period, the retail portion of differences between the fuel and purchased power costs assumed in the Rate Agreement and PSNH's actual costs, which include the costs related to the Seabrook Power Contracts and the Clean Air Act Amendment. The cost components of the FPPAC are subject to a prudence review by the NHPUC. The costs associated with purchases from certain nonutility generators (NUGs) over the level assumed in the Rate Agreement are deferred and recovered through the FPPAC. PSNH has been renegotiating the rate orders mandating the purchase of high-cost NUG power. The NHPUC has approved an amendment to the Rate Agreement allowing settlement agreements to be implemented with two wood-fired NUGs. In 1994, the two NUGs that were settled gave up their rights to sell their output to PSNH in exchange for lump-sum cash payments totaling approximately $40 million. The deferred buyout payments are included as part of PSNH's recoverable energy costs. During the Rate Agreement's fixed-rate period, all of the savings from the buyout will be used to reduce PSNH's recoverable energy costs. At the end of the fixed-rate period, 50 percent of the savings will be used to reduce the recoverable energy costs, with the remainder reducing current rates. PSNH has also reached tentative agreements with the six remaining wood-fired NUGs. These agreements are subject to NHPUC approval. At December 31, 1995, PSNH's net recoverable energy costs were approximately $220 million, including purchased power deferrals of $185.6 million and the NUGs deferred buyout payments of $34.2 million. J. INCOME TAXES The tax effect of temporary differences (differences between the periods in which transactions affect income in the financial statements and the periods in which they affect the determination of income subject to tax) is accounted for in accordance with the ratemaking treatment of the applicable regulatory commissions. The adoption of SFAS 109, Accounting for Income Taxes, in 1993 increased the company's deferred tax asset for net operating losses (NOLs) previously not recognized. As the potential benefit is being given to customers through rates, PSNH established an associated regulatory liability. The adoption of SFAS 109 also increased deferred tax liabilities and as it is probable that the increase in deferred tax liabilities will be recovered from customers through rates, PSNH established a regulatory asset. The tax effect of temporary differences, including timing differences accrued under previously approved accounting standards, which give rise to the accumulated deferred tax obligation is as follows:
At December 31, 1995 1994 -------------------------------------------------------------------------------------- (Thousands of Dollars) Accelerated depreciation and other plant-related differences... $ 231,126 $ 81,732 NOL carryforwards ............................................ (191,873) (247,440) Regulatory assets - income tax gross up ...................... 85,192 33,837 Other ........................................................ 104,612 193,951 ---------- ---------- $ 229,057 $ 62,080 ========= ==========
At December 31, 1995, PSNH had a NOL carryforward of approximately $572 million, to be used against PSNH's federal taxable income, and to expire between the years 2000 and 2006. PSNH also had Investment Tax Credit (ITC) carryforwards of $52 million, which expire between the years 1996 and 2004. For a portion of the carryforward amounts indicated above, the reorganization of PSNH under Chapter 11 of the United States Bankruptcy Code limits the annual amount of NOL and ITC carryforwards that may be used. Approximately $95 million of the NOL and $21 million of the ITC carryforwards are subject to this limitation. K. DERIVATIVE FINANCIAL INSTRUMENTS PSNH utilizes an interest-rate cap to manage well-defined interest-rate risk. The premium paid for the purchased interest-rate-cap agreement is amortized to interest expense over the term of the cap. Unamortized premiums are included in deferred charges. Amounts receivable under the cap agreement are accrued and offset against interest expense. Any material unrealized gains or losses on the interest-rate cap will be deferred until realized. For further information on derivatives, see Note 11, "Derivative Financial Instruments." 2. SEABROOK POWER CONTRACTS PSNH and NAEC have entered into two power contracts that obligate PSNH to purchase NAEC's 35.98 percent ownership of the capacity and output of Seabrook for the term of Seabrook's Nuclear Regulatory Commission (NRC) operating license. Under these power contracts, PSNH is obligated to pay NAEC's cost of service during this period, regardless of whether Seabrook 1 is operating. NAEC's cost of service includes all of its Seabrook-related costs, including operation and maintenance (O&M) expenses, fuel expense, income and property tax expense, depreciation expense, and certain overhead and other costs, and a return on its allowed investment. PSNH has included its right to buy power from NAEC on its Balance Sheets as part of utility plant with a corresponding obligation. At December 31, 1995, this right was valued at approximately $910.8 million. The contracts established the value of the initial investment in Seabrook (initial investment) at $700 million. As of December 31, 1995, the portion of the initial investment on which NAEC is entitled to earn a cash return was 85 percent. The initial investment will be fully phased into NAEC's rate base as of May 1, 1996. From the Acquisition Date through December 31, 1995, NAEC recorded $162.4 million of deferred return on the excluded portion of its investment in Seabrook 1. The deferred return on the excluded portion of NAEC's investment in Seabrook 1 will be recovered from PSNH with carrying charges beginning December 1, 1997, and will be fully recovered by May 2001. NAEC is depreciating its initial investment over the term of Seabrook 1's operating license (39 years), and any subsequent plant additions are depreciated on a straight-line basis over the remaining term of the power contracts at the time the subsequent additions are placed in service. If Seabrook 1 is shut down prior to the expiration of the NRC operating license, PSNH will be unconditionally required to pay NAEC termination costs for 39 years, less the period during which Seabrook 1 has operated. These termination costs will reimburse NAEC for its share of Seabrook 1 shut-down and decommissioning costs, and will pay NAEC a return of and on any undepreciated balance of its initial investment over the remaining term of the power contracts, and the return of and on any capital additions to the plant made after the Acquisition Date over a period of five years after shut down (net of any tax benefits to NAEC attributable the cancellation). Contract payments charged to operating expenses are approximately: Year Contract Payments ---- ----------------- (Thousands of Dollars) 1995 ....................... $154,000 1994 ....................... 143,000 1993 ....................... 123,000 Interest included in the contract payments was $51 million in 1995, $43 million in 1994, and $33 million in 1993. Future minimum payments, excluding executory costs, such as property taxes, state use taxes, insurance, and maintenance, under the terms of the contracts, as of December 31, 1995, are approximately: Year Seabrook Power Contracts ---- ------------------------ (Thousands of Dollars) 1996 ........................ $ 79,900 1997 ........................ 86,000 1998 ........................ 143,800 1999 ........................ 142,100 2000 ........................ 140,300 After 2000 .................. 1,195,800 ---------- Future minimum payments ..... 1,787,900 Less amount representing interest 877,100 ----------- Present value of Seabrook Power Contracts ................. $ 910,800 =========== 3. LEASES PSNH has entered into lease agreements, some of which are capital leases, for the use of data processing and office equipment, vehicles, and office space. The provisions of these lease agreements generally provide for renewal options. The following rental payments have been charged to operating expense: Year Capital Leases Operating Leases ---- -------------- ---------------- 1995 ........................ $1,103,000 $5,291,000 1994 ........................ 1,061,000 4,255,000 1993 ........................ 701,000 6,197,000 Interest included in capital leases was $351,000 in 1995, $394,000 in 1994, and $403,000 in 1993. Future minimum rental payments, excluding executory costs, such as property taxes, state use taxes, insurance, and maintenance, under long-term noncancellable leases, as of December 31, 1995, are: Year Capital Leases Operating Leases ---- -------------- ---------------- (Thousands of Dollars) 1996 ........................ $1,100 $7,200 1997 ........................ 1,100 6,100 1998 ........................ 1,000 4,800 1999 ........................ 700 4,100 2000 ........................ 500 3,600 After 2000 .................. 1,200 11,500 ------- -------- Future minimum lease payments $5,600 $37,300 ======= Less amount representing interest 1,100 ----- Present value of future minimum lease payments .................. $4,500 ====== 4. NUCLEAR DECOMMISSIONING Millstone 3 and Seabrook 1 have service lives that are expected to end during the years 2025 and 2026, respectively. Upon retirement, these units must be decommissioned. A 1992 decommissioning study concluded that complete and immediate dismantlement at retirement continues to be the most viable and economic method of decommissioning Millstone 3. A 1994 Seabrook decommissioning study confirmed that complete and immediate dismantlement at retirement is the most viable and economic method of decommissioning Seabrook 1. Decommissioning studies are reviewed and updated periodically to reflect changes in decommissioning requirements, costs, technology, and inflation. The estimated cost of decommissioning PSNH's 2.85 percent ownership share of Millstone 3 and NAEC's 35.98 percent share of Seabrook 1, in year-end 1995 dollars, is $12.5 million and $152.5 million, respectively. These estimated costs assume levelized collections for Millstone 3 and escalated collections for Seabrook 1, and after-tax earnings on the Millstone and Seabrook decommissioning funds of 6.5 percent and 6.1 percent, respectively. Millstone 3 and Seabrook 1 decommissioning costs will be increased annually by their respective escalation rates. PSNH's Millstone 3 decommissioning costs are accrued over the expected service life of the unit and are included in depreciation expense on its Statements of Income. Nuclear decommissioning related to PSNH's share of Millstone 3 amounted to $0.3 million in 1995, 1994, and 1993. Nuclear decommissioning, as a cost of removal, is included in the accumulated provision for depreciation on PSNH's Balance Sheets. At December 31, 1995, the balance in the accumulated reserve for decommissioning amounted to $2.4 million. See "Nuclear Decommissioning" in the MD&A for a discussion of changes being considered by the FASB related to accounting for closure and removal of long-lived assets (including nuclear decommissioning). PSNH makes payments to an independent decommissioning trust for its portion of the costs of decommissioning Millstone 3. Under the terms of the Rate Agreement, PSNH is obligated to pay NAEC's share of Seabrook 1's decommissioning costs, even if the unit is shut down prior to the expiration of its operating license. Accordingly, NAEC bills PSNH directly for its share of the costs of decommissioning Seabrook 1. PSNH records its Seabrook decommissioning costs as a component of purchased power expense on its Statements of Income. Under the Rate Agreement, PSNH's Seabrook decommissioning costs are recovered through base rates. As of December 31, 1995, PSNH collected through rates approximately $1.8 million toward the future decommissioning costs of its share of Millstone 3, which has been transferred to the external decommissioning trust. Earnings on the decommissioning trust increase the decommissioning trust balance and the accumulated reserve for decommissioning. Unrealized gains and losses associated with the decommissioning trust also impact the balance of the trust and the accumulated reserve for decommissioning. As of December 31, 1995, NAEC (including payments made prior to the Acquisition Date by PSNH) has paid approximately $13.1 million, into Seabrook 1's decommissioning financing fund. Changes in requirements or technology, the timing of funding or dismantling, or adoption of a decommissioning method other than immediate dismantlement would change decommissioning cost estimates and the amounts required to be recovered. PSNH attempts to recover sufficient amounts through its allowed rates to cover its expected decommissioning costs. Only the portion of currently estimated total decommissioning costs that has been accepted by regulatory agencies is reflected in rates of PSNH. Based on present estimates and assuming its nuclear units operate to the end of their licensing period, PSNH expects that the decommissioning trust and financing fund will be substantially funded when the units are retired from service. PSNH, along with other New England utilities, has equity investments in the four Yankee companies. Each Yankee company owns a single nuclear generating unit with service lives that are expected to end during the years 2007 through 2012. PSNH's ownership share of estimated costs, in year-end 1995 dollars, of decommissioning the units owned and operated by CY, MY, and VY is $19.3 million, $17.7 million, and $13.9 million, respectively. Under the terms of the contracts with the Yankee companies, the shareholders-sponsors are responsible for their proportionate share of the operating costs of each unit, including decommissioning. The nuclear decommissioning costs of the Yankee companies are included as part of the cost of power purchased by PSNH. YAEC is in the process of dismantling its nuclear facility. Accelerated decommissioning of that unit has been delayed because of litigation over the NRC's approval of YAEC's decommissioning plan. Effective November 1995, YAEC began billing its sponsors, including PSNH, amounts based on a revised estimate approved by the FERC that assumes decommissioning of the plant by the year 2000. This revised decommissioning estimate was based on access to the Barnwell, South Carolina low-level radioactive waste facility, changes in assumptions about earnings in decommissioning trust investments, and changes in other decommissioning cost assumptions. At December 31, 1995, the estimated remaining costs, including decommissioning, amounted to $268.8 million, of which PSNH's share was approximately $18.8 million. Management expects that PSNH will continue to be allowed to recover such FERC-approved costs from its customers. Accordingly, PSNH has recognized these costs as a regulatory asset, with corresponding obligations, on its Balance Sheets. 5. SHORT-TERM DEBT PSNH has credit lines totaling $125 million available through a revolving- credit agreement with a group of 19 banks. PSNH may borrow funds on a short-term revolving basis using either fixed-rate or standby loans. Fixed rates are set using competitive bidding. Standby loan rates are based upon several alternative variable rates. PSNH is obligated to pay a facility fee of 0.25 percent per annum on the total commitment. At December 31, 1995 and 1994, there were no borrowings under the agreement. These credit lines will expire in May 1996. PSNH is in the process of negotiating an increase and extension to the revolving credit agreement. Certain subsidiaries of NU, including PSNH, are members of the Northeast Utilities System Money Pool (Pool). The Pool provides a more efficient use of the cash resources of the system, and reduces outside short-term borrowings. NUSCO administers the Pool as agent for the member companies. Short-term borrowing needs of the member companies are first met with available funds of other member companies, including funds borrowed by NU parent. NU parent may lend to the Pool but may not borrow. Funds may be withdrawn from or repaid to the Pool at any time without prior notice. Investing and borrowing subsidiaries receive or pay interest based on the average daily Federal Funds rate. However, borrowings based on loans from NU parent bear interest at NU parent's cost and must be repaid based upon the terms of NU parent's original borrowing. At December 31, 1995 and 1994, PSNH had no outstanding borrowings from the Pool. Maturities of PSNH's short-term debt obligations were for periods of three months or less. The amount of short-term borrowings that may be incurred by PSNH is subject to periodic approval by the SEC under the 1935 Act. Under the SEC restrictions, PSNH was authorized, as of January 1, 1995 to incur short-term borrowings up to a maximum of $175 million. PSNH is seeking approval from the NHPUC to increase its short-term debt limit to $225 million. 6. PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION Details of preferred stock subject to mandatory redemption are: Shares Outstanding December 31, ---------------------------- Description December 31, 1995 1995 1994 1993 ------------------------------------------------------------------------ (Thousands of Dollars) 10.60% Series A of 1991 5,000,000 $125,000 $125,000 $125,000 ======== ======== ======== In case of default on dividends or sinking-fund payments, no payments may be made on any junior stock by way of dividends or otherwise (other than in shares of junior stock) so long as the default continues. If PSNH is in arrears in the payment of dividends on any outstanding shares of preferred stock, PSNH would be prohibited from redemption or purchase of less than all of the preferred stock outstanding. The Series A Preferred Stock is not subject to optional redemption by PSNH. It is subject to an annual sinking fund requirement of $25 million, beginning on June 30, 1997, sufficient to retire annually 1,000,000 shares at $25 per share. 7. LONG-TERM DEBT Details of long-term debt outstanding are: December 31, ------------ 1995 1994 ----------------------------------------------------------------------- (Thousands of Dollars) First Mortgage Bonds: 8 7/8% Series A, due 1996............ $172,500 $172,500 9.17% Series B, due 1998............ 170,000 170,000 -------- --------- Total First Mortgage Bonds.... 342,500 342,500 Term Loan/Notes: Variable Rate due 1996 .............. - 141,000 Pollution Control Revenue Bonds: 7.65% Tax-Exempt Series A, due 2021. 66,000 66,000 7.50% Tax-Exempt Series B, due 2021. 108,985 108,985 7.65% Tax-Exempt Series C, due 2021. 112,500 112,500 Adjustable Rate, Taxable, Series D, due 2021 39,500 39,500 Adjustable Rate, Taxable, Series E, due 2021 69,700 69,700 Adjustable Rate, Tax-Exempt, Series D, due 2021 75,000 75,000 Adjustable Rate, Tax-Exempt, Series E, due 2021 44,800 44,800 Less: Amounts due within one year .. 172,500 94,000 ---------- --------- Long-term debt, net ....... $686,485 $905,985 ======== ======== Long-term debt maturities and cash sinking-fund requirements on debt outstanding at December 31, 1995 for the years 1996 through 2000 are approximately $172.5 million for 1996, $0 for 1997, $170 million for 1998, and $0 for 1999 and 2000. Also, there are annual renewal and replacement fund requirements equal to 2.25 percent of the average of net depreciable property owned by PSNH at the reorganization date, plus cumulative gross property additions thereafter. PSNH expects to meet these future fund requirements by certifying property additions. Any deficiency would need to be satisfied by the deposit of cash or bonds. Essentially, all utility plant of PSNH is subject to the lien of its first mortgage bond indenture. PSNH's Revolving Credit Facility is secured by a second lien, junior to the lien of its first mortgage bond indenture, on all PSNH property located in New Hampshire. At December 31, 1995 and 1994, there were no borrowings under the Revolving Credit Facility. Concurrent with the issuance of PSNH's Series A and B First Mortgage Bonds, PSNH entered into financing arrangements with the Industrial Development Authority of the state of New Hampshire (IDA). Pursuant to these arrangements, the IDA originally issued seven series of Pollution Control Revenue Bonds (PCRBs), and loaned the proceeds to PSNH. In 1992 and 1993, the Business Finance Authority, formerly the IDA, issued $75 million and $44.8 million, respectively, of tax-exempt PCRBs to replace outstanding taxable PCRBs of the same amount. At December 31, 1995 and 1994, $516.5 million of PCRBs were outstanding. The average effective interest rates on the variable-rate pollution control notes ranged from 3.9 percent to 6.1 percent for 1995, and 2.9 percent to 4.3 percent for 1994. PSNH's obligation to repay each series of PCRBs is secured by a series of First Mortgage Bonds that were issued under its indenture. Each such series of First Mortgage Bonds contains terms and provisions with respect to maturity, principal payment, interest rate, and redemption that correspond to those of the applicable series of PCRBs. For financial reporting purposes, these bonds would not be considered outstanding unless PSNH fails to meet its obligations under the PCRBs. The Series A and B First Mortgage Bonds are not redeemable prior to their maturity except in limited circumstances. The PCRBs, except for Series D and E, are redeemable on or after May 1, 2001, at the option of the company with accrued interest and at specified premiums. Under current interest rate elections by PSNH, the Series D and E PCRBs are redeemable, at par plus accrued interest at the end of each interest-rate period. Future interest- rate elections by PSNH could significantly defer or eliminate the availability of optional redemptions by PSNH, and could affect costs as well. 8. INCOME TAX EXPENSE The components of federal and state income tax provisions are: For the Years Ended December 31, 1995 1994 1993 ------------------------------------------------------------------------- (Thousands of Dollars) Current income taxes: Federal ............................ $(1,166) $ 368 $ (937) State .............................. 1,767 1,219 1,183 ------- -------- -------- Total current .................... 601 1,587 246 ------- -------- -------- Deferred income taxes, net: Federal ............................ 72,147 63,941 47,407 State .............................. (1,606) 3,666 3,131 ------- -------- -------- Total deferred .................. 70,541 67,607 50,538 Investment tax credits, net .......... (555) (560) (565) --------- --------- --------- Total income tax expense ............. $70,587 $68,634 $50,219 ======= ======= ======= The components of total income tax expense are classified as follows: Income taxes charged to operating expenses $69,758 $68,088 $54,087 Other income taxes ................... 829 546 (3,868) -------- -------- -------- Total income tax expense ............. $70,587 $68,634 $50,219 ======= ======= ======= Deferred income taxes are comprised of the tax effects of temporary differences as follows: For the Years Ended December 31, 1995 1994 1993 -------------------------------------------------------------------------- (Thousands of Dollars) Depreciation ......................... $ 1,294 $ 2,701 $ 4,549 Deferred tax asset associated with NOL 57,543 23,611 25,438 Energy adjustment clauses ............ 5,098 30,954 15,155 Amortization of regulatory settlement 11,501 11,501 7,667 Other ................................ (4,895) (1,160) (2,271) -------- -------- -------- Deferred income taxes, net ........... $70,541 $67,607 $50,538 ======= ======= ======= A reconciliation between income tax expense and the expected tax expense at the applicable statutory rate is as follows: For the Years Ended December 31, 1995 1994 1993 -------------------------------------------------------------------------- (Thousands of Dollars) Expected federal income tax at 35 percent of pretax income ................... $53,845 $51,127 $35,860 Tax effect of differences: Depreciation ....................... 1,868 1,407 1,593 Amortization of acquisition costs .. 31,522 31,508 31,432 Seabrook intercompany loss ......... (13,048) (19,637) (19,176) Investment tax credit amortization . (555) (560) (565) State income taxes, net of federal benefit 105 3,175 2,804 Other, net ......................... (3,150) 1,614 (1,729) -------- -------- -------- Total income tax expense ............. $70,587 $68,634 $50,219 ======= ======= ======= 9. EMPLOYEE BENEFITS A. PENSION BENEFITS PSNH participates in a uniform noncontributory-defined benefit retirement plan covering all regular system employees. Benefits are based on years of service and employees' highest eligible compensation during five consecutive years of employment. The company's direct portion of the system's pension cost, part of which was charged to utility plant, approximated $2.3 million in 1995, $4.4 million in 1994, and $6.6 million in 1993. Pension costs for 1994 and 1993 included approximately $1.9 million and $3.4 million, respectively, related to workforce-reduction programs. Currently, PSNH funds annually an amount at least equal to that which will satisfy the requirements of the Employee Retirement Income Security Act and the Internal Revenue Code. Pension costs are determined using market-related values of pension assets. Pension assets are invested primarily in domestic and international equity securities and bonds. The components of net pension cost for PSNH are:
For the Years Ended December 31, 1995 1994 1993 --------------------------------------------------------------------------- (Thousands of Dollars) Service cost ...................... $ 3,462 $ 5,531 $ 7,539 Interest cost ..................... 11,923 11,129 11,180 Return on plan assets ............. (33,156) 246 (19,308) Net amortization .................. 20,108 (12,526) 7,215 -------- -------- --------- Net pension cost .................. $ 2,337 $ 4,380 $ 6,626 ======== ======== ======== ---------------------------------------------------------------
For calculating pension cost, the following assumptions were used: For the Years Ended December 31, 1995 1994 1993 ------------------------------------------------------------------- Discount rate ..................... 8.25% 7.75% 8.00% Expected long-term rate of return . 8.50 8.50 8.50 Compensation/progression rate ..... 5.00 4.75 5.00 The following table represents the plan's funded status reconciled to the Balance Sheets: At December 31, 1995 1994 ----------------------------------------------------------------------- (Thousands of Dollars) Accumulated benefit obligation, including vested benefits at December 31, 1995 and 1994 of $123,475,000 and $111,198,000, respectively $133,840 $121,202 ======== ======== Projected benefit obligation (PBO) .... $169,040 $146,972 Market value of plan assets ........... 159,094 136,104 -------- -------- PBO in excess of plan assets .......... (9,946) (10,868) Unrecognized transition amount ........ 4,671 5,004 Unrecognized prior service costs ...... 5,428 5,775 Unrecognized net gain ................. (38,759) (36,180) --------- --------- Accrued pension liability ............. $(38,606) $(36,269) ======== ======== ------------------------------------------------------------------------- The following actuarial assumptions were used in calculating the plan's year-end funded status: For the Years Ended December 31, 1995 1994 --------------------------------------------------------------- Discount rate ......................... 7.50% 8.25% Compensation/progression rate ......... 4.75 5.00 B. POSTRETIREMENT BENEFITS OTHER THAN PENSIONS PSNH provides certain health care benefits, primarily medical and dental, and life insurance benefits through a benefit plan to retired employees (referred to as SFAS 106 benefits). These benefits are available for employees retiring from the company who have met specified service requirements. For current employees and certain retirees, the total SFAS 106 benefit is limited to two times the 1993 per-retiree health care costs. The SFAS 106 obligation has been calculated based on this assumption. PSNH's direct portion of SFAS 106 benefits, part of which were deferred or charged to utility plant, approximated $7.2 million in 1995, $7.6 million in 1994, and $9.1 million in 1993. PSNH is funding SFAS 106 postretirement costs through external trusts. The company is funding, on an annual basis, amounts that have been rate- recovered and which also are tax-deductible under the Internal Revenue Code. The trust assets are invested primarily in equity securities and bonds. The components of health care and life insurance costs are:
For the Years Ended December 31, 1995 1994 1993 --------------------------------------------------------------------------- (Thousands of Dollars) Service cost .................. $ 933 $ 971 $1,260 Interest cost ................. 4,063 3,844 4,800 Return on plan assets ......... (1,694) 37 - Amortization of unrecognized transition obligation .................. 2,941 2,941 3,046 Other amortization, net ....... 998 (206) - ------- -------- --------- Net health care and life insurance costs $7,241 $7,587 $9,106 ====== ====== ====== ---------------------------------------------------------------
For calculating PSNH's SFAS 106 benefits cost, the following assumptions were used: For the Years Ended December 31, 1995 1994 1993 ------------------------------------------------------------------ Discount rate ................. 8.00% 7.75% 7.75% Long-term rate of return: Health assets, net of tax .. 5.00 5.00 5.00 Life assets ................ 8.50 8.50 8.50 The following table represents the plan's funded status reconciled to the Balance Sheet: At December 31, 1995 1994 ------------------------------------------------------------------------- (Thousands of Dollars) Accumulated postretirement benefit obligation of: Retirees ................... $ 44,985 $ 39,881 Fully eligible active employees 27 52 Active employees not eligible to retire 10,627 9,065 -------- ---------- Total accumulated postretirement benefit obligation 55,639 48,998 Market value of plan assets ... 11,743 6,606 --------- ---------- Accumulated postretirement benefit obligation in excess of plan assets .............. (43,896) (42,392) Unrecognized transition amount 49,989 52,930 Unrecognized net gain ........ (8,373) (13,204) -------- -------- Accrued postretirement benefit liability $ (2,280) $ (2,666) ========= ======== ------------------------------------------------------------------------ The following actuarial assumptions were used in calculating the plan's year-end funded status: At December 31, 1995 1994 -------------------------------------------------------------------- Discount rate ......................... 7.50% 8.00% Health care cost trend rate (a) ....... 8.40 10.20 (a) The annual growth in per capita cost of covered health care benefits was assumed to decrease to 5.4 percent by 2001. The effect of increasing the assumed health-care-cost trend rate by one percentage point in each year would increase the accumulated postretirement benefit obligation as of December 31, 1995 by $3.7 million and the aggregate of the service and interest cost components of net periodic postretirement benefit cost for the year then ended by $0.3 million. The trust holding the plan assets is subject to federal income taxes at a 35 percent tax rate. PSNH is currently recovering SFAS 106 costs, including amounts previously deferred. 10. COMMITMENTS AND CONTINGENCIES A. CONSTRUCTION PROGRAM The construction program is subject to periodic review and revision. PSNH currently forecasts construction expenditures of $200.9 million for the years 1996-2000, including $51.5 million for 1996. In addition, the company estimates that nuclear fuel requirements, for its share of Millstone 3, will be $4.8 million for the years 1996-2000, including $1.8 million for 1996. B. NUCLEAR PERFORMANCE On January 31, 1996, the NRC announced that the three Millstone nuclear power plants operated by NNECO had been placed on its "watch list" because of long-standing performance concerns. The NRC cited a number of operational problems which have arisen since 1990 at the Millstone plants. The NRC recognized that there are significant current variations in the performance of the three units. The performance concerns cited by the NRC, combined with NU's failure to maintain previous performance improvements, have resulted in the NRC requiring close monitoring of Millstone unit operations and the implementation of a corrective action program. While the NRC has not specifically restricted operations at the Millstone site, the company expects that there will be costs associated with the NRC's actions that cannot accurately be estimated at this time. C. ENVIRONMENTAL MATTERS PSNH is subject to regulation by federal, state, and local authorities with respect to air and water quality, handling the disposal of toxic substances and hazardous and solid wastes, and the handling and use of chemical products. PSNH has an active environmental auditing and training program and believes that it is in substantial compliance with current environmental laws and regulations. Environmental requirements could hinder the construction of new generating units, transmission and distribution lines, substations, and other facilities. The cumulative long-term, cost impact of increasingly stringent environmental requirements cannot accurately be estimated. Changing environmental requirements could also require extensive and costly modifications to PSNH's existing generating units, and transmission and distribution systems, and could raise operating costs significantly. As a result, PSNH may incur significant additional environmental costs, greater than amounts included in cost of removal and other reserves, in connection with the generation and transmission of electricity and the storage, transportation, and disposal of by- products and wastes. PSNH may also encounter significantly increased costs to remedy the environmental effects of prior waste handling activities. PSNH has recorded a liability for what it believes, based upon information currently available, are its estimated environmental remediation costs for waste disposal sites. In most cases, additional future environmental cleanup costs are not reasonably estimable due to a number of factors, including the unknown magnitude of possible contamination, the appropriate remediation methods, the possible effects of future legislation or regulation, and the possible effects of technological changes. At December 31, 1995, the liability recorded by PSNH for its estimated environmental remediation costs, excluding any possible insurance recoveries or recoveries from third parties, amounted to approximately $5.0 million. PSNH cannot estimate the potential liability for future claims, including environmental remediation costs, that may be brought against it. However, considering known facts, existing laws, and regulatory practices, management does not believe the matters disclosed above will have a material effect on PSNH's financial position or future results of operations. D. NUCLEAR INSURANCE CONTINGENCIES Under certain circumstances, in the event of a nuclear incident at one of the nuclear facilities covered by the federal government's third- party liability indemnification program, the company could be assessed in proportion to its ownership interest in each nuclear unit up to $75.5 million, not to exceed $10 million per nuclear unit in any one year. The maximum assessment is to be adjusted at least every five years for inflationary changes. Under the terms of the power contracts with NAEC, PSNH could be obligated to pay for any assessment charged to NAEC as a "cost of service." Based on the ownership interest in Millstone 3 and NAEC's ownership interest in Seabrook 1, PSNH's maximum liability, including any additional potential assessments, would be $30.8 million per incident. In addition, through power purchase contracts with the three operating Yankee regional nuclear generating companies, PSNH would be responsible for up to an additional $11.1 million per incident. Payments for PSNH's ownership interest in nuclear generating facilities would be limited to a maximum of $5.3 million per incident per year. Insurance has been purchased to cover the primary cost of repair, replacement, or decontamination of utility property resulting from insured occurrences at Millstone 3. PSNH is subject to retroactive assessments if losses exceed the accumulated funds available to the insurer. The maximum potential assessment against PSNH with respect to losses arising during the current policy year is approximately $0.5 million under the primary property insurance program. Insurance has been purchased to cover certain extra costs incurred in obtaining replacement power during prolonged accidental outages and the excess cost of repair, replacement, or decontamination or premature decommissioning of utility property resulting from insured occurrences. PSNH is subject to retroactive assessments if losses exceed the accumulated funds available to the insurer. The maximum potential assessments against PSNH (including costs resulting from PSNH's contracts with NAEC), with respect to losses arising during current policy years are approximately $1.6 million under the replacement power policies and $11.1 million under the excess property damage, decontamination, and decommissioning policies. Although PSNH has purchased the limits of coverage currently available from the conventional nuclear insurance pools, the cost of a nuclear incident could exceed available insurance proceeds. Insurance has been purchased aggregating $200 million on an industry basis for coverage of worker claims. All participating reactor operators insured under this coverage are subject to retrospective assessments of $3.0 million per reactor. The maximum potential assessment against PSNH (including costs resulting from the Seabrook power contracts with NAEC), with respect to losses arising during the current policy period is approximately $1.8 million. E. LONG-TERM CONTRACTUAL ARRANGEMENTS Yankee Companies: PSNH, along with CL&P and WMECO, purchased approximately 6.7 percent of their electricity requirements pursuant to long-term contracts with the Yankee companies. Under the terms of their agreements, the companies pay their ownership (or entitlement) shares of generating costs, which include depreciation, O&M expenses, taxes, the estimated cost of decommissioning, and a return on invested capital. These costs are recorded as purchased-power expense and recovered through the companies' rates. PSNH's total cost of purchases under these contracts for the units that are operating amounted to $26.4 million in 1995, $23.4 million in 1994, and $26.5 million in 1993. See Note 1C, "Summary of Significant Accounting Policies-Investments and Jointly Owned Electric Utility Plant," and Note 4, "Nuclear Decommissioning," for more information on the Yankee companies. Nonutility Generators: PSNH has entered into various arrangements for the purchase of capacity and energy from NUGs. These arrangements have terms from 20 to 30 years, currently expiring in the years 1998 through 2023, and require PSNH to purchase the energy at specified prices or formula rates. For the 12 months ended December 31, 1995, approximately 13 percent of system electricity requirements was met by NUGs. PSNH's total cost of purchases under these arrangements amounted to $129.6 million in 1995, $130.0 million in 1994, and $133.4 million in 1993. These costs are eventually recovered through the company's rates. For additional information, see Note 1I, "Summary of Significant Accounting Policies-Recoverable Energy Costs." New Hampshire Electric Cooperative: PSNH entered into a buy-back agreement to purchase the capacity and energy of the New Hampshire Electric Cooperative, Inc.'s (NHEC) share of Seabrook 1 and to pay all of NHEC's Seabrook 1 costs for a ten-year period, which began July 1, 1990. The total cost of purchases under this agreement was $15.8 million in 1995, $14.6 million in 1994, and $14.4 million in 1993. A portion of these costs is collected currently through the FPPAC and the remaining costs are deferred for future collection in accordance with the Rate Agreement. In connection with the agreement, NHEC agreed to continue as a firm-requirements customer of PSNH for 15 years. Hydro-Quebec: Along with other New England utilities, PSNH, CL&P, WMECO, and HWP entered into agreements to support transmission and terminal facilities to import electricity from the Hydro-Quebec system in Canada. PSNH is obligated to pay, over a 30-year period ending in 2020, its proportionate share of the annual O&M and capital costs of these facilities. The estimated annual costs of PSNH's significant long-term contractual arrangements are as follows: 1996 1997 1998 1999 2000 -------------------------------------------------------------------- (Millions of Dollars) Yankee Companies $25.4 $25.8 $27.7 $27.6 $29.6 Nonutility Generators 130.3 134.5 137.9 141.4 145.4 NHEC .......... 14.6 22.5 29.5 29.7 14.6 Hydro-Quebec .. 11.2 10.6 10.3 10.0 9.9 F. DEFERRED RECEIVABLE FROM AFFILIATED COMPANY At the time PSNH emerged from bankruptcy on May 16, 1991, in accordance with the phase-in under the Rate Agreement, it began accruing a deferred return on a portion of its Seabrook investment. From May 16, 1991 to the Acquisition Date, PSNH accrued a deferred return of $50.9 million. On the Acquisition Date, PSNH sold the $50.9 million deferred return to NAEC as part of the Seabrook-related assets. At the time PSNH transferred the deferred return to NAEC, it realized, for income tax purposes, a gain that is deferred under the consolidated income tax rules. This gain will be restored for income tax purposes when the deferred return of $50.9 million, and the associated income taxes of $32.9 million, are collected by NAEC through the Seabrook power contracts. When NAEC recovers the $32.9 million in years eight through ten of the Rate Agreement, it is obligated to make corresponding payments to PSNH. On the Acquisition Date, PSNH recorded the $32.9 million of income taxes associated with the deferred return as a deferred receivable from NAEC, with a corresponding entry to deferred revenue, on its Balance Sheet. In 1993, due to changes in tax rates, this amount was adjusted to $33.3 million. 11. DERIVATIVE FINANCIAL INSTRUMENTS The company utilizes derivative financial instruments to manage well-defined interest-rate risks. The company does not use them for trading purposes. PSNH has entered into an interest-rate cap contract with a financial institution in order to reduce a portion of the interest-rate risk associated with certain variable-rate tax-exempt pollution control revenue bonds, as well as a portion of the PSNH Variable-Rate Term Loan. During 1995, there was one outstanding contract held by PSNH, covering $75 million of its variable rate debt, which expired in January 1996. The contract entitled PSNH to receive from its counterparties the amount, if any, by which the interest payments on its variable-rate tax-exempt pollution control revenue bond exceeds the J. J. Kenny High Grade Index and the PSNH Variable-Rate Term Loan exceeds the three-month LIBOR rate. Due to its upcoming expiration, as of December 31, 1995, the total fair market value of this cap was $0. 12. FAIR VALUE OF FINANCIAL INSTRUMENTS The following methods and assumptions were used to estimate the fair value of each of the following financial instruments: Cash and nuclear decommissioning trusts: The carrying amounts approximate fair value. SFAS 115, Accounting for Certain Investments in Debt and Equity Securities, requires investments in debt and equity securities to be presented at fair value and was adopted by PSNH on a prospective basis as of January 1, 1994. Unrealized gains and losses resulting from the adoption of SFAS 115 have not been material. There was no change in funding requirements of the trusts nor any impact on earnings as a result of the adoption of SFAS 115. Preferred stock and long-term debt: The fair value of PSNH's securities is based upon the quoted market price for those issues or similar issues. Adjustable rate securities are assumed to have a fair value equal to their carrying value. The carrying amounts of PSNH's financial instruments and the estimated fair values are as follows: Carrying Fair At December 31, 1995 Amount Value ------------------------------------------------------------------------ (Thousands of Dollars) Preferred stock subject to mandatory redemption $125,000 $131,250 Long-term debt - First Mortgage Bonds .... 342,500 352,517 Other long-term debt ..................... 516,485 532,190 ------------------------------------------------------------------------ Carrying Fair At December 31, 1994 Amount Value ------------------------------------------------------------------------ (Thousands of Dollars) Preferred stock subject to mandatory redemption $125,000 $127,500 Long-term debt - First Mortgage Bonds .... 342,500 342,931 Other long-term debt ..................... 657,485 641,673 The fair values shown above have been reported to meet the disclosure requirements and do not purport to represent the amounts at which those obligations would be settled. To the Board of Directors of Public Service Company of New Hampshire: We have audited the accompanying balance sheets of Public Service Company of New Hampshire (a New Hampshire corporation and a wholly owned subsidiary of Northeast Utilities) as of December 31, 1995 and 1994, and the related statements of income, common stockholder's equity, 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 Public Service Company of New Hampshire 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. /s/ Arthur Andersen LLP ARTHUR ANDERSEN LLP Hartford, Connecticut February 16, 1996 PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - ---------------------------------------------------------------------- This section contains management's assessment of PSNH's (the company) financial condition and the principal factors having an impact on the results of operations. The company is a wholly owned subsidiary of Northeast Utilities (NU). This discussion should be read in conjunction with the company's financial statements and footnotes. FINANCIAL CONDITION OVERVIEW Net income was approximately $83 million in 1995, an increase of approximately $6 million, from approximately $77 million in 1994. The 1995 net income was higher primarily due to higher revenues from the sixth step of PSNH's Rate Agreement and higher base fuel recoveries, partially offset by higher capacity charges under the Seabrook Power Contract, higher purchased power, and higher income taxes. Retail kilowatt-hour sales rose by only 0.4 percent in 1995 as a result of a flat economy in New England. With the New England economy not forecasted to grow substantially during 1996, sales levels are expected to remain flat. PSNH acts as both a buyer and a seller of electricity in the highly competitive wholesale electricity market in the Northeast. Increased competition has made the renegotiation of expiring wholesale contracts, as well as the signing of new contracts, financially challenging. During 1995, the Federal Energy Regulatory Commission issued a proposal for restructuring the electric-power industry which calls for open access to transmission facilities, a standard formula for calculating rates, and full recovery of stranded investments. The impact on PSNH of this proposal, which is expected to be finalized in 1996, is not known at this time. During 1995, the Coalition of Northeastern Governors released its report addressing the restructuring of the electric-power industry and its resulting impact on customers and states. The report presented the future as one in which there would be some form of continued regulation for transmission and distribution with fully competitive generation. In 1995, the New Hampshire Legislature created a committee to review the industry's structure and called for the New Hampshire Public Utilities Commission (NHPUC) to initiate a retail wheeling pilot program. Under the current NHPUC proposal, the program, which is expected to begin in 1996, will initially impact 3 percent of PSNH's peak retail electric load, but only allows for a 50-percent recovery of PSNH's potentially strandable costs. PSNH and the NHPUC Staff have entered into a joint recommendation that, if approved by the NHPUC, would govern PSNH's participation in the retail wheeling pilot program. Under this settlement, PSNH would provide competing electric suppliers access to 3 percent of its retail customers. PSNH would recover 100 percent of its potentially strandable costs via a delivery charge, but would provide a 10- percent incentive credit off its traditional rates to encourage customer participation in the two-year program. PSNH is taking a proactive role in the electric-power industry's movement toward competition. PSNH has outlined a comprehensive approach to enhancing customer satisfaction and market efficiency while moving toward full competition in the electricity marketplace. The approach calls for several significant changes in electricity pricing, the ability to introduce new products and services, the method of rate-setting, and the operation of the New England Power Pool. The plan also calls for the phase-in of supplier choices through the use of pilot programs. Management believes that a fully competitive market for electricity should begin once all issues relating to the transition from traditional utility regulation have been thoroughly addressed. In addition to the formulation of this approach and ongoing meetings with legislators, regulators, and others in the industry, PSNH is moving ahead in other areas, including revenue enhancement initiatives, and cost reductions, to better position itself for an increasingly competitive environment. A comprehensive companywide effort, which started in 1994, to reengineer PSNH's business and operating processes continued throughout 1995. PSNH expects that this effort will have significant positive effects on operating costs and customer service. Many of the organizational changes in the operating and service functions announced in 1995 and early 1996 are consistent with the initial recommendations of the reengineering teams. While PSNH's reengineering efforts will be reduced in 1996, implementation costs relating to the previous reengineering efforts are expected to increase. With retail electric revenues accounting for approximately 80 percent of its 1995 revenues, PSNH has continued to develop a number of initiatives to retain and serve its existing customers and to expand its retail customer base. The most visible result of these efforts is the expansion of the Retail Marketing organization. Retail Marketing's mission is to better understand the needs and concerns of PSNH's retail customer and to develop innovative approaches to addressing these issues. These initiatives include providing discounts to certain customers for signing economic development and competitive generation- based contracts, offering demand-side-management services, and providing additional products and services. WORKFORCE REDUCTIONS In January 1996, NU completed its nuclear workforce reduction plan. Approximately 220 positions were eliminated through a combination of early retirements, attrition and layoffs. The total pretax cost of the workforce reduction, to the NU system, which was recognized in 1995, was approximately $9 million. RATE MATTERS PSNH follows accounting principles in accordance with Statement of Financial Accounting Standards (SFAS) 71, "Accounting for the Effects of Certain Types of Regulation" that allows the economic effects of rate regulation to be reflected. Under these principles, regulators may permit incurred costs for certain events or transactions, which would be treated as expenses by nonregulated enterprises, to be deferred as regulatory assets and recovered in revenues at a later date. The creation of these regulatory assets has kept down electric rates in past years, at the expense of having higher rates in the future. At December 31, 1995, PSNH's regulatory assets totaled approximately $430 million. The largest regulatory assets are related to the future recovery of energy cots, approximately $220 million, and income taxes, approximately $193 million. The substantial costs of amortizing these regulatory assets would hinder PSNH from competing effectively in an openly competitive electric market if customers are not required to pay such costs. Given the increasingly competitive nature of the industry and increased activity in the regulatory environment, PSNH has made the recovery of regulatory assets one of its central financial strategies, while balancing the customer's pricing needs with NU's shareholder's earnings requirements. Under its existing rate agreement, PSNH is allowed to recover a significant portion of its regulatory assets during the next five years. However, maintaining the present recovery level is dependent upon the outcome of negotiations between PSNH and the NHPUC when its current rate agreement expires. As the expiration of PSNH's current rate agreement approaches, negotiations will be held between PSNH and the NHPUC to determine whether, or to what extent, rates should be adjusted going forward. PSNH's strategy during these negotiations will be to maintain stable rates, applying any available earnings that may result to reduce the balance of its regulatory assets. Management is unable to predict the ultimate outcome of these negotiations, which will be subject to NHPUC approval. In March 1995, the Financial Accounting Standards Board (FASB) issued SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of." SFAS 121, which was effective January 1, 1996, requires assets, including regulatory assets, that are no longer probable of recovery through future revenues be charged to earnings. If future competition or regulatory actions cause any portion of its operations to no longer be subject to SFAS 71, PSNH would be required to determine the fair value of the related regulatory assets and liabilities and record any necessary write-downs. Additionally, if events create uncertainty about the recoverability of any of PSNH'S remaining long-lived assets, a similar analysis would be required for those assets in accordance with SFAS 121. Under its current regulatory environment, PSNH believes that its use of SFAS 71 remains appropriate and that the adoption of SFAS 121 will not have a material impact on its financial position or results of operations. See the "Notes to Financial Statements," Note 1G, for further details on regulatory accounting. In June 1995, PSNH's base rates increased by 5.5 percent under the sixth step of a seven-year 1989 rate agreement approved by the NHPUC. In November 1995, the NHPUC authorized a PSNH request to reduce its Fuel and Purchased Power Adjustment Clause (FPPAC) rate, which took effect on December 1, 1995, and will continue through May 31, 1996. The decision reduced PSNH's overall rates by approximately 2.6 percent. In 1995, PSNH completed installation of equipment to comply with the Clean Air Act Amendments of 1990. The capitalized cost of the installation was approximately $25 million, and will cause PSNH to spend approximately $4 million annually for additional operation and maintenance costs. In April 1995, the NHPUC began proceedings to determine whether these costs are recoverable from customers. The NHPUC is allowing PSNH to recover these costs through the FPPAC, subject to refund, pending a final decision. The costs associated with purchases by PSNH from certain nonutility generators (NUGs) over the level assumed in rates are deferred for recovery over ten-year periods through the FPPAC. PSNH is attempting to renegotiate these arrangements with the NUGs. At December 31, 1995, the unrecovered deferral was approximately $192 million, including buyout payments of approximately $34 million for two of PSNH's eight wood-fired NUGs. By December 31, 1995, PSNH had reached agreements with the owners of the remaining six wood-fired NUGs. If consummated, these agreements could result in net savings of approximately $430 million to PSNH's customers over a period of 20 years following guaranteed payments of approximately $250 million. Management will reevaluate whether to proceed with these agreements if the NHPUC fails to provide for full recovery of stranded costs. NUCLEAR PERFORMANCE On January 31, 1996, the Nuclear Regulatory Commission (NRC) placed Millstone 1, 2, and 3 (Millstone) on its "watch list." The NRC's action was in response to a number of performance concerns which have arisen since 1990 and a failure to resolve employee safety concerns. The NRC's action will result in close monitoring of programs and performance at Millstone to assure the development and implementation of effective corrective actions. NU's management plans to continue its extensive efforts already underway to address these concerns. Concurrent with the NRC's action, NU provided the NRC with the results of a comprehensive self-assessment review of the employee concern program at Millstone. Additionally, in January 1996, NU announced a reorganization of its nuclear operations which included the creation of a new office of Nuclear Safety and Oversight. Operations at Millstone 3 have not been restricted by its placement on the "watch list". NU's management expects that the increased NRC attention will inevitably have effects and costs that are not known at this time. The Seabrook plant operated at 83.2 percent of capacity for the year ended December 31, 1995, compared with 61.6 percent in 1994 and a 1995 national average of 77.6 percent. The higher 1995 capacity factor was primarily the result of unplanned and extended outages in 1994 compared to only a 37.5-day planned refueling and maintenance outage in 1995, the unit's shortest to date. ENVIRONMENTAL MATTERS NU devotes substantial resources to identify and comply with the multitude of environmental requirements it faces. NU has active auditing programs addressing a variety of regulatory requirements, including an environmental auditing program to detect and remedy noncompliance with environmental laws or regulations. PSNH is potentially liable for environmental cleanup costs at a number of sites both inside and outside its service territory. To date, the future estimated environmental remediation liability has not been material with respect to the earnings or financial position of PSNH. At December 31, 1995, the company had recorded an environmental reserve amounting to approximately $5 million, as required under SFAS 5, ``ccounting for Contingencies.'' These costs could be significantly higher if alternative remedies become necessary. NUCLEAR DECOMMISSIONING PSNH's estimated cost to decommission its 2.85 percent share of Millstone 3 and NAEC's 35.98 percent share of Seabrook 1 is approximately $13 million and $153 million, respectively, in year-end 1995 dollars. These costs are being recognized over the lives of the respective units and a portion is being recovered through rates. Under the terms of the Rate Agreement, the company is obligated to pay NAEC's share of Seabrook's decommissioning costs, even if the unit is shut down prior to the expiration of its operating license. The FASB is currently reviewing the accounting for closure and removal costs, including decommissioning and similar costs, for long-lived assets. If current electric-power industry accounting practices for such decommissioning costs were changed, annual provisions for decommissioning would increase and the estimated costs for decommissioning would be recorded as a liability rather than as a component of accumulated depreciation. See the "Notes to Financial Statements," Note 4, for further information on nuclear decommissioning, including PSNH's share of costs to decommission the regional nuclear generating units . LIQUIDITY AND CAPITAL RESOURCES Cash provided from operations increased approximately $58 million in 1995, from 1994, primarily due to the 1994 payments to the NUGs. Cash used for financing activities increased approximately $97 million in 1995, from 1994, primarily due to the repayment of the Term Loan and the payment of its first common stock dividends in 1995. Cash used for investments decreased approximately $44 million in 1995, from 1994, primarily due to an increase in short-term loans to other NU system companies under the NU system Money Pool. The company has a more leveraged capital structure than most other investor- owned public utilities and is required to make substantial interest payments. The company's indebtedness under the Revolving Credit Facility, and some of the company's pollution control revenue bonds bear interest at floating rates to be set periodically, causing the company to be sensitive to fluctuating interest rates. PSNH has entered into an interest-rate-cap contract to reduce a portion of its interest-rate risk. In October 1995, Moody's Investors Service lowered its rating for PSNH and NAEC securities, bringing the rating for PSNH's First Mortgage Bonds below investment grade. Standard & Poor's had previously downgraded PSNH to below investment grade. NAEC securities had not been previously rated at investment grade. These downgrades could adversely affect the future availability and cost of funds for these companies. PSNH may be required to issue a significant amount of new debt in 1996, since it must fund the maturity of its $172.5 million first mortgage bond issue at the same time that it may need to finance more than $100 million for payments to its wood-fired NUG's. See the "Notes to Financial Statements," Note 7, for further information on derivative financial instruments and Notes 6, 7, and 10A, for information on construction and long-term debt funding requirements. RESULTS OF OPERATIONS OPERATING REVENUES The components of the change in operating revenues for the past two years are provided in the table below. Change In Operating Revenues Increase/(Decrease) 1995 vs. 1994 1994 vs. 1993 - ---------------------------------------------------------------------- (Millions of Dollars) Regulatory decisions $20 $20 Fuel, purchased power and FPPAC cost recoveries 49 32 Sales volume (11) 6 --- --- Total revenue change $58 $58 === === Revenues related to regulatory decisions increased, primarily due to the effects of the June 1995 and 1994 retail-rate increases. Fuel, purchased-power and FPPAC cost recoveries increased primarily due to higher fuel and purchased-power costs. Sales volume decreased as a result of price discounts, milder weather, and lower wholesale sales. Operating revenues increased approximately $58 million in 1994, from 1993. Revenues related to regulatory decisions increased primarily, due to the effects of the June 1994 and 1993 retail-rate increases. Fuel, purchased-power and FPPAC cost recoveries increased, primarily due to higher fuel and purchased- power costs. Sales volume increased as a result of higher retail sales from an improved economy and colder winter weather. Retail sales increased 2.0 percent in 1994 from 1993 sales levels. FUEL, PURCHASED AND NET INTERCHANGE POWER Fuel, purchased and net interchange power expense increased approximately $34 million in 1995, from 1994, primarily due to the timing in the recognition of fuel expenses under the FPPAC. Fuel, purchased and net interchange power increased approximately $15 million in 1994, from 1993, primarily due to an increase in purchased power. OTHER OPERATION AND MAINTENANCE EXPENSES Other operation and maintenance expenses increased by approximately $9 million in 1995, from 1994, primarily due to higher capacity charges under the Seabrook Power Contracts due to the 1995 refueling and maintenance outage at the Seabrook nuclear plant in 1995. Other operation and maintenance expenses increased by approximately $10 million in 1994, from 1993, primarily due to maintenance work during the two outages at the Seabrook nuclear plant in 1994 and higher storm-related expenses in 1994, partially offset by lower 1994 payroll and benefit costs and the cost of an employee-reduction program in 1993. See the "Notes to Financial Statements," Note 2, for further information on the Seabrook Power Contracts. DEPRECIATION EXPENSES Depreciation expenses increased by $6 million in 1995, from 1994, primarily due to the additional depreciation allowed from the savings from burning gas at Newington Station and an increase in plant additions. The change in depreciation expense in 1994, from 1993, was not significant. AMORTIZATION OF REGULATORY ASSETS, NET Although the change in 1995, from 1994, was not significant, amortization of regulatory assets net, decreased approximately $12 million in 1994, from 1993, primarily due to the higher amortization in 1994 of the regulatory liability recognized under a global settlement approved at the end of 1993. Approximately $128 million of pre-acquisition losses are being amortized over six years as a credit to amortization expense. 1994 included a full year of amortization as compared to only eight months of amortization in 1993. FEDERAL AND STATE INCOME TAXES Federal and state income taxes increased approximately $2 million in 1995, from 1994, primarily due to higher taxable income. Federal and state income taxes increased approximately $18 million in 1994, from 1993, primarily due to higher taxable income.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE SELECTED FINANCIAL DATA ====================================================================================== Jan. 1, 1995 Jan. 1, 1994 Jan. 1, 1993 June 5, 1992(a) to to to to For the Periods Dec. 31, 1995 Dec. 31, 1994 Dec. 31, 1993 Dec. 31, 1992 - --------------------------------------------------------------------------------------- (Thousands of Dollars) Operating Revenues... $ 979,590 $ 922,039 $ 864,415 $ 492,559 Operating Income..... 155,520 152,086 124,710 61,206 Net Income (Loss).... 83,255 77,444 52,237 29,398 At Dec. 31, 1995 Dec. 31, 1994 Dec. 31, 1993 Dec. 31, 1992 - -------------------------------------------------------------------------------------- Total Assets......... $2,909,636 $2,845,967 $2,774,511 $2,793,768 Long-Term Debt (c)... 858,985 999,985 1,093,985 1,187,985 Liabilities Subject to Settlement(c)...... - - - - Preferred Stock Subject to Mandatory Redemption(c) 125,000 125,000 125,000 125,000 Preferred Stock Not Subject to Mandatory Redemption - - - - Obligations Under Seabrook Power Contract and Other Capital Lease(c)... 915,288 887,967 856,559 787,826 (a) PSNH was acquired by NU on June 5, 1992. (b) PSNH was reorganized on May 16, 1991. (c) Includes portions due within one year.
SELECTED FINANCIAL DATA - ------------------------------------------------------- Jan. 1, 1992 May 16, 1991(b) January 1, 1991 to to to June 4, 1992 Dec. 31, 1991 May 15, 1991 - ------------------------------------------------------- (Thousands of Dollars) $ 381,769 $ 539,827 $ 246,281 34,250 82,755 21,616 12,778 52,694 (100,791) June 4, 1992 Dec. 31, 1991 May 15, 1991** - ------------------------------------------------------- (Thousands of Dollars) $2,693,414 $2,636,525 $2,502,237 1,488,985 1,515,985 - - - 1,901,803 125,000 125,000 - - - - - - - PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE STATISTICS - ------------------------------------------------------------------------------ Gross Electric Average Utility Plant Annual December 31, Use Per Electric (Thousands of kWh Sales Residential Customers Employees Dollars)(a) (Millions) Customer (kWh) (Average) (December 31) - ------------------------------------------------------------------------------ 1995 $2,716,060 11,001 6,576 406,077 1,325 1994 2,737,628 11,008 6,768 400,775 1,374 1993 2,760,228 11,146 6,817 397,277 1,426 1992(b) 2,763,075 12,294 6,874 394,046 1,680 1991 2,647,866 11,377 7,184 390,793 2,639 STATEMENTS OF QUARTERLY FINANCIAL DATA (Unaudited) - ----------------------------------------------------------------------------- Quarter Ended (c) ------------------------------------------------- 1995 March 31 June 30 September 30 December 31 - ----------------------------------------------------------------------------- Operating Revenues.......... $252,337 $232,849 $249,626 $244,778 ======== ======== ======== ======== Operating Income............ $ 41,858 $ 31,480 $ 40,333 $ 41,849 ========= ========= ========= ========= Net Income (Loss)........... $ 21,823 $ 13,892 $ 23,195 $ 24,345 ========= ========= ========= ========= 1994 - --------------------------------------------------------------------------- Operating Revenues.......... $249,279 $210,875 $227,976 $233,909 ======== ======== ======== ======== Operating Income............ $ 43,441 $ 32,388 $ 38,713 $ 37,544 ========= ========= ========= ========= Net Income.................. $ 24,278 $ 14,001 $ 19,262 $ 19,903 ========= ========= ========= ========= - --------------------------------------------------------------------------- (a) Includes reclassification of the unamortized acquisition costs to gross utility plant. (b) PSNH was acquired by NU on June 5, 1992. (c) Reclassifications of quarterly data have been made to conform with the current presentation. EX-13.5 20 ANNUAL REPORT OF NAEC EXHIBIT 13.5 1995 Annual Report North Atlantic Energy Corporation Index Contents Page - -------- ---- Balance Sheets.............................................. 2-3 Statements of Income........................................ 4 Statements of Cash Flows.................................... 5 Statements of Common Stockholder's Equity................... 6 Notes to Financial Statements............................... 7 Report of Independent Public Accountants.................... 16 Management's Discussion and Analysis of Financial Condition and Results of Operations....................... 17 Selected Financial Data..................................... 21 Statistics.................................................. 21 Statements of Quarterly Financial Data...................... 21 Bondholder Information...................................... Back Cover NORTH ATLANTIC ENERGY CORPORATION BALANCE SHEETS
- ---------------------------------------------------------------------------------- At December 31, 1995 1994 - ---------------------------------------------------------------------------------- (Thousands of Dollars) ASSETS - ------ Utility Plant, at original cost: Electric................................................ $ 771,794 $769,379 Less: Accumulated provision for depreciation......... 99,772 75,176 ----------- --------- 672,022 694,203 Construction work in progress........................... 7,616 3,704 Nuclear fuel, net....................................... 27,482 19,797 ----------- --------- Total net utility plant............................. 707,120 717,704 ----------- --------- Other Property and Investments: Nuclear decommissioning trusts, at market............... 15,312 10,342 Other, at cost.......................................... 222 222 ----------- --------- 15,534 10,564 ----------- --------- Current Assets: Cash.................................................... 8,384 8,166 Notes receivable from affiliated companies.............. 2,500 28,750 Receivables from affiliated companies................... 18,692 13,983 Materials and supplies, at average cost................. 12,269 10,036 Prepayments and other................................... 4,157 2,149 ----------- --------- 46,002 63,084 ----------- --------- Deferred Charges: Regulatory assets (Note 1G)........................ 239,896 166,598 Unamortized debt expense................................ 5,619 4,834 Other................................................... 478 795 ----------- --------- 245,993 172,227 ----------- --------- Total Assets........................................ $1,014,649 $963,579 =========== =========
The accompanying notes are an integral part of these financial statements. NORTH ATLANTIC ENERGY CORPORATION BALANCE SHEETS
- ----------------------------------------------------------------------------------- At December 31, 1995 1994 - ----------------------------------------------------------------------------------- (Thousands of Dollars) CAPITALIZATION AND LIABILITIES - ------------------------------ Capitalization: Common stock--$1 par value--authorized and outstanding 1,000 shares in 1995 and 1994........... $ 1 $ 1 Capital surplus, paid in................................. 160,999 160,999 Retained earnings........................................ 59,677 59,236 ----------- --------- Total common stockholder's equity............... 220,677 220,236 Long-term debt........................................... 540,000 540,000 ----------- --------- Total capitalization............................ 760,677 760,236 ----------- --------- Current Liabilities: Notes payable to affiliated company...................... 8,000 - Long-term debt--current portion.......................... 20,000 20,000 Accounts payable......................................... 6,135 4,073 Accounts payable to affiliated companies................. 143 38 Accrued interest......................................... 3,452 18,288 Accrued taxes............................................ 1,346 1,439 Other.................................................... 270 1,174 ----------- --------- 39,346 45,012 ----------- --------- Deferred Credits: Accumulated deferred income taxes (Note 1I)......... 179,135 120,250 Deferred obligation to affiliated company................ 33,284 33,284 Other.................................................... 2,207 4,797 ----------- --------- 214,626 158,331 ----------- --------- Commitments and Contingencies (Note 7) Total Capitalization and Liabilities............ $1,014,649 $963,579 =========== =========
The accompanying notes are an integral part of these financial statements. NORTH ATLANTIC ENERGY CORPORATION STATEMENTS OF INCOME
- -------------------------------------------------------------------------------- For the Years Ended December 31, 1995 1994 1993 - -------------------------------------------------------------------------------- (Thousands of Dollars) Operating Revenues............................. $ 157,183 $ 145,751 $ 125,408 ---------- ---------- ---------- Operating Expenses: Operation -- Fuel...................................... 12,030 7,144 7,067 Other..................................... 36,737 37,929 35,656 Maintenance.................................. 12,442 14,951 7,858 Depreciation................................. 23,406 22,959 22,642 Federal and state income taxes (Note 5).. 10,187 8,027 5,673 Taxes other than income taxes................ 10,987 11,791 12,794 ---------- ---------- ---------- Total operating expenses............... 105,789 102,801 91,690 ---------- ---------- ---------- Operating Income............................... 51,394 42,950 33,718 ---------- ---------- ---------- Other Income: Deferred Seabrook return--other funds (Note 1H)....................... 9,405 12,951 13,397 Other, net................................... 1,556 1,272 1,891 Income taxes--credit......................... 2,776 3,970 1,653 ---------- ---------- ---------- Other income, net...................... 13,737 18,193 16,941 ---------- ---------- ---------- Income before interest charges......... 65,131 61,143 50,659 ---------- ---------- ---------- Interest Charges: Interest on long-term debt................... 62,721 64,022 64,022 Other interest............................... (519) (280) 45 Deferred Seabrook return--borrowed funds funds (Note 1H)....................... (21,512) (33,134) (39,406) ---------- ---------- ---------- Interest charges, net.................. 40,690 30,608 24,661 ---------- ---------- ---------- Net Income..................................... $ 24,441 $ 30,535 $ 25,998 ========== ========== ==========
The accompanying notes are an integral part of these financial statements. NORTH ATLANTIC ENERGY CORPORATION STATEMENTS OF CASH FLOWS
- -------------------------------------------------------------------------------------------------- For the Years Ended December 31, 1995 1994 1993 - -------------------------------------------------------------------------------------------------- (Thousands of Dollars) Operating Activities: Net Income.................................................. $ 24,441 $ 30,535 $ 25,998 Adjustments to reconcile to net cash from operating activities: Depreciation.............................................. 23,406 22,959 22,642 Deferred income taxes and investment tax credits, net..... 46,114 34,449 37,121 Deferred return - Seabrook................................ (30,917) (46,085) (52,803) Other sources of cash..................................... 12,140 6,803 9,050 Other uses of cash........................................ (35,261) (2,842) (1,028) Changes in working capital: Receivables............................................... (4,709) 9,998 (790) Materials and supplies.................................... (2,233) (2,683) (1,990) Accounts payable.......................................... 2,167 (2,277) 5,026 Accrued taxes............................................. (93) 1,312 126 Other working capital (excludes cash)..................... (17,748) 2,363 822 ----------- ----------- ----------- Net cash flows from operating activities...................... 17,307 54,532 44,174 ----------- ----------- ----------- Financing Activities: Issuance of long-term debt.................................. 225,000 - - Net increase (decrease) in short-term debt.................. 8,000 - (18,500) Reacquisitions and retirements of long-term debt............ (225,000) - - Cash dividends on common stock.............................. (24,000) (10,000) - ----------- ----------- ----------- Net cash flows used for financing activities.................. (16,000) (10,000) (18,500) ----------- ----------- ----------- Investment Activities: Investment in plant: Electric utility plant.................................... (6,906) (11,256) (6,707) Nuclear fuel.............................................. (16,609) (1,227) (13,983) ----------- ----------- ----------- Net cash flows used for investments in plant................ (23,515) (12,483) (20,690) NU System Money Pool........................................ 26,250 (28,750) - Other investment activities, net............................ (3,824) (3,537) (2,844) ----------- ----------- ----------- Net cash flows used for investments........................... (1,089) (44,770) (23,534) ----------- ----------- ----------- Net Increase (Decrease) In Cash For The Period................ 218 (238) 2,140 Cash - beginning of period.................................... 8,166 8,404 6,264 ----------- ----------- ----------- Cash - end of period.......................................... $ 8,384 $ 8,166 $ 8,404 =========== =========== =========== Supplemental Cash Flow Information: Cash paid (received) during the year for: Interest, net of amounts capitalized........................ $ 73,923 $ 64,056 $ 63,393 =========== =========== =========== Income taxes................................................ $ (36,679) $ (34,988) $ (32,350) =========== =========== ===========
TThe accompanying notes are an integral part of these financial statements. NORTH ATLANTIC ENERGY CORPORATION STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
- ----------------------------------------------------------------------------------- Capital Retained Common Surplus, Earnings Stock Paid In (a) Total - ----------------------------------------------------------------------------------- (Thousands of Dollars) Balance at January 1, 1993 ............. $ 1 $ 160,999 $ 12,703 $ 173,703 Net income for 1993................. 25,998 25,998 ---------- ---------- --------- ---------- Balance at December 31, 1993............ 1 160,999 38,701 199,701 Net income for 1994................. 30,535 30,535 Cash dividends on common stock...... (10,000) (10,000) ---------- ---------- --------- ---------- Balance at December 31, 1994............ 1 160,999 59,236 220,236 Net income for 1995................. 24,441 24,441 Cash dividends on common stock...... (24,000) (24,000) ---------- ---------- --------- ---------- Balance at December 31, 1995............ $ 1 $ 160,999 $ 59,677 $ 220,677 ========== ========== ========= ==========
(a) The company had dividend restrictions imposed by its long-term debt agreement and was effectively prohibited by the agreement from the distribution of any dividends through May 1993. After that time, all retained earnings are available plus an allowance of $10 million. The accompanying notes are an integral part of these financial statements. North Atlantic Energy Corporation NOTES TO FINANCIAL STATEMENTS - ---------------------------------------------------------------------- 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES A. PRESENTATION North Atlantic Energy Corporation (NAEC or the company), The Connecticut Light and Power Company (CL&P), Public Service Company of New Hampshire (PSNH), Western Massachusetts Electric Company (WMECO), and Holyoke Water Power Company (HWP), are the operating subsidiaries comprising the Northeast Utilities system (the system) and are wholly-owned by Northeast Utilities (NU). The system furnishes retail electric service in Connecticut, New Hampshire, and western Massachusetts through CL&P, PSNH, WMECO, and HWP. NAEC sells all of its capacity to PSNH. In addition to its retail service, the system furnishes firm and other wholesale electric services to various municipalities and other utilities. The system serves about 30 percent of New England's electric needs and is one of the 20 largest electric utility systems in the country as measured by revenues. Other wholly owned subsidiaries of NU provide substantial support services to the system. Northeast Utilities Service Company (NUSCO) supplies centralized accounting, administrative, data processing, engineering, financial, legal, operational, planning, purchasing, and other services to the system companies. North Atlantic Energy Service Corporation acts as agent for NAEC and CL&P in operating the Seabrook nuclear generating facility. Northeast Nuclear Energy Company (NNECO) acts as agent for CL&P, PSNH, and WMECO in operating the Millstone nuclear generating facilities. All transactions among affiliated companies are on a recovery of cost basis which may include amounts representing a return on equity, and are subject to approval by various federal and state regulatory agencies. 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 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. Certain reclassifications of prior years' data have been made to conform with the current year's presentation. B. FUTURE ACCOUNTING STANDARD The Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of in March 1995. SFAS 121 became effective January 1, 1996, and establishes accounting standards for evaluating and recording asset impairment. SFAS 121 requires the evaluation of long-lived assets for impairment when certain events occur or conditions exist that indicate the carrying amounts of assets may not be recoverable. Refer to Note 1G, "Regulatory Accounting" for further information on the regulatory impacts of the company's adoption of SFAS 121. C. JOINTLY OWNED ELECTRIC UTILITY PLANT NAEC has a 35.98 percent joint-ownership interest in Seabrook 1, a 1,148-megawatt (MW) nuclear generating unit, including the 0.4 percent ownership interest in Seabrook 1 which NAEC acquired from Vermont Electric Generation and Transmission Cooperative in February 1994. NAEC sells all of its share of the power generated by Seabrook 1 to PSNH. As of December 31, 1995 and 1994, plant-in-service included approximately $715.7 million and $714.2 million, respectively, and the accumulated provision for depreciation included approximately $82.2 million and $63.1 million, respectively, for NAEC's share of Seabrook 1. NAEC's share of Seabrook 1 expenses is included in the operating expenses on the accompanying Statements of Income. D. DEPRECIATION The provision for depreciation is calculated using the straight-line method based on estimated remaining lives of depreciable utility plant- in-service, adjusted for salvage value and removal costs, as approved by the Federal Energy Regulatory Commission (FERC). Except for major facilities, depreciation factors are applied to the average plant-in- service during the period. Major facilities are depreciated from the time they are placed in service. When plant is retired from service, the original cost of plant, including costs of removal, less salvage, is charged to the accumulated provision for depreciation. The depreciation rates for the several classes of electric plant-in-service are equivalent to a composite rate of 3.3 percent in 1995 and 1994, and 3.2 percent in 1993. See Note 2, "Nuclear Decommissioning," for additional information on nuclear plant decommissioning. E. PUBLIC UTILITY REGULATION NU is registered with the Securities and Exchange Commission (SEC) as a holding company under the Public Utility Holding Company Act of 1935 (1935 Act), and it and its subsidiaries, including the company, are subject to the provisions of the 1935 Act. Arrangements among the system companies, outside agencies, and other utilities covering interconnections, interchange of electric power, and sales of utility property are subject to regulation by the FERC and/or the SEC. The company is subject to further regulation for rates, accounting, and other matters by the FERC and the New Hampshire Public Utilities Commission (NHPUC). F. SEABROOK POWER CONTRACTS PSNH and NAEC have entered into two power contracts that obligate PSNH to purchase NAEC's 35.98 percent ownership of the capacity and output of Seabrook 1 for the term of Seabrook 1's Nuclear Regulatory Commission (NRC) operating license. Under these contracts, PSNH is obligated to pay NAEC's cost of service during this period, regardless if Seabrook 1 is operating. NAEC's cost of service includes all of its Seabrook- related costs, including operation and maintenance expense, fuel expense, income and property tax expense, depreciation expense, certain overhead and other costs, and a return on its allowed investment. The Seabrook power contracts established the value of the initial investment in Seabrook (initial investment) at $700-million. As of December 31, 1995, the portion of the initial investment on which NAEC is entitled to earn a cash return was 85 percent. The initial investment will be fully phased into NAEC's rate base as of May 1, 1996. From June 5, 1992 (the date NU acquired PSNH and NAEC acquired Seabrook 1 from PSNH - the Acquisition Date) through December 31, 1995, NAEC recorded $162.4 million of deferred return on the excluded portion of its investment in Seabrook 1. The deferred return on the excluded portion of NAEC's investment in Seabrook 1 will be recovered from PSNH with carrying charges beginning December 1, 1997, and will be fully recovered by May 2001. NAEC is depreciating its initial investment over the term of Seabrook 1's operating license (39 years), and any subsequent plant additions are depreciated on a straight-line basis over the remaining term of the Seabrook power contracts at the time the subsequent additions are placed in service. If Seabrook 1 is shut down prior to the expiration of the NRC operating license, PSNH will be unconditionally required to pay NAEC termination costs for 39 years, less the period during which Seabrook 1 has operated. These termination costs will reimburse NAEC for its share of Seabrook 1 shut-down and decommissioning costs, and will pay NAEC a return of and on any undepreciated balance of its initial investment over the remaining term of the Seabrook power contracts, and the return of and on any capital additions to the plant made after the Acquisition Date over a period of five years after shut down (net of any tax benefits to NAEC attributable to the cancellation). G. REGULATORY ACCOUNTING The accounting policies of the company and the accompanying financial statements conform to generally accepted accounting principles applicable to rate-regulated enterprises and reflect the effects of the ratemaking process in accordance with SFAS 71, Accounting for the Effects of Certain Types of Regulation. Assuming a cost-of-service based regulatory structure, regulators may permit incurred costs, normally treated as expenses, to be deferred and recovered in future revenues. Through their actions, regulators may also reduce or eliminate the value of an asset, or create a liability. If any portion of the company's operations were no longer subject to the provisions of SFAS 71, as a result of a change in the cost-of-service based regulatory structure or the effects of competition, the company would be required to write off related regulatory assets and liabilities. The company would also be required to determine any impairment to other assets, and write down these assets to fair value. Based on current regulation and recent regulatory decisions and initiatives relating to competition in the company's markets, the company believes that its use of regulatory accounting remains appropriate. SFAS 121 requires that any assets, including regulatory assets, which are no longer probable of recovery through future revenues be revalued based on estimated future cash flows. If the revaluation is less than the book value of the asset, an impairment loss would be charged to earnings. As noted above, based on the current regulatory environment, it is not expected that SFAS 121 will have a material impact on the company's financial position or results of operations upon adoption. This conclusion may change in the future as competitive factors influence wholesale and retail pricing in the electric utility industry, or if the cost-of-service based regulatory structure were to change. For further information on the company's regulatory environment, refer to Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A). The components of regulatory assets are as follows: At December 31, 1995 1994 ------------------------------------------------------------------- (Thousands of Dollars) Deferred costs-Seabrook 1 (Note 1H) .. $162,430 $131,513 Income taxes, net (Note 1I) .......... 43,231 30,461 Recoverable energy costs (Note 1J) ... 2,349 4,624 Unamortized loss on reacquired debt (Note 1K) 31,886 - --------- --------- $239,896 $166,598 ======== ======== H. DEFERRED COST - SEABROOK 1 As prescribed by the Rate Agreement, NAEC is phasing into rates the recoverable portions of its investment in Seabrook 1 and is deferring certain costs for future collection. This plan is in compliance with SFAS 92, Regulated Enterprises - Accounting for Phase-In Plans. See Note 1F for terms of Seabrook 1's phase-in. I. INCOME TAXES The tax effect of temporary differences (differences between the periods in which transactions affect income in the financial statements and the periods in which they affect the determination of income subject to tax) is accounted for in accordance with the ratemaking treatment of the FERC. The adoption of SFAS 109, Accounting for Income Taxes, in 1993 increased the company's net deferred tax obligation. As it is probable that the increase in deferred tax liabilities will be recovered through the Seabrook power contracts, NAEC established a regulatory asset. The tax effect of temporary differences, including timing differences accrued under previously approved accounting standards, which give rise to the accumulated deferred tax obligation is as follows: At December 31, 1995 1994 ----------------------------------------------------------------- (Thousands of Dollars) Accelerated depreciation and other plant-related differences $156,448 $ 93,486 Regulatory assets - income tax gross up 15,131 7,223 Other ................................. 7,556 19,541 ---------- --------- $179,135 $120,250 ======== ======== J. RECOVERABLE ENERGY COSTS Under the Energy Policy Act of 1992 (Energy Act), NAEC is assessed for its proportionate shares of the costs of decontaminating and decommissioning uranium enrichment plants owned by the United States Department of Energy (D&D assessment). The Energy Act requires that regulators treat D&D assessments as a reasonable and necessary current cost of fuel, to be fully recovered in rates, like any other fuel cost. NAEC is currently recovering these costs through rates. As of December 31, 1995, the company's total D&D deferral was approximately $2.3 million. K. UNAMORTIZED LOSS ON REACQUIRED DEBT In December 1995, NAEC called its $205 million principal amount, 15.23 percent notes due in 2000, and replaced the issue with funding from the proceeds of a $225 million, five-year term, variable-rate facility. As a result of this refinancing, redemption premiums of approximately $32 million were incurred. These redemption premiums have been deferred as a regulatory asset, and are being amortized over the five-year term of the new variable-rate facility, until 2000. For further information on the NAEC refinancing, refer to Note 4, "Long-Term Debt." L. DERIVATIVE FINANCIAL INSTRUMENTS The company utilizes interest-rate swaps to manage a well-defined interest-rate risk. Amounts receivable or payable under interest-rate swap agreements are accrued and offset against interest expense. Any material unrealized gains or losses on interest-rate swaps will be deferred until realized. For further information on derivatives, see Note 8, "Derivative Financial Instruments." 2. NUCLEAR DECOMMISSIONING The Seabrook 1 nuclear power plant has a service life that is expected to end in 2026. Upon retirement, this unit must be decommissioned. A 1994 Seabrook decommissioning study confirmed that complete and immediate dismantlement at retirement is the most viable and economic method of decommissioning Seabrook 1. Decommissioning studies are reviewed and updated periodically to reflect changes in decommissioning requirements, costs, technology, and inflation. NAEC's 35.98 percent ownership of the estimated costs of decommissioning Seabrook 1, in year-end 1995 dollars, is $152.5 million. This estimated cost assumes escalated collections and after-tax earnings on the Seabrook decommissioning funds of 6.1 percent. Seabrook 1 decommissioning costs will be increased annually by an escalation rate. Nuclear decommissioning costs are accrued over the expected service life of the unit and are included in depreciation expense on the Statements of Income. Nuclear decommissioning costs amounted to $3.0 million in 1995, $2.7 million in 1994, and $2.6 million in 1993. Nuclear decommissioning, as a cost of removal, is included in the accumulated provision for depreciation on the Balance Sheets. At December 31, 1995, the balance in the accumulated reserve for decommissioning amounted to $15.3 million. See "Nuclear Decommissioning" in the MD&A for a discussion of changes being considered by the FASB related to accounting for decommissioning costs. Under the terms of the Rate Agreement, PSNH is obligated to pay NAEC's share of Seabrook 1's decommissioning costs, even if the unit is shut down prior to the expiration of its operating license. NAEC's portion of the cost of decommissioning Seabrook 1 is paid to an independent decommissioning financing fund managed by the state of New Hampshire. As of December 31, 1995, NAEC (including pre-Acquisition Date payments made by PSNH) had paid approximately $13.1 million into Seabrook 1's decommissioning financing fund. Earnings on the decommissioning financing fund increase the decommissioning financing fund balance and the accumulated reserve for decommissioning. Unrealized gains and losses associated with the decommissioning financing fund also impact the balance of the fund and the accumulated reserve for decommissioning. Changes in fund requirements or technology, the timing of funding or dismantling, or adoption of a decommissioning method other than immediate dismantlement would change decommissioning cost estimates and the amounts required to be recovered. PSNH attempts to recover sufficient amounts through its allowed rates to cover NAEC's expected decommissioning costs. Only the portion of currently estimated total decommissioning cost that has been accepted by the NHPUC and the FERC is reflected in PSNH's rates. Based on present estimates and assuming Seabrook 1 operates to the end of its licensing period, NAEC expects that the decommissioning financing fund will be substantially funded when Seabrook 1 is retired from service. 3. SHORT-TERM DEBT NAEC is a limited participant in the Northeast Utilities System Money Pool (Pool). As a limited participant, NAEC is limited to borrowing funds provided by NU parent. The Pool provides a more efficient use of the cash resources of the system, and reduces outside short-term borrowings. NUSCO administers the Pool as agent for the member companies. Borrowings based on loans from NU parent bear interest at NU parent's cost and must be repaid based upon the terms of NU parent's original borrowing. At December 31, 1995, NAEC had $8.0 million of borrowings outstanding from the Pool. At December 31, 1994, NAEC had no outstanding borrowings from the Pool. The interest rate on borrowings from the Pool at December 31, 1995 was 4.7 percent. Maturities of NAEC's short-term debt obligations were for periods of three months or less. The amount of short-term borrowings that may be incurred by NAEC is subject to periodic approval by the SEC under the 1935 Act. Under the SEC restrictions, NAEC was authorized, as of January 1, 1995, to incur short- term borrowings up to a maximum of $50 million. 4. LONG-TERM DEBT Details of long-term debt outstanding are: December 31, ------------ 1995 1994 ---------------------------------------------------------------- (Thousands of Dollars) First Mortgage Bonds: 9.05% Series A, due 2002 ........... $335,000 $355,000 Notes: 15.23% due 2000 .................... - 205,000 Variable rate, due 2000 ............. 225,000 - Less: Amounts due within one year .. 20,000 20,000 --------- -------- Long-term debt, net ....... $540,000 $540,000 ======== ======== Long-term debt maturities and cash sinking-fund requirements on debt outstanding at December 31, 1995 for the years 1996 through 2000 are $20 million annually for 1996-1998, $70 million in 1999, and $295 million in 2000. On December 11, 1995, NAEC redeemed, at a special redemption price, its $205 million, 15.23 percent notes which were due in 2000. This transaction was executed to coincide with the funding date of NAEC's new $225 million variable-rate bank note. The $225 million note will mature in 2000 with quarterly interest payments scheduled to be made through maturity. In order to mitigate the interest-rate risk inherent with the variable rate issue, NAEC has executed a $225 million interest-rate swap agreements with four counterparty banks. The $225 million swap effectively fixes the interest rate on the variable-rate agreement at 7.05 percent. For more information on the interest-rate swap, see Note 8, "Derivative Financial Instruments." The Series A Bonds are not redeemable prior to maturity except out of proceeds of sales of property subject to the lien of the Series A First Mortgage Bond Indenture (Indenture), at general redemption prices established by the Indenture, and out of condemnation or insurance proceeds and through the operation of the sinking fund. Essentially all of NAEC's utility plant is subject to the lien of its Indenture. 5. INCOME TAX EXPENSE The components of the federal and state income tax provisions are: For the Years Ended December 31, 1995 1994 1993 (Note 1I) --------------------------------------------------------------------- (Thousands of Dollars) Current income taxes: Federal ...................... $(38,703) $(30,553) $(33,225) State ........................ - 161 124 --------- --------- ---------- Total current .............. (38,703) (30,392) (33,101) --------- --------- --------- Deferred income taxes, net: Federal ....................... 41,885 34,449 37,199 State ......................... 4,229 - (78) ----------- -------- ---------- Total deferred ............. 46,114 34,449 37,121 --------- --------- -------- Total income tax expense ... $ 7,411 $ 4,057 $ 4,020 ========== ======== ======== The components of total income tax expense are classified as follows: For the Years Ended December 31, 1995 1994 1993 (Note 1I) --------------------------------------------------------------------- (Thousands of Dollars) Income taxes charged to operating expenses ..................... $ 10,187 $ 8,027 $ 5,673 Other income taxes ............. (2,776) (3,970) (1,653) --------- --------- -------- Total income tax expense $ 7,411 $ 4,057 $ 4,020 ======== ========= ======== Deferred income taxes are comprised of the tax effects of temporary differences as follows: For the Years Ended December 31, 1995 1994 1993 (Note 1I) --------------------------------------------------------------------- (Thousands of Dollars) Depreciation ................... $24,444 $22,783 $23,000 Alternative minimum tax ........ - 73 1,250 Bond redemptions ............... 12,087 - - Seabrook 1 return .............. 8,109 11,597 13,792 Property taxes ................. - - (1,003) Other .......................... 1,474 (4) 82 -------- --------- ---------- Deferred income taxes, net $46,114 $34,449 $37,121 ======= ======= ======= A reconciliation between income tax expense and the expected tax expense at the applicable statutory rate is as follows:
For the Years Ended December 31, 1995 1994 1993 (Note 1I) ----------------------------------------------------------------------------- (Thousands of Dollars) Expected federal income tax at 35 percent of pretax income $11,148 $12,107 $10,506 Tax effect of differences: Depreciation ................. (2,159) (2,087) (1,481) Deferred Seabrook 1 return ... (3,292) (4,533) (4,689) State income taxes, net of federal benefit 2,749 104 30 Other, net ..................... (1,035) (1,534) (346) -------- -------- ------- Total income tax expense ....... $ 7,411 $ 4,057 $ 4,020 ======= ======= ======= 6. DEFERRED OBLIGATION TO AFFILIATED COMPANY At the time PSNH emerged from bankruptcy on May 16, 1991, in accordance with the phase-in under the contracts, it began accruing a deferred return on the unphased-in portion of its Seabrook 1 investment. From May 16, 1991 to the Acquisition Date, PSNH accrued a deferred return of $50.9 million. On the Acquisition Date, PSNH transferred the $50.9 million deferred return to NAEC as part of the Seabrook-related assets. At the time PSNH transferred the deferred return to NAEC, it realized, for income tax purposes, a gain that is deferred under the consolidated income tax rules. This gain will be restored for income tax purposes when the deferred return of $50.9 million, and the associated income taxes of $33.3 million, are collected by NAEC through the Seabrook power contracts. When NAEC recovers the $33.3 million in years eight through ten of the Rate Agreement, it is obligated to make corresponding payments to PSNH. 7. COMMITMENTS AND CONTINGENCIES A. SEABROOK 1 CONSTRUCTION PROGRAM The construction program for Seabrook 1 is subject to periodic review and revision. NAEC currently forecasts construction expenditures for its share of Seabrook 1 to be $34.1 million for the years 1996-2000, including $6.0 million for 1996. In addition, NAEC estimates that its share of Seabrook 1 nuclear fuel requirements will be $44.7 million for the years 1996-2000, including $0.6 million for 1996. B. ENVIRONMENTAL MATTERS NAEC is subject to regulation by federal, state, and local authorities with respect to air and water quality, handling the disposal of toxic substances and hazardous and solid wastes, and the handling and use of chemical products. NAEC has an active environmental auditing and training program and believes that it is in substantial compliance with current environmental laws and regulations. Environmental requirements could hinder future construction. The cumulative long-term, cost impact of increasingly stringent environmental requirements cannot accurately be estimated. Changing environmental requirements could also require extensive and costly modifications to NAEC's existing investment in Seabrook 1 and could raise operating costs significantly. As a result, NAEC may incur significant additional environmental costs, greater than amounts included in cost of removal and other reserves, in connection with the generation of electricity and the storage, transportation, and disposal of by-products and wastes. NAEC may also encounter significantly increased costs to remedy the environmental effects of prior waste handling activities. NAEC cannot estimate the potential liability for future claims, including environmental remediation costs, that may be brought against it. However, considering known facts, existing laws, and regulatory practices, management does not believe the matters disclosed above will have a material effect on NAEC's financial position or future results of operations. C. NUCLEAR INSURANCE CONTINGENCIES Under certain circumstances, in the event of a nuclear incident at one of the nuclear facilities covered by the federal government's third- party liability indemnification program, the company could be assessed in proportion to its ownership interest in a nuclear unit up to $75.5 million not to exceed $10 million per nuclear unit in any one year. The maximum assessment is to be adjusted at least every five years for inflationary changes. Based on the ownership interest in Seabrook 1, NAEC's maximum liability, including any additional potential assessments would be $28.5 million per incident. Payments for NAEC's ownership interest would be limited to a maximum of $3.6 million per incident per year. Insurance has been purchased to cover certain extra costs incurred in obtaining replacement power during prolonged accidental outages and the excess cost of repair, replacement, or decontamination or premature decommissioning of utility property resulting from insured occurrences. NAEC is subject to retroactive assessments if losses exceed the accumulated funds available to the insurer. The maximum potential assessments against NAEC with respect to losses arising during current policy years are approximately $8.1 million under the replacement power policies. The cost of a nuclear incident could exceed available insurance proceeds. Insurance has been purchased aggregating $200 million on an industry basis for coverage of worker claims. All participating reactor operators insured under this coverage are subject to retrospective assessments of $3.0 million per reactor. The maximum potential assessment against NAEC with respect to losses arising during the current policy period is approximately $1.1 million. Under the terms of the Seabrook power contracts, any nuclear insurance assessments described above would be passed on to PSNH as a "cost of service." 8. DERIVATIVE FINANCIAL INSTRUMENTS The company utilizes derivative financial instruments to manage well-defined interest-rate rates. The company does not use them for trading purposes. NAEC uses interest-rate swap agreements with financial institutions to hedge against interest-rate risk associated with its $225 million variable-rate bank note. The interest-rate swaps minimize exposure associated with rising interest rates, and effectively fix the interest rate for this borrowing arrangement. Under the swap agreements, NAEC exchanges quarterly payments based on a differential between a fixed contractual interest rate and the three-month LIBOR rate at a given time. As of December 31, 1995, NAEC had outstanding agreements with a total notional value of approximately $225 million, and a negative mark-to-market position of approximately $3.8 million. These swap agreements have been made with various financial institutions, each of which are rated "A" or better by Standard & Poor's rating group. NAEC is exposed to credit risk on the interest-rate swaps if the counterparties fail to perform their obligations. However, NAEC anticipates that the counterparties will be able to fully satisfy their obligations under the contracts. 9. FAIR VALUE OF FINANCIAL INSTRUMENTS The following methods and assumptions were used to estimate the fair value of each of the following financial instruments: Cash and nuclear decommissioning trust: The carrying amounts approximate fair value. SFAS 115, Accounting for Certain Investments in Debt and Equity Securities, requires investment in debt and equity securities to be presented at fair value and was adopted by the company on a prospective basis as of January 1, 1994. During 1995, the investments held by the company's decommissioning trust increased by approximately $0.3 million as of December 31, 1995, and decreased by approximately $0.9 million as of December 31, 1994, with a corresponding offset to the accumulated provision for depreciation. The $0.3 million increase in 1995 represents cumulative gross unrealized holding gains. The cumulative gross unrealized holding losses were immaterial for 1995. The $0.9 million decrease in 1994 represents cumulative gross holding losses of $0.9 million. There were no material cumulative gross unrealized holding gains in 1994. There was no change in the funding requirements of the trust nor any impact on earnings as a result of the adoption of SFAS 115. Long-term debt: The fair value of NAEC's long-term debt is based upon the quoted market price for those issues or similar issues. The carrying amounts of NAEC's financial instruments and the estimated fair values are as follows: Carrying Fair At December 31, 1995 Amount Value ------------------------------------------------------------------------ (Thousands of Dollars) First Mortgage Bonds ..................... $335,000 $336,575 Other long-term debt ..................... $225,000 $225,000 ------------------------------------------------------------------- Carrying Fair At December 31, 1994 Amount Value ------------------------------------------------------------------------ (Thousands of Dollars) First Mortgage Bonds ..................... $355,000 $351,450 Other long-term debt ..................... $205,000 $242,925 The fair values shown above have been reported to meet the disclosure requirements and do not purport to represent the amounts at which those obligations would be settled. 10. NUCLEAR PERFORMANCE On January 31, 1996, the NRC announced that the three Millstone nuclear power plants, operated by NNECO, had been placed on its "watch list" because of long-standing performance concerns. The NRC cited a number of operational problems which have arisen since 1990 at the Millstone plants. The NRC recognized that there are significant current variations in the performance of the three units. The performance concerns cited by the NRC, combined with NU's failure to maintain previous performance improvements, have resulted in the NRC requiring close monitoring of Millstone unit operations and the implementation of a corrective action program. North Atlantic Energy Corporation Report of Independent Public Accountants - --------------------------------------------------------------------------- To the Board of Directors of North Atlantic Energy Corporation: We have audited the accompanying balance sheets of North Atlantic Energy Corporation (a New Hampshire corporation and a wholly owned subsidiary of Northeast Utilities) as of December 31, 1995 and 1994, and the related statements of income, common stockholder's equity, 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 North Atlantic Energy Corporation 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. /s/ Arthur Andersen LLP ARTHUR ANDERSEN LLP Hartford, Connecticut February 16, 1996 NORTH ATLANTIC ENERGY CORPORATION MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - ---------------------------------------------------------------------- This section contains management's assessment of NAEC's (the company) financial condition and the principal factors having an impact on the results of opera- tions. The company is a wholly owned subsidiary of Northeast Utilities (NU). This discussion should be read in conjunction with NAEC's financial statements and footnotes. FINANCIAL CONDITION OVERVIEW On June 5, 1992 (the Acquisition Date), NU acquired Public Service Company of New Hampshire (PSNH), and PSNH's 35.58 percent share of the Seabrook 1 nuclear power plant (Seabrook 1) and other Seabrook-related assets were transferred to the company. At the Acquisition Date, PSNH and the company entered into the Seabrook Power Contract (the Contract), under which PSNH is obligated to buy from the company, and the company is obligated to sell to PSNH, all of the company's capacity and output of Seabrook 1 for a period equal to the length of the Nuclear Regulatory Commission (NRC) full-power operating license for Seabrook (through 2026). Under the Contract, PSNH is unconditionally obligated to pay the company's "cost of service" during the period whether or not Seabrook 1 is operating and without regard to the cost of alternative sources of power. In addition, PSNH will be obligated to pay decommissioning and project cancellation costs after the termination of the operating license. NAEC does not have any employees of its own and does not operate Seabrook 1. North Atlantic Energy Service Corporation (NAESCO) is the managing agent and represents the Seabrook 1 joint owners, including NAEC, in the operation of Seabrook 1. On February 15, 1994, NAEC acquired Vermont Electric Generation and Transmission Cooperative's (VEG&T) 0.4 percent ownership interest of Seabrook 1 for approximately $6.4 million, giving NAEC a total joint-ownership interest in Seabrook 1 of 35.98 percent. NAEC sells the output from the Seabrook interest purchased from VEG&T to PSNH under an agreement which is substantially similar to the Seabrook Power Contract discussed above (the Contracts). The company's "cost of service" includes all of its prudently incurred Seabrook 1-related costs, including operation and maintenance expense, fuel expense, property tax expense, depreciation expense, certain overhead and other costs, and a phased-in return on its Seabrook 1 investment. The Contract established the initial recoverable investment in Seabrook 1 at $700 million (Initial Investment), plus any capital additions, net of depreciation. The company's only assets are Seabrook 1 and other Seabrook 1-related assets and its only source of revenue are the Contracts. PSNH's obligations under the Contracts are solely its own and have not been guaranteed by NU. The Contracts contain no provisions entitling PSNH to terminate its obligations. If, however, PSNH were to fail to perform its obligations under the Contracts, the company would be required to find other purchasers for Seabrook power. The electric-power industry is continuing to move toward a more competitive environment. The New Hampshire Public Utilities Commission (NHPUC) is reviewing the rates charged by its electric-power suppliers. Although the NHPUC has some limited authority over the company's Contracts with PSNH, its rates are subject to regulation by the Federal Energy Regulatory Commission (FERC). During 1995, FERC issued a proposal for restructuring the electric-power industry, which calls for open access to transmission facilities, a standard formula for calculating rates, and full recovery of stranded investments. The impact of this proposal, which is expected to be finalized in 1996, is not expected to have a material impact on NAEC's financial position or results of operations. NAEC's net income was approximately $24 million in 1995, a decrease of approximately $7 million, from approximately $31 million in 1994. The 1995 net income was lower primarily due to a one-time adjustment to correct the deferred Seabrook 1 return balance and lower state income taxes. WORKFORCE REDUCTIONS In January 1996, NU and NAESCO completed their nuclear workforce reduction plan. Approximately 36 positions were eliminated at Seabrook 1, through a combination of early retirements, attrition, and layoffs. The total pretax cost of the workforce reduction, which was recognized in 1995, was approximately $2 million. RATE MATTERS NAEC follows accounting principles in accordance with Statement of Financial Accounting Standards (SFAS) 71, "Accounting for the Effects of Certain Types of Regulation" that allows the economic effects of rate regulation to be reflected. Under these principles, regulators may permit incurred costs for certain events or transactions, which would be treated as expenses by nonregulated enterprises, to be deferred as regulatory assets and recovered in revenues at a later date. The creation of these regulatory assets has kept down electric rates in past years, at the expense of having higher rates in the future. At December 31, 1995, NAEC's regulatory assets totaled approximately $240 million. The largest regulatory asset, nearly $162 million, is related to the deferred return associated with the amount of the Seabrook 1 investment that has not been included in rates. As of December 31, 1995, NAEC has included in rates $595 million of its Seabrook 1 investment. The remaining investment ($105 million) will be phased into rates in May 1996. An additional amount of deferred Seabrook 1 return of approximately $51 million is recorded as utility plant. The deferred amounts associated with the Seabrook 1 phase-in will be recovered under NAEC's Contracts with PSNH over the period December 1997 through May 2001. In March 1995, the Financial Accounting Standards Board (FASB) issued SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of." SFAS 121, which was effective January 1, 1996, requires assets, including regulatory assets, that are no longer probable of recovery through future revenues be charged to earnings. If future competition or regulatory actions in New Hampshire cause any portion of its operations to no longer be subject to SFAS 71, NAEC would be required to determine the fair value of the related regulatory assets and liabilities and record any necessary write-downs. Additionally, if events create uncertainty about the recoverability of any of NAEC's remaining long-lived assets, a similar analysis would be required for those assets in accordance with SFAS 121. Under its current regulatory environment, NAEC believes that its use of SFAS 71 remains appropriate and that the adoption of SFAS 121 will not have a material impact on its financial position or results of operations. See the "Notes to Financial Statements," Note 1G, for further details on regulatory accounting. NUCLEAR PERFORMANCE On January 31, 1996, the NRC placed Millstone 1, 2, and 3 (Millstone) on its "watch list." The NRC's action was in response to a number of performance concerns which have arisen since 1990 and a failure to resolve employee safety concerns. The NRC's action will result in close monitoring of programs and performance at Millstone to assure the development and implementation of effective corrective actions. NU's management plans to continue its extensive efforts already under way to address these concerns. Concurrent with the NRC's action, NU provided the NRC with the results of a comprehensive self-assessment review of the employee concern program at Millstone. Additionally, in January 1996, NU announced a reorganization of its nuclear operations which included the creation of a new office of Nuclear Safety and Oversight. Although the start-up of Millstone 1, which is currently in outage, will be affected by its placement on the NRC's "watch list," operations at Millstone 2 and 3 have not been restricted. NU's management expects that the increased NRC attention will inevitably have effects and costs that are not known at this time. The Seabrook plant operated at 83.2 percent of capacity for the year ended December 31, 1995, compared with 61.6 percent in 1994 and a 1995 national average of 77.6 percent. The higher 1995 capacity factor was primarily the result of unplanned and extended outages in 1994. The unit had a 37.5-day planned refueling and maintenance outage in 1995, the unit's shortest to date. ENVIRONMENTAL MATTERS NU devotes substantial resources to identify and comply with the multitude of environmental requirements it faces. NU has active auditing programs addressing a variety of regulatory requirements, including an environmental auditing program to detect and remedy noncompliance with environmental laws or regulations. See the "Notes to Financial Statements," Note 7B, for further information regarding other environmental matters. NUCLEAR DECOMMISSIONING NAEC's estimated cost to decommission its share of Seabrook 1 is approximately $153 million in year-end 1995 dollars. These costs are being recognized over the life of the unit and a portion is being recovered through PSNH's rates. PSNH is obligated to pay NAEC's share of Seabrook's decommissioning costs even if the unit is shut down prior to the expiration of its license. The FASB is currently reviewing the accounting for closure and removal costs, including decommissioning and similar costs, for long-lived assets. If current electric-power industry accounting practices for such decommissioning costs were changed, annual provisions for decommissioning would increase and the estimated costs for decommissioning would be recorded as a liability rather than as a component of accumulated depreciation. See the "Notes to Financial Statements," Note 2, for further information regarding nuclear decommissioning. LIQUIDITY AND CAPITAL RESOURCES Cash provided from operations decreased approximately $37 million in 1995, from 1994, primarily due to the payment of accrued interest and debt expense associated with the note refinancing discussed below. Cash used for financing activities increased approximately $6 million in 1995, from 1994, primarily due to an increase in the payment of cash dividends on common stock, partially offset by an increase in short-term debt. Cash used for investments decreased approximately $43 million in 1995, from 1994, primarily due to the repayment of short-term loans by other NU system companies under the NU system Money Pool, partially offset by higher nuclear fuel expenditures due to the 1995 Seabrook refueling outage. In October 1995, Moody's Investors Service lowered its ratings of PSNH and NAEC securities, bringing the rating for PSNH's First Mortgage Bonds below investment grade. Standard & Poor's had previously downgraded PSNH to below investment grade. NAEC securities had not been previously rated at investment grade. These downgrades could adversely affect the future availability and cost of funds for these companies. In December 1995, NAEC refinanced its $205-million, 15.23-percent note with a $225 million five-year variable rate bank loan. The refinancing is expected to save PSNH customers approximately $4 million annually for 5 years. In order to mitigate the interest-rate risk inherent with the variable rate issue, NAEC executed a $225 million interest-rate swap. The swap effectively fixes the interest cost on the variable-rate loan at 7.05 percent. See the "Notes to Financial Statements," Notes 4 and 8, for further information on the refinancing and interest-rate swap, Note 11, for further information on derivative financial instruments, and Notes 4 and 7A, for further information on construction and long-term debt funding requirements. RESULTS OF OPERATIONS OPERATING REVENUES Operating revenues represent amounts billed to PSNH under the terms of the Contracts and billings to PSNH for decommissioning expense. Operating revenues increased approximately $11 million in 1995, from 1994, primarily due to the increased return associated with the phase-in of an additional 15 percent of Seabrook plant's initial investment in May 1995 and May 1994, respectively. Operating revenues increased approximately $20 million in 1994, from 1993, primarily due to the higher operation and maintenance expenses and the increased return associated with the phase-in of additional Seabrook plant in May 1994. FUEL EXPENSES Fuel expenses increased approximately $5 million in 1995, from 1994, primarily due to the better performance of Seabrook in 1995. The change in 1994, from 1993, was not significant. OTHER OPERATION AND MAINTENANCE EXPENSES Other operation and maintenance expenses, net decreased approximately $4 million in 1995, from 1994, and increased approximately $9 million in 1994, from 1993, primarily due to the unplanned and extended Seabrook outages in 1994. FEDERAL AND STATE INCOME TAXES Federal and state income taxes increased approximately $3 million in 1995, from 1994, despite a decrease in income due primarily to higher state taxes as a result of a one-time adjustment to the deferred income tax provision. The change in 1994, from 1993, was not significant. DEFERRED SEABROOK RETURN Deferred Seabrook return - other and borrowed funds decreased approximately $15 million in 1995, from 1994, primarily because additional Seabrook investment was phased into rates in May 1995 and May 1994 and because of a one-time adjustment of approximately $5 million made in June 1995 to correct the deferred Seabrook return balance. Deferred Seabrook return - other and borrowed funds decreased approximately $6 million in 1994, from 1993, primarily because additional Seabrook investment was phased into rates in May 1994. NORTH ATLANTIC ENERGY CORPORATION SELECTED FINANCIAL DATA 1995 1994 1993 1992* - --------------------------------------------------------------------------- (Thousands of Dollars) Operating Revenues........... $ 157,183 $145,751 $125,408 $ 78,444 ========== ======== ======== ========= Operating Income............. $ 51,394 $ 42,950 $ 33,718 $ 16,122 ========== ======== ======== ========= Net Income................... $ 24,441 $ 30,535 $ 25,998 $ 12,703 ========== ======== ======== ========= Cash Dividends on Common Stock $ 24,000 $ 10,000 $ - $ - ========== ========= ======== ========= Total Assets................. $1,014,649 $963,579 $900,821 $818,123 ========== ======== ======== ======== Long-Term Debt (a)........... $ 560,000 $560,000 $560,000 $560,000 ========== ======== ======== ======== (a) Includes portion due within one year.
STATISTICS 1995 1994 1993 1992* - -------------------------------------------------------------------------------------- Gross Electric Utility Plant at December 31, (Thousands of Dollars)....... $ 806,892 $792,880 $789,127 $774,920 ========= ======== ======== ======== kWh Sales (Millions) for the twelve month period ending December 31,. 3,016 2,229 3,218 1,268 ========= ======== ======== ========
- ---------------------------------------------------------------------- STATEMENTS OF QUARTERLY FINANCIAL DATA (Unaudited) - ------------------------------------------------------- Quarter Ended ------------------------------------------------ 1995 March 31 June 30 September 30 December 31 - ------------------------------------------------------------------------------ Operating Revenues.......... $33,984 $36,362 $39,696 $47,141 ======= ======= ======= ======= Operating Income............ $10,974 $12,752 $13,795 $13,873 ======= ======= ======= ======= Net Income.................. $ 7,501 $ 3,280 $ 6,914 $ 6,746 ======= ======= ======= ======= 1994 - ---------------------------------------------------------------------------- Operating Revenues.......... $32,211 $40,011 $37,603 $35,926 ======= ======= ======= ======= Operating Income............ $ 8,594 $10,718 $11,851 $11,787 ======= ======= ======= ======= Net Income.................. $ 6,643 $ 6,725 $ 8,161 $ 9,006 ======= ======= ======== ======= *The company began commercial operations on June 5, 1992. Information presented for 1992 covers the period June 5, 1992 through December 31, 1992. EX-21 21 SUBSIDIARIES OF THE REGISTRANT NORTHEAST UTILITIES SYSTEM Exhibit 21 SUBSIDIARIES OF THE REGISTRANT Northeast Utilities The Connecticut Light and Power Company (100%) - CL&P Capital, L.P. (3%) - Research Park, Inc. (100%) - The City and Suburban Electric and Gas Company (100%) - Electric Power Incorporated (100%) - The Connecticut Transmission Corporation (100%) - The Nutmeg Power Company (100%) - The Connecticut Steam Company (100%) - Connecticut Yankee Atomic Power Company (34.5%) - Yankee Atomic Electric Company (24.5%) - Maine Yankee Atomic Power Company (12%) - Vermont Yankee Nuclear Power Corporation (9.5%) Public Service Company of New Hampshire (100%) - Properties, Inc. (100%) - New Hampshire Electric Company (100%) - Connecticut Yankee Atomic Power Company (5%) - Yankee Atomic Electric Company (7%) - Maine Yankee Atomic Power Company (5%) - Vermont Yankee Nuclear Power Corporation (4%) North Atlantic Energy Corporation (100%) North Atlantic Energy Service Corporation (100%) Western Massachusetts Electric Company (100%) - Connecticut Yankee Atomic Power Company (9.5%) - Yankee Atomic Electric Company (7%) - Maine Yankee Atomic Power Company (3%) - Vermont Yankee Nuclear Power Corporation (2.5%) Holyoke Water Power Company (100%) - Holyoke Power and Electric Company (100%) Charter Oak Energy, Inc. (100%) - Charter Oak Paris, Inc. (100%) - COE Development Corporation (100%) - COE (UK) Corp. (79.9%) - COE (Gencoe) Corp. (49%) -COE (UK) Corp. (20.1%) - COE (Argentina I Corp.) (100%) - COE (Argentina II Corp.) (100%) - COE Tejona Corporation (100%) - COE Ave Fenix Corporation (100%) Northeast Nuclear Energy Company (100%) Northeast Utilities Service Company (100%) The Quinnehtuk Company (100%) The Rocky River Realty Company (100%) HEC, Inc. (100%) - HEC International Corporation (100%) - HEC Energy Consulting Canada, Inc. (100%) - Southwest HEC Energy Services, L.L.C. (100%) EX-27.1 22 FDS FOR NU
UT 0000072741 NORTHEAST UTILITIES AND SUBSIDIARIES 1,000 YEAR DEC-31-1995 DEC-31-1995 PER-BOOK 7,000,837 505,897 917,409 2,120,823 0 10,544,966 678,056 936,308 1,007,340 2,423,552 302,500 169,700 3,705,215 99,000 0 0 218,157 1,500 147,372 83,110 3,394,860 10,544,966 3,748,991 261,970 2,895,783 3,157,011 591,980 29,793 621,031 299,218 321,813 39,379 282,434 221,701 315,862 883,334 2.24 0.00 EX-27.2 23 FDS FOR CL&P
UT 0000023426 THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES 1,000 YEAR DEC-31-1995 DEC-31-1995 PER-BOOK 3,970,633 307,468 517,041 1,235,593 0 6,030,735 122,229 637,981 785,476 1,545,686 155,000 116,200 1,812,646 51,750 0 0 9,372 0 108,408 63,856 2,167,817 6,030,735 2,386,107 181,324 1,883,735 2,062,081 324,026 12,398 333,446 128,230 205,216 21,185 184,031 164,154 124,350 528,923 0.00 0.00 EX-27.3 24 FDS FOR WMECO
UT 0000106170 WESTERN MASSACHUSETTS ELECTRIC COMPANY 1,000 YEAR DEC-31-1995 DEC-31-1995 PER-BOOK 822,397 88,702 68,765 162,482 0 1,142,346 26,812 150,182 115,296 292,290 22,500 53,500 347,470 24,050 0 0 0 1,500 20,855 15,156 365,025 1,142,346 420,208 13,798 343,084 357,144 63,064 3,003 66,329 27,196 39,133 4,944 34,189 30,223 26,840 88,171 0.00 0.00 EX-27.4 25 FDS FOR PSNH
UT 0000315256 PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE 1,000 YEAR DEC-31-1995 DEC-31-1995 PER-BOOK 1,613,906 22,500 199,474 1,073,756 0 2,909,636 1 422,385 143,039 565,425 125,000 0 686,485 0 0 0 172,500 0 874,292 40,996 444,938 2,909,636 979,590 70,587 754,312 824,070 155,520 4,974 159,665 76,410 83,255 13,250 70,005 52,000 76,320 237,947 0.00 0.00 EX-27.5 26 FDS FOR NAEC
UT 0000880416 NORTH ATLANTIC ENERGY CORPORATION 1,000 YEAR DEC-31-1995 DEC-31-1995 PER-BOOK 707,120 15,534 46,002 245,993 0 1,014,649 1 160,999 59,677 220,677 0 0 540,000 8,000 0 0 20,000 0 0 0 225,972 1,014,649 157,183 7,411 95,602 105,789 51,394 10,961 65,131 40,690 24,441 0 24,441 24,000 62,721 17,307 0.00 0.00 -----END PRIVACY-ENHANCED MESSAGE-----