10-K 1 MAIN 10-K DOCUMENT NORTHEAST UTILITIES THE CONNECTICUT LIGHT AND POWER COMPANY PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE WESTERN MASSACHUSETTS ELECTRIC COMPANY NORTH ATLANTIC ENERGY CORPORATION 1994 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. . . . . . . . . . . . . 2 The Economy . . . . . . . . . . . . . . . . . 3 Retail Marketing. . . . . . . . . . . . . . . 3 Wholesale Marketing . . . . . . . . . . . . . 5 Rates. . . . . . . . . . . . . . . . . . . . . . . 6 Connecticut Retail Rates. . . . . . . . . . . 6 New Hampshire Retail Rates. . . . . . . . . . 8 Massachusetts Retail Rates. . . . . . . . . . 11 Resource Plans . . . . . . . . . . . . . . . . . . 13 Construction. . . . . . . . . . . . . . . . . 13 Future Needs. . . . . . . . . . . . . . . . . 13 Financing Program. . . . . . . . . . . . . . . . . 14 1994 Financings . . . . . . . . . . . . . . . 14 1995 Financing Requirements . . . . . . . . . 15 1995 Financing Plans. . . . . . . . . . . . . 15 Financing Limitations . . . . . . . . . . . . 15 Electric Operations. . . . . . . . . . . . . . . . 18 Distribution and Load . . . . . . . . . . . . 18 Generation and Transmission . . . . . . . . . 21 Fossil Fuels. . . . . . . . . . . . . . . . . 21 Nuclear Generation. . . . . . . . . . . . . . 22 Non-Utility Businesses. . . . . . . . . . . . . . . 32 General . . . . . . . . . . . . . . . . . . . 32 Private Power Development . . . . . . . . . . 33 Energy Management Services. . . . . . . . . . 33 Regulatory and Environmental Matters . . . . . . . 34 Environmental Regulation. . . . . . . . . . . 34 Electric and Magnetic Fields. . . . . . . . . 41 FERC Hydro Project Licensing. . . . . . . . . 42 Employees. . . . . . . . . . . . . . . . . . . . . 42 Subsequent Events. . . . . . . . . . . . . . . . . 44 Item 2. Properties. . . . . . . . . . . . . . . . . . 46 Item 3. Legal Proceedings . . . . . . . . . . . . . . 51 Item 4. Submission of Matters to a Vote of Security Holders . . . . . . . . . . . . . . . . . . . 54 PART II Item 5. Market for Registrants' Common Equity and Related Shareholder Matters . . . . . . . . . 55 Item 6. Selected Financial Data . . . . . . . . . . . 55 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations. . . . . . . . . . . . . . . . . 57 Item 8. Financial Statements and Supplementary Data . 57 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure . . . 58 PART III Item 10. Directors and Executive Officers of the Registrants . . . . . . . . . . . . . . . . . 59 Item 11. Executive Compensation. . . . . . . . . . . . 63 Item 12. Security Ownership of Certain Beneficial Owners and Management . . . . . . . . . . . . 67 Item 13. Certain Relationships and Related Transactions. . . . . . . . . . . . . . . . . 69 PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K . . . . . . . . . . . 70 GLOSSARY OF TERMS The following is a glossary of frequently used abbreviations or acronyms that are found throughout this report: COMPANIES NU. . . . . . . . . . . . . . Northeast Utilities CL&P . . . . . . . . . . . . The Connecticut Light and Power Company 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 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 GENERATING UNITS Millstone 1 . . . . . . . . . Millstone Unit No. 1, a 660-MW nuclear electric 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 GLOSSARY OF TERMS REGULATORS (Continued) 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 AFUDC . . . . . . . . . . . . Allowance for funds used during construction CC. . . . . . . . . . . . . . Conservation charge DSM . . . . . . . . . . . . . Demand-Side Management Energy Policy Act . . . . . . Energy Policy Act of 1992 FPPAC . . . . . . . . . . . . Fuel and purchased power adjustment clause (PSNH) GUAC. . . . . . . . . . . . . Generation utilization adjustment clause (CL&P) IRM . . . . . . . . . . . . . Integrated resource management 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 ROE . . . . . . . . . . . . . Return on equity 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). It is not itself 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 eight municipal electric systems and investor-owned utilities. The System companies also supply other wholesale electric services to various municipalities and other utilities. NU 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, which sells its share of the capacity and output of the Seabrook nuclear generating facility (Seabrook) in Seabrook, New Hampshire, to PSNH under two life-of-unit, full cost recovery contracts. NU's subsidiary North Atlantic Energy Service Corporation (North Atlantic or NAESCO) has operational responsibility for Seabrook. Other 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 or the Service Company) provides 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 the System companies and other New England utilities in operating the Millstone nuclear generating facilities in Connecticut. North Atlantic acts as agent for the System companies and other New England utilities in operating Seabrook. 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 non-utility businesses. Directly and through subsidiaries, Charter Oak develops and invests in cogeneration, small power production and other forms of non-utility 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 commercial, industrial and institutional electric customers. See "Nonutility Businesses." A reorganization of NU entailing realignment into two core business groups became effective on January 1, 1994. The first group, the energy resources group, is devoted to energy resource acquisition and wholesale marketing and focuses on nuclear, fossil and hydroelectric generation and wholesale power marketing. The other 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 are served by various support functions known collectively as the corporate center. In connection with NU's reorganization, the System is undergoing a corporate reengineering process to assist in identifying opportunities to become more competitive while improving customer service and maintaining a high level of operational performance. PUBLIC UTILITY REGULATION NU is 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, accounts and records, involvement in non-utility 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. The System companies are subject to the Federal Power Act as administered by the Federal Energy Regulatory Commission (FERC). The Energy Policy Act amended this 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. In addition, the Nuclear Regulatory Commission (NRC) has broad jurisdiction over the System's nuclear units and 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. 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. See generally "Rates," "Electric Operations" and "Regulatory and Environmental Matters." COMPETITION AND MARKETING Competitive forces within the electric utility industry are continuing to increase due to a variety of influences, including legislative and regulatory actions, technological advances and changes in consumer demands. In response, the System has developed, and is continuing to develop, a number of initiatives to retain and continue to serve its existing customers and to expand its retail and wholesale customer base. The System also benefits from a diverse retail base. The System has no significant dependence on any one retail customer or industry. THE ECONOMY In 1994, the System experienced its most significant retail sales growth in six years, due in large part to the economic recovery in New England. Employment levels have risen, particularly in New Hampshire, unemployment rates have fallen, and personal income has increased in all three states comprising the System's retail service territory. The System's 1994 retail sales, which comprise 77 percent of all kilowatt-hour sales, rose by a total of 2.9 percent or 867 million kilowatt-hours over 1993. Retail sales growth was consistent across all major customer classes, with residential sales rising by 2.8 percent, commercial sales by 3.2 percent and industrial sales by 2.6 percent. Retail sales growth was strongest for CL&P, which recorded an increase of 3.4 percent, and weakest for WMECO, which experienced a 1.4 percent increase. At PSNH, retail sales rose by 2.0 percent. Overall, weather had little effect on sales volume, with mild weather after mid-August offsetting unusually cold weather in January and hot weather in late June and July. In 1995, the System expects little retail sales growth from 1994, primarily because of the effects of higher interest rates on the regional economy and further cutbacks in defense-related industries in Connecticut. Over the longer term, retail sales growth is expected to be strongest in New Hampshire, which by some measures has the fastest-growing economy in New England. In 1994, many businesses announced plans to expand in New Hampshire. The System estimates that PSNH will have compounded annual sales growth of 1.9 percent from 1994 through 1999, compared with 1.4 percent for CL&P and 0.9 percent for WMECO. Wholesale sales, which comprised the remaining 23 percent of all sales, rose 0.8 percent or 75 million kilowatt-hours in 1994, due to aggressive marketing efforts and the opening of new wholesale markets as a result of increased wholesale competition, including the addition of Madison, Maine as a wholesale customer. RETAIL MARKETING Retail sales growth and the System's success in lowering operating costs were the primary reasons for the improvement in NU's financial performance in 1994. Because the System has surplus generating capacity, additional demand can be easily met from existing generation. As a result, the additional costs of serving expanding load--principally the cost of additional fuel--are far less than the revenues received from the additional kilowatt-hour sales. 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 required in any of the System's jurisdictions. In 1994, Connecticut regulators reviewed the desirability of retail wheeling and determined that it was not in the best interest of the state until new generating capacity is needed, which the System projects to be in 2009. The Connecticut Department of Public Utility Control (DPUC) is presently conducting a generic proceeding studying the restructuring of the electric industry and competition in order to develop findings and recommendations to be presented to policymakers at the legislative level. A decision in this proceeding is expected in mid-1995. In New Hampshire, several bills related to retail wheeling have been introduced in the legislature. The chairman of the New Hampshire Public Utilities Commission (NHPUC) has set up a roundtable discussion with legislators, utilities and large customers on how to deal with a more competitive market. In addition, a new entity, Freedom Electric Power Company (FEPCO), has filed with the NHPUC for permission to do business as an electric utility to serve selected large PSNH customers. PSNH and other New Hampshire utilities are opposing FEPCO's petition before the NHPUC. There also have been several bills introduced in Massachusetts that involve the potential for retail wheeling, electric utility industry restructuring and regulatory reform. To date, none of these bills have been enacted. On February 10, 1995, the Massachusetts Department of Public Utilities (DPU) initiated an investigation into various ways in which the electric utility industry in Massachusetts could be restructured. The DPU has asked interested parties to comment on numerous topics such as competition and customer choice by March 31, 1995. It is not known when the DPU will issue an order in this proceeding. While retail wheeling is not required in the System's retail service territory, competitive forces nonetheless are influencing retail pricing. These include competition from alternate fuels such as natural gas, competition from customer-owned generation and regional competition for business retention and expansion. The System's retail business group is continuing to work with customers to address their concerns. Since the fall of 1991, the System companies have reached approximately 230 special rate agreements with customers to increase or retain their electricity purchases from the System, including 124 CL&P customers, 54 PSNH customers and 44 WMECO customers through the end of 1994. These agreements include 135 agreements to retain existing customers and 87 agreements for new customers and account for approximately four percent of System 1994 retail revenues. In general, these special rate agreements have terms of approximately five years. Most of CL&P's agreements have been entered pursuant to general rate riders approved by the DPUC. Most of PSNH's special contracts require individual approval from the NHPUC. The DPU requires individual approval of some special contracts, but in 1994 the DPU also authorized WMECO to reduce rates by five 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. As of December 31, 1994, ten WMECO customers had signed up for this service extension discount. Many of the special rate agreements were reached individually on a customer-by-customer basis. However, three significant groups of customers also entered agreements with certain of the System companies over the past two years. In 1993, HWP entered ten-year contracts with all of its approximately 40 retail industrial customers, which accounted for approximately $7 million of revenue in 1994. PSNH entered into long-term contracts with approximately 30 sawmill operators and nine ski resorts in 1994. Negotiated retail rate reductions for System customers under rate agreements in effect for 1994 amounted to approximately $20 million, including $11 million for CL&P, $3 million for PSNH, $4 million for WMECO and $2 million for HWP. Management believes that the aggregate amount of retail rate reductions will increase in 1995, but that such agreements will continue to provide significant benefits to the System including the preservation of approximately four percent of retail revenues. Special rate agreements represent only a portion of the System's response to the new competitive forces in the energy marketplace. The System spent approximately $46 million in 1994 on demand side management (DSM) programs. Over 60 percent of DSM program costs were targeted to the commercial and industrial sectors. These programs help customers improve the efficiency of their electric lighting, manufacturing, and heating, ventilating and air conditioning systems, making them more competitive in their own markets, which in turn enables them to be more viable employers in the System's service territories. DSM program costs are recovered from customers through various cost recovery adjustment mechanisms. For further information on DSM programs, see "Rates - Connecticut Retail Rates - Demand Side Management" and "Rates - Massachusetts Retail Rates - Demand Side Management." System companies also are increasingly working with customers to improve reliability and power quality within commercial and industrial facilities. Many of the System's programs for residential customers are targeted at improving the efficiency of lighting and electric space heating, as well as the energy efficiency of new homes. Residential space heating represents approximately five percent of the System's retail electric sales, and suppliers of alternative fuels, such as natural gas, have actively recruited residential customers to convert their heating systems from electric heat. In 1994, an increase in the number of CL&P's space heating customers offset decreases in the numbers of WMECO's and PSNH's space heating customers. 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). Many of the sales contracts signed by the System companies in the late 1980's have expired or will expire in the mid-1990's, and much of the revenue produced by such contracts has not been replaced through new wholesale power arrangements. In 1994, wholesale sales, including firm wholesale service and other bulk supply transactions, accounted for approximately $331 million, or approximately 9.2 percent, of System revenues, down from approximately $383 million in 1993, due in large part to the loss of one major customer and the increased competitiveness of the wholesale market. Unless prices on the wholesale market improve, revenues are expected to fall further in 1995 before stabilizing in late 1996 and 1997. Wholesale sales are made primarily to investor-owned utilities and municipal systems or cooperative electric systems in the Northeast. The System will be increasing its efforts to increase wholesale sales through intensified marketing efforts. The System's power marketing efforts benefit from the interconnection of its transmission system with all of the major utilities in New England, as well as with three of the largest electric utilities in New York state. The System's 1994 firm wholesale sales were approximately 1.3 million megawatt-hours. In 1994, firm wholesale electric service accounted for approximately 2.5 percent of the System's revenues (approximately 1.4 percent of CL&P's operating revenue, 6 percent of PSNH's operating revenue and a negligible amount of WMECO's operating revenue). In 1994, the System companies commenced service under six long-term sales contracts with municipal electric systems, including five in Massachusetts and one in Maine. These power sales contracts have terms which range from five to ten years. The related revenues, which amounted to approximately $4 million in 1994, are expected to increase over the coming years. The System also sold an average of approximately 400 MW of power during 1994 in short-term sales to four utilities in New York State. Those sales ranged in duration from a week to six months and accounted for approximately $54 million in System revenues in 1994. The System owns approximately one-half of the 2,000 MW of surplus capacity in New England. This surplus and the resulting competition for business has caused the System to renegotiate some of its arrangements with its existing wholesale customers. For example, in 1994 CL&P began serving the City of Chicopee, Massachusetts under a new ten-year arrangement. Furthermore, CL&P and the Town of Wallingford, Connecticut signed a contract for service of Wallingford's approximate 110 MW load for a ten-year period beginning in 1995. The new arrangement was coordinated through the Connecticut Municipal Electric Energy Cooperative, an organization that assists municipalities with their energy needs, and supersedes CL&P's current firm wholesale contract with Wallingford. In these cases, due to wholesale competition, the customers were able to secure prices lower than those that would have been paid under traditional cost-of-service ratemaking. Similarly, long-term agreements were renegotiated before 1994 with the New Hampshire Electric Cooperative and several other municipal and small investor-owned electric systems in Connecticut, New Hampshire and Massachusetts. 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. In 1994, the System companies collected approximately $42 million in transmission revenues for transmission of power sales emanating from either the System or from other generating plants. See "Electric Operations - Generation and Transmission" for further information on bulk supply transactions and for information on pending FERC proceedings relating to transmission service. All of the wholesale electric transactions of CL&P, PSNH, WMECO, NAEC and HWP are subject to the jurisdiction of the FERC. For a discussion of certain FERC-regulated sales of power by CL&P, PSNH, WMECO and HWP to other utilities, see "Electric Operations - Distribution and Load." For a discussion of sales of power by NAEC to PSNH, see "Rates - Seabrook Power Contract." RATES CONNECTICUT RETAIL RATES GENERAL CL&P's retail electric rate schedules are subject to the jurisdiction of the DPUC. Connecticut law provides that increased rates may not be put into effect without the prior approval of the DPUC. Connecticut law authorizes the DPUC to order a rate reduction before holding a full-scale rate proceeding if it finds that (i) a utility's earnings exceed authorized levels by one percentage point or more for six consecutive months, (ii) tax law changes significantly increase the utility's profits, or (iii) the utility may be collecting rates that are more than just and reasonable. The law requires the DPUC to give notice to the utility and any customers affected by the interim decrease. The utility would be afforded a hearing. If final rates set after a full rate proceeding or court appeal are higher, customers would be surcharged to make up the difference. 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 provides 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. The rate increases were implemented as scheduled in 1993 and 1994. For more information regarding the 1993 Decision, see "Legal Proceedings." CL&P ADJUSTMENT CLAUSES CL&P has a fossil fuel and purchased power adjustment clause pursuant to which CL&P, subject to periodic review by the DPUC, recovers or refunds substantially all prudently incurred expenses and credits applicable to its retail electric rates on a current basis. 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 twelve-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 twelve-month period beginning September 1. On January 5, 1994, the DPUC issued a decision ordering CL&P not to include a GUAC amount in customers' bills through August 1994. The DPUC found that CL&P overrecovered its fuel costs during the 1992-1993 GUAC period and offset the amount of the overrecovery against the unrecovered GUAC balance. The effect of the order was a disallowance of $7.9 million. On March 4, 1994, CL&P appealed this decision to Hartford Superior Court and expects a decision in the spring of 1995. In the most recent GUAC period, which ended July 31, 1994, the actual level of nuclear generating performance was 68.2 percent, resulting in a GUAC deferral of $23.7 million to be collected from customers beginning in September 1994. On December 30, 1994, the DPUC ordered CL&P to collect from customers over the ensuing eight months only $15.9 million of the $23.7 million GUAC deferral accrued during the 1993-1994 GUAC year. The DPUC disallowed $7.8 million of the deferral, finding that CL&P had overrecovered that amount through base rate fuel recoveries. The DPUC further stated that it would follow a similar course in the future. CL&P has also appealed this order. For the GUAC year ended July 31, 1995, CL&P expects to defer in excess of $50 million of GUAC fuel costs for projected nuclear performance below 72 percent. As of December 31, 1994, CL&P has reserved $13 million against this amount based on the methodology applied by the DPUC in previous GUAC decisions. 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, which occurred during the period October 1990 - February 1992. Three of these prudence reviews are either on appeal or still pending at the DPUC. Approximately $92 million of costs are at issue in these remaining cases, some or all of which may be disallowed. 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. For further information on these prudence reviews, see "Nuclear Performance" in the notes to NU's and CL&P's financial statements. 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 conservation costs in excess of costs reflected in base rates over periods ranging from 3.85 to 10 years. In June 1994, the DPUC issued an order approving a reduction in the amortization period from eight years to 3.85 years for CL&P's 1994 DSM expenditures, which will allow CL&P to recover its total 1994 program budget of $40 million over 3.85 years beginning in 1994. On October 31, 1994, CL&P filed an application with the DPUC regarding CL&P's 1995 DSM expenditures, program designs, performance incentive mechanism and lost fixed-cost recovery. CL&P proposed a budget level of $36.7 million for 1995 DSM expenditures and an amortization period for new expenditures of 3.93 years. The DPUC began hearings on the proposed budget and programs during November 1994. CL&P's unrecovered DSM costs at December 31, 1994, excluding carrying costs, which are collected currently, were approximately $116 million. NEW HAMPSHIRE RETAIL RATES RATE AGREEMENT AND FPPAC PSNH's 1989 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 five base rate increases went into effect as scheduled and the remaining two base rate increases will be put in effect on June 1, 1995 and June 1, 1996, concurrently with semi-annual adjustments in the FPPAC. Political and economic pressures, caused by historically high retail electric rates in New Hampshire, may inhibit additional rate increases, including FPPAC increases, above 5.5 percent per year during the next two years, may lead to challenges to the Rate Agreement in the future and may limit rate recoveries after the period for the seven 5.5 percent increases has ended. In accordance with the schedule for rate increases under the Rate Agreement, PSNH increased its average retail electric rates by about 5.5 percent in June 1994. 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, 1993 through May 31, 1994, the NHPUC approved an increase in the FPPAC rate which resulted in a 1.8% increase in overall base rates. For the period June 1, 1994 through November 30, 1994, the NHPUC approved an increase in the FPPAC rate consistent with an overall increase in base rates of 5.5% For the period December 1, 1994 through May 31, 1995, the NHPUC approved a continuation of the current FPPAC rate. This rate treatment allowed PSNH to limit overall rate increases in 1994 to a level that did not exceed 5.5%, while maintaining an FPPAC rate level sufficient to collect the Seabrook refueling costs over four periods through rates by the end of November 30, 1995. The FPPAC rate is not expected to increase in 1995. The costs associated with purchases by PSNH from certain NUGs at prices over the level assumed in rates and a portion of the payments to New Hampshire Electric Cooperative, Inc. (NHEC) for PSNH's buyback of NHEC's Seabrook entitlement are deferred and recovered through the FPPAC over ten years. As of December 31, 1994, NUG and NHEC deferrals totaled approximately $174 and $20.3 million, respectively. Under the Rate Agreement, PSNH has an obligation to use its best efforts to renegotiate burdensome purchase power arrangements with 13 specified NUGs that were selling their output to PSNH under long term rate orders. In general, PSNH has been attempting to exchange present cash payments for relief from high-cost purchased power obligations to the NUGs, with such payments and an associated return being recoverable from customers over a future amortization period. For more information regarding the Rate Agreement, see "PSNH Rate Agreement" in the notes to NU's and PSNH's financial statements. On April 19, 1994, the NHPUC approved new purchase power agreements with five hydroelectric NUGs. These agreements were effective retroactive to January 1993. Management anticipates that the initial decrease in payments to these NUGs during a year with normal water flow will average approximately 14 percent or $1.4 million per year. PSNH will flow the savings resulting from these new agreements through the FPPAC to its customers. The first of these new power purchase agreements will expire in 2022. The NHPUC deferred action on whether PSNH had exercised its best effort to renegotiate the agreements. In addition, PSNH has been involved in negotiations with eight wood-fired NUGs. On September 23, 1994, the NHPUC approved settlement agreements with two 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. These NUGs also agreed not to compete with PSNH or other NU subsidiaries. Under New Hampshire legislation passed in May 1994, PSNH and the remaining six wood-fired NUGs were directed to continue negotiations concerning their power sales arrangements. Absent successful negotiations, the parties were directed to enter into a mediation process to be completed by November 14, 1994. The legislation required the parties to attempt to agree on a settlement under which the payments PSNH made for the NUGs' power would be lowered but the plants would continue to operate. At a January 4, 1995 status hearing, the NHPUC directed further mediation to take place with a representative from the State of New Hampshire assisting the parties. Only one agreement emerged from the mediation process, which calls for a payment of $52 million in return for a substantial reduction in the rates charged to PSNH. This agreement was filed with the NHPUC in February 1995. The Rate Agreement also provides for the recovery by PSNH through rates of a regulatory asset, 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 regulatory asset at December 31, 1994 was approximately $679 million. In accordance with the Rate Agreement, approximately $204 million of the remaining regulatory asset is scheduled to be amortized and recovered through rates by 1998, and the remaining amount, approximately $475 million, is being amortized and recovered through rates by 2011. PSNH earns a return each year on the unamortized portion of the asset. For more information regarding PSNH's recovery of this regulatory asset after 1997, see "Regulatory Asset-PSNH" in the notes to NU's financial statements and "Regulatory Asset" in the notes to PSNH's financial statements. SEABROOK POWER CONTRACT PSNH and NAEC entered into the Seabrook Power Contract (Contract) in June 1992. Under the terms of the Contract, PSNH is obligated to purchase NAEC's initial 35.56942% ownership share of the capacity and output of Seabrook 1 for the term of Seabrook's NRC operating license and to pay NAEC's "cost of service" during this period, whether or not Seabrook 1 continues to operate. NAEC's cost of service includes all of its prudently incurred Seabrook 1-related costs, including maintenance and operation expenses, cost of fuel, depreciation of NAEC's recoverable investment in Seabrook 1 and a phased-in return on that investment. The payments by PSNH to NAEC under the Contract 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 Rates - Rate Agreement and FPPAC" for information relating to the Rate Agreement. At December 31, 1994, NAEC's net utility plant investment in Seabrook 1 was approximately $718 million. If Seabrook 1 were retired prior to the expiration of its NRC operating license term, NAEC would continue to be entitled under the Contract to recover its remaining Seabrook investment and a return on that investment and its other Seabrook-related costs for 39 years, less the period during which Seabrook 1 has operated. The Contract provides that NAEC's return on its "allowed investment" in Seabrook 1 (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 Contract, its actual debt and preferred equity costs, and a common equity cost of 12.53 percent for the first ten years of the Contract, and thereafter at an equity rate of return to be fixed in a filing with the 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 1997. As of December 31, 1994, 70 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, 1994, the amount of this deferred return was $131.5 million. For additional information regarding the Contract and a similar contract, which involves NAEC's acquisition of Vermont Electric Generation and Transmission Cooperative, Inc.'s ownership interest in Seabrook, see "Seabrook Power Contract" in the notes to PSNH's financial statements. MASSACHUSETTS RETAIL RATES GENERAL WMECO's retail electric rate schedules 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. On May 26, 1994, the DPU approved a settlement offer from WMECO and the Massachusetts Attorney General that, among other things, provided that: (1) all pending WMECO generating unit performance review proceedings regarding unit outages from mid-1987 through mid-1993 would be terminated without findings; (2) WMECO's customers' overall bills will be reduced by approximately $13.3 million over the 20-month period June 1, 1994 to January 31, 1996; (3) WMECO will not file for increased base rates effective before February 1, 1996; (4) WMECO will amortize post-retirement benefits other than pensions costs over a three-year period starting July 1, 1994; and (5) WMECO will offer a five percent rate reduction to its largest customers who agree not to self-generate or take electricity from another provider for five years. The settlement did not have a significant adverse impact on WMECO's 1994 earnings. 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 January 21, 1994 the DPU approved a settlement offer from WMECO, the Massachusetts Attorney General, the Massachusetts Division of Energy Resources (DOER), the Conservation Law Foundation (CLF) and the Massachusetts Public Interest Research Group (MASSPIRG) pre-approving DSM funding levels for 1994 and 1995 of $14.2 million and $15.8 million, respectively. The settlement also provides for cost recovery adjustments and an incentive mechanism if certain implementation objectives are met. In a subsequent proceeding, the DPU established a CC for each rate class at least through 1994 (and ordered deferred recovery of conservation-related costs in connection with two rate classes) and examined the level of conservation savings delivered by WMECO programs in prior years (and disallowed certain claimed conservation savings). On January 11, 1995, the DPU initiated hearings to set CCs for 1995, review the claimed level of conservation savings delivered and review the mechanism for determining lost fixed-cost recovery. Recently, in proceedings involving two other utilities, the DPU changed its policy to limit recovery of lost revenues due to implementation of conservation measures to a fixed period. If such a policy is implemented for WMECO, WMECO could lose several millions of dollars of revenues starting in 1996 and possibly as early as 1995. Further hearings for WMECO's docket are scheduled for March 1995. Management cannot predict when the DPU will issue a decision in this case. 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 quarterly fuel clause. The DPU must hold public hearings before permitting quarterly 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 the operation of the Northeast Utilities Generation and Transmission Agreement (NUG&T). The NUG&T is the FERC-approved contract among the System operating companies, other than PSNH, that provides for the sharing among the companies on a system-wide basis costs of generation and transmission and serves as the basis for planning and operating the System's bulk power supply system on a unified basis. 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 if a utility fails to meet the fuel procurement and use performance goals set for that utility. 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, as discussed above, for the three Millstone units and for the three regional nuclear operating units (the Yankee plants) in which WMECO has ownership interests. Subsequent to the May 26, 1994 settlement between WMECO and the DPU, the DPU initiated a review of WMECO's 1993-1994 generating unit performance. Hearings have not begun in that proceeding and it is not known when the DPU may issue a decision. RESOURCE PLANS CONSTRUCTION The System's construction program expenditures, including allowance for funds used during construction (AFUDC), in the period 1995 through 1999 are estimated to be as follows: 1995 1996 1997 1998 1999 (Millions) CL&P $148 $136 $144 $145 $145 PSNH 51 36 32 39 39 WMECO 36 28 29 39 39 NAEC 5 8 7 6 6 OTHER 14 10 10 10 10 ---- ---- ---- ---- ---- TOTAL $254 $218 $222 $239 $239 ==== ==== ==== ==== ==== 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, improved reliability or other causes. The construction program's main focus is maintaining and upgrading the existing transmission and distribution system, as well as 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 2009. 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 2009 by over 650 MW. See "Rates - Connecticut Retail Rates - Demand Side Management" and "Rates - Massachusetts Retail Rates - Demand Side Management" 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 680 MW of firm capacity in 1994. This is the maximum amount that the System companies expect to purchase from NUGs for the foreseeable future. See "New Hampshire Retail Rates - Rate Agreement and FPPAC" for information concerning PSNH's efforts to renegotiate its agreements with thirteen NUGs. 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 and possibly repowering certain of the System's older fossil plants. 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 1900 MW of resources by 2009 that would otherwise have been retired. In addition, repowering of some of the System's retired generating plants could provide the System with approximately 900 MW of capacity. The capacity could be brought on line in various increments timed with the year of need. 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. For information regarding the agreement concerning NOX emissions at the Merrimack units, see "Regulatory and Environmental Matters - Environmental Regulation - Air Quality Requirements." See "Electric Operations - Nuclear Generation - Nuclear Plant Licensing and NRC Regulation" and - "Nuclear Performance" for further information on the NRC rule on nuclear plant operating license renewal, and information on the expiration dates of the operating licenses of the nuclear plants in which the System companies have interests. Before the System can make any decisions about whether license extensions for any of its nuclear units are feasible, detailed technical and economic studies will be needed. The System's long-term resource plan also anticipates that the System's nuclear units will continue to run through the scheduled terms of their respective operating licenses. For information regarding the early retirement of one of the System's nuclear units, see "Electric Operations - Nuclear Generation - Nuclear Performance" and - "Decommissioning." FINANCING PROGRAM 1994 FINANCINGS In 1994, CL&P and WMECO issued $535 and $90 million, respectively, of first mortgage bonds. In virtually all cases, new issues of first mortgage bonds were of smaller principal amounts than the issues that were retired with the proceeds of such issuances, with cash derived from operations making up the balance of funds needed to effect the retirements. This was done as part of NU's overall effort to reduce the System companies' debt levels. Total debt, including short-term and capitalized leased obligations, was $4.54 billion as of December 31, 1994, compared with $4.88 billion as of December 31, 1993 and $5.21 billion as of December 31, 1992. For more information regarding 1994 financings, see Notes to Consolidated Statements of Capitalization of NU and "Long-Term Debt" in the notes to CL&P's, PSNH's, WMECO's and NAEC's financial statements. 1995 FINANCING REQUIREMENTS In addition to financing the construction requirements described under "Resource Plans - Construction," the System companies are obligated to meet $1.3 billion of long-term debt maturities and cash sinking fund requirements and $124.9 million of preferred stock cash sinking fund requirements in 1995 through 1999. In 1995, long-term debt maturity and cash sinking fund requirements will be $175.8 million, consisting of $11.9 million of cash sinking fund requirements to be met by CL&P, $94 million of cash sinking fund requirements to be met by PSNH, $35.8 million of long-term debt maturities and cash sinking fund requirements to be met by WMECO, $20 million of cash sinking fund requirements to be met by NAEC and $14.1 million of cash sinking fund requirements to be met by other subsidiaries. The System's aggregate capital requirements for 1995, exclusive of requirements under the Niantic Bay Fuel Trust (NBFT), are as follows: Total CL&P PSNH WMECO NAEC Other System (Millions of Dollars) Construction (including AFUDC)..... $148 $51 $36 $ 5 $14 $254 Nuclear Fuel (excluding AFUDC).. 47 1 11 9 - 68 Maturities.............. - - 35 - - 35 Cash Sinking Funds.. 12 94 1 20 14 141 ---- ---- --- --- --- ---- Total........... $207 $146 $83 $34 $28 $498 ==== ==== === === === ==== 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. 1995 FINANCING PLANS The System companies currently expect to finance their 1995 requirements through internal cash flow and short-term debt. This estimate excludes the nuclear fuel requirements financed through the NBFT. In addition to financing their 1995 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 at a lower effective cost. On January 23, 1995, CL&P issued, through an affiliate, $100 million of 9.3 percent Monthly Income Preferred Securities, to help finance the retirement of approximately $125 million of preferred stock. FINANCING LIMITATIONS The amounts of short-term borrowings that may be incurred by NU, CL&P, PSNH, WMECO, HWP, NAEC, NNECO, The Rocky River Realty Company (RRR), The Quinnehtuk Company (Quinnehtuk) (RRR and Quinnehtuk are real estate subsidiaries) and HEC are subject to periodic approval by the SEC under the 1935 Act. The following table shows the amount of short-term borrowings authorized by the SEC for each company as of January 1, 1995 and the amounts of outstanding short-term debt of those companies at the end of 1994. Maximum Authorized Short-Term Debt Short-Term Debt Outstanding at 12/31/94* (Millions) NU.................. $ 150 $ 104 CL&P ............... 325 179 PSNH ............... 175 - WMECO............... 60 - HWP................. 5 - NAEC................ 50 - NNECO............... 50 6 RRR................. 22 17 Quinnehtuk.......... 8 5 HEC................. 11 2 ----- Total $ 313 ===== ----------------- * This column includes borrowings of various System companies from NU and other System companies through the Northeast Utilities System Money Pool (Money Pool). Total System short term indebtedness to unaffiliated lenders was $190 million at December 31, 1994. 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 five percent of the total common equity of NU. As of March 1, 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 short term or other unsecured borrowings those companies may incur. As of December 31, 1994, CL&P's charter would permit CL&P to incur an additional $450.3 million of unsecured debt and WMECO's charter would permit it to incur an additional $145.5 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, 1994, CL&P's common equity ratio was 42.0 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 that requires, in effect, that the NU consolidated common equity (as defined) be at least 27 percent for three consecutive quarters. At December 31, 1994, NU's common equity ratio was 33.4 percent. Credit agreements to which PSNH is a party forbid its incurrence of 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 23 percent of total capitalization (as defined) through June 30, 1995 and 25 percent thereafter. In addition, PSNH must demonstrate that its ratio of operating income to interest expense will be at least 1.75 to 1 at the end of each fiscal quarter for the remaining term of the agreement. At December 31, 1994, PSNH's common equity ratio was 32.7 percent and its operating income to interest expense ratio for the twelve-month period was 2.69 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, 1994, including unallocated shares held by the ESOP trust, would be approximately $236.2 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 - Rate Agreement and FPPAC." NAEC paid dividends of $5 million in each of the third and fourth quarters of 1994. 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 or the issuance of additional common shares under the dividend reinvestment plan. 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, 1994, CL&P had $225.6 million, WMECO had $90.1 million and PSNH had $125.0 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, 1994, $69.2 million was available to be paid under this provision. PSNH's credit agreements prohibit PSNH 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, 1994, $162 million was available to be paid under these provisions. 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. The Service Company 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 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 4.0 million (2.5 million in Connecticut, 959,000 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 1994, CL&P furnished retail electric service to approximately 1.1 million customers in Connecticut, PSNH provided retail electric service to approximately 400,000 customers in New Hampshire and WMECO served approximately 194,000 retail electric customers in Massachusetts. HWP serves 46 retail customers in Holyoke, Massachusetts. The following table shows the sources of 1994 electric revenues based on categories of customers: CL&P PSNH WMECO NAEC Total System Residential........... 41% 35% 38% - 40% Commercial............ 34 28 31 - 33 Industrial ........... 14 18 19 - 16 Wholesale* ........... 9 16 9 100% 9 Other ................ 2 3 3 - 2 ---- ---- ---- ---- ---- Total ................ 100% 100% 100% 100% 100% * Includes capacity sales. NAEC's 1994 electric revenues were derived entirely from sales to PSNH under the Seabrook Power Contract. See "Rates - Seabrook Power Contract" for a discussion of the contract. Through December 31, 1994, the all-time maximum demand on the System was 6339 MW, which occurred on July 21, 1994. The System was also selling approximately 896 MW of capacity to other utilities at that time. At the time of the peak, the System's generating capacity, including capacity purchases, was 8948 MW. System energy requirements were met in 1993 and 1994 as set forth below: Source 1994 1993 Nuclear .................................... 54% 62% Oil ........................................ 7 7 Coal ....................................... 8 10 Hydroelectric .............................. 4 3 Natural gas ................................ 3 2 NUGs ....................................... 14 14 Purchased power............................. 10 2 ----- --- 100% 100% The actual changes in kilowatt-hour sales for the last two years and the forecasted sales growth estimates for the 10-year period 1994 through 2004, in each case exclusive of bulk power sales, for the System, CL&P, PSNH and WMECO are set forth below: 1994 over 1993 over Forecast 1994-2004 1993 (under) 1992 Compound Rate of Growth System......... 2.50% 10.9%(1) 1.2% CL&P........... 3.66% (0.3)% 1.1% PSNH........... 1.56% 1.0% 1.5% WMECO....... 1.47% 0.1% 1.2% (1) The percent increase in System 1993 sales over 1992 sales is due to the inclusion of PSNH sales beginning in June 1992. In 1990, FERC required the reclassification of bulk power sales from "purchased power" to "sales for resale" for 1990 and later reporting years. Bulk power sales are not included in the development of any long-term forecasted growth rates. The actual changes in kilowatt-hour sales for the last two years, adjusted for bulk power sales (by adding back the bulk power sales), for the System, CL&P, PSNH and WMECO are set forth below: 1994 over (under) 1993 1993 over (under) 1992 System ................... 2.37% 11.8% CL&P ..................... 3.33% 1.2% PSNH ..................... (1.35)% (9.3)% WMECO .................... 5.58% 13.5% For a discussion of trends in bulk power sales, see "Competition and Marketing." The System's total kilowatt-hour sales grew 2.5% in 1994 because of economic growth. The growth was broad-based and was not dominated by any particular industry or sector. Partially offsetting the gains in the economy were continued curtailments in the defense and insurance industries, which particularly affected the CL&P service area. Such curtailments should continue into 1995, which, combined with the efforts of the Federal Reserve to slow the national recovery, have the potential to further thwart New England's recovery. Moreover, where energy costs are a significant part of operating expenses, business customers may turn to self-generation, switch fuel sources or relocate to other states and countries, which have aggressive programs to attract new businesses. 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 1.2% growth rate of sales over this period. This growth rate is significantly below historic rates because of anticipated labor force constraints 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 0.5% higher if the System did not pursue DSM programs at the forecasted levels. See "Rates - Connecticut Retail Rates" and "Rates - Massachusetts Retail Rates" for information about rate treatment of DSM costs. With the System's generating capacity of 8,241 MW as of January 1, 1995 (including the net of capacity sales to and purchases from other utilities, and approximately 688 MW of capacity purchased from NUGs under existing contracts), the System expects to meet reliably its projected annual peak load growth of 1.2 percent until at least the year 2009. The availability of new resources and reduced demand for electricity have combined to place the System and most other New England electric utilities in a surplus capacity situation. 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 1,700 MW in the summer of 1995. For further information on the effect of competition on sales of surplus capacity, see "Competition and Marketing." The System companies operate and dispatch their generation as provided in the New England Power Pool (NEPOOL) Agreement. In 1994, the peak demand on the NEPOOL system was 20,519 MW in July, which was 949 MW above the 1993 peak load of 19,570 MW in July of that year. NEPOOL has projected that there will be a decrease in demand in 1995 and estimates that the summer 1995 peak load could reach 20,425 MW. NEPOOL projects that sufficient capacity will be available to meet this anticipated demand. GENERATION AND TRANSMISSION The System companies and most other New England utilities with electric generating facilities are parties to the NEPOOL Agreement. Under the NEPOOL Agreement, planning and operation of the region's generation and transmission facilities are coordinated. 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. The System companies, except PSNH and NAEC, pool their electric production costs and the costs of their principal transmission facilities under the Northeast Utilities Generation and Transmission Agreement (NUG&T). In addition, a ten-year agreement, expiring in June 2002, between PSNH and CL&P, WMECO and HWP provides for a sharing of the capability responsibility savings and energy expense savings resulting from a single system dispatch. In January 1992, FERC issued a decision approving NU's acquisition of PSNH, provided that the combined system accord transmission access to other utilities and non-utility generators that need to use the NU-PSNH transmission system to buy or sell electricity. FERC noted that NU system customers should remain harmless from the granting of such access. In accordance with the January 1992 decision, in April and August 1992, NU made compliance filings with FERC, including transmission tariffs implementing such conditions. FERC has 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. For information regarding the appeal of FERC's approval of NU's acquisition of PSNH, see "Legal Proceedings." The terms on which wheeling transactions are to be effected in New England have stimulated a series of negotiations among utilities, regulators, power brokers and marketers and non-utility generators, directed at the possible development of a regional transmission group within New England. Any arrangement would require widespread support by the parties and be subject to approval by FERC. FOSSIL FUELS The System's residual oil-fired generation stations used approximately six million barrels of oil in 1994. The System obtained the majority of its oil requirements in 1994 through contracts with two large, independent oil companies. Those contracts allow for some spot purchases when market conditions warrant, but spot purchases represented less than 10 percent of the System's fuel oil purchases in 1994. 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 converted CL&P's Devon Units 7 and 8 into oil and gas dual-fuel generating units in July 1994. The System now has five generating stations, aggregating approximately 800 MW, which can burn either residual oil or natural gas as economics, environmental concerns or other factors dictate. CL&P, PSNH and WMECO all 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 the Devon units 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 to 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 expects to use lower sulfur coal in its plants in the future. See "Regulatory and Environmental Matters - Environmental Regulation - Air Quality Requirements." NUCLEAR GENERATION GENERAL The 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. The 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 and NAEC have been affected at times by the inability of certain other Seabrook joint owners to fund their share of Seabrook costs. Great Bay Power Corporation (GBPC), a former subsidiary of Eastern Utilities Associates and owner of 12.13 percent of Seabrook, began bankruptcy proceedings in February 1991. On November 11, 1994, a final plan of reorganization of GBPC was confirmed by the United States Bankruptcy Court. Under the plan of reorganization's financing agreement, on November 22, 1994 a group of investors purchased 60 percent of the reorganized GBPC's common stock for an investment of $35 million and repaid CL&P $7.3 million for advances which CL&P made to cover GBPC's shortfalls in funding its share of operating costs of Seabrook during the bankruptcy. 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 a Yankee company are responsible for proportional shares of the operating costs of the 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 non-stockholder 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 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. 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. Several regulatory enforcement actions, with associated civil monetary penalties aggregating $357,500, were taken by the NRC in 1994 for certain violations which occurred at Millstone Station. However, approximately $270,000 of such amounts related to violations that occurred prior to 1994. 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. One such issue that has received considerable attention from the NRC in the last several years concerns the ability and willingness of nuclear plant workers to raise nuclear safety concerns without fear of retaliation for doing so. The NRC has identified the Millstone Station in particular as a site where workers have expressed concern with their ability to raise nuclear safety issues to company supervisors and managers. Management is aware of the NRC's concerns in this area, and is taking steps to ensure that the environment at Millstone is one where workers feel free to raise issues without fear of retaliation. 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 73.2 percent for January through September 1994, and 67.5 percent for the five nuclear units operated by the System in 1994, compared with 80.8 percent for 1993. The lower 1994 capacity factor was primarily due to extended refueling and maintenance outages at Millstone 1, Millstone 2 and Seabrook and unexpected technical and operating difficulties at Millstone 2, Seabrook and CY. The System anticipates total expenditures in 1995 of approximately $477.5 million for operations and maintenance and $82.2 million in capital improvements for the five nuclear plants that it operates. The Performance Enhancement Program (PEP), initiated in 1992 by the System's nuclear organization, was designed in response to a declining performance trend noted in the early 1990's. Seven PEP action plans were completed in 1994. The System companies spent $25.2 million on PEP in 1994 and have budgeted $21.7 million (included in the 1995 operations and maintenance annual budget) for 1995 PEP action plans. The remaining nine action plans are expected to be completed by the end of 1997. 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 1990-1993 period, see "Rates - Connecticut Retail Rates," "Rates - New Hampshire Retail Rates" and "Rates - Massachusetts Retail Rates." MILLSTONE UNITS For the twelve months ended December 31, 1994, the three Millstone units' composite capacity factor was 66.4 percent, compared with a composite capacity factor of 79.3 percent for the twelve months ended December 31, 1993 and 53.1 percent for the same period in 1992. Millstone 1, a 660 MW boiling water reactor, has a license expiration date of October 6, 2010. In 1994, Millstone 1 operated at a 58.3 percent capacity factor. The unit began a 71 day planned refueling and maintenance outage on January 15, 1994. Millstone 1 returned to service on May 20, 1994, for an outage duration of 125 days. The delay in completing the outage on schedule was primarily attributable to unanticipated work associated with the service water systems, certain system valves and surveillance testing. The next refueling outage is scheduled for October 1995. Millstone 2, a 870 MW pressurized water reactor, has a license expiration date of July 31, 2015. In 1994 Millstone 2 operated at a 48.2 percent capacity factor. The unit began a planned 63-day refueling and maintenance outage on October 1, 1994. Subsequent events have added substantially to the duration of the refueling outage and at present, the unit is not expected return to service before mid-April 1995. Earlier in 1994, Millstone 2 experienced a 57-day unplanned maintenance outage which ended on June 18, 1994 and a second unplanned outage to repair the reactor coolant pump oil collection system from July 27, 1994 to September 3, 1994. The recovery of replacement power operation and maintenance costs incurred during these outages are subject to prudence reviews in both Connecticut and Massachusetts. A recent report issued by the NRC for the Millstone Station noted significant weaknesses in Millstone 2's operations and maintenance. Subsequently, a senior NRC official expressed disappointment with the continued weaknesses in Millstone 2's performance. The primary cause of the NRC's disappointment with Millstone 2's performance appears to be that, despite significant management attention and action over a period of years, the NRC does not believe it has seen enough objective evidence of improvement in reducing procedural noncompliance and other human errors. Management has acknowledged the basis for the NRC's concern with Millstone 2 and has been devoting increased attention to resolving these issues. Management and the NRC expect to continue to closely monitor performance at Millstone 2. Millstone 3, a 1154 MW pressurized water reactor, has a license expiration date of November 25, 2025. In 1994, Millstone 3 operated at a 94 percent capacity factor. The unit had no planned refueling and maintenance outages in 1994. Millstone 3 experienced one unplanned outage in 1994 which lasted from September 8, 1994 to September 22, 1994. The next refueling outage is scheduled to begin on April 14, 1995, with a planned duration of 54 days. 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 a half years before Seabrook's full power operating license was issued. The System will determine at the appropriate time whether to seek recapture of this period from the NRC and thus add an additional three and a half years to the operating term for Seabrook. In 1994, Seabrook operated at a capacity factor of 61.6 percent. The unit began a scheduled refueling and maintenance outage on April 9, 1994. The unexpected discovery of reactor coolant pump locking cups and a bolt in the reactor vessel contributed substantially to the duration of the outage. The unit returned to service on August 1, 1994 for an outage duration of 114 days. Seabrook experienced one unplanned outage in 1994 which lasted from January 26 to February 17, 1994 when a main steam isolation valve closed during quarterly surveillance testing. The next refueling outage is scheduled for November 1995. YANKEE UNITS CONNECTICUT YANKEE CY, a 582 MW pressurized water reactor, has a license expiration date of June 29, 2007. In 1994 CY operated at a capacity factor of 75.4 percent. CY experienced two unplanned outages with durations greater than two weeks in 1994. The first such outage began in February 1994 and lasted 44 days in order to repair and replace service water piping. On July 11, 1994 the unit began a second forced outage to upgrade the oil collection system for the reactor coolant pumps. The unit returned to service on August 17, 1994. CY began a planned refueling and maintenance outage on January 28, 1995, with a scheduled duration of 51 days. 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 1994, MY operated at a capacity factor of 85.9 percent. The current refueling outage began in January 1995. VERMONT YANKEE VY, a 514 MW boiling water reactor, has a license expiration date of March 21, 2012. In 1994, VY operated at a capacity factor of 94.4 percent. The current refueling outage began on March 17, 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 and WMECO and YAEC permit YAEC to recover from each its proportional share of the Yankee Rowe shutdown and decommissioning costs. For more information regarding recovery of decommissioning costs for Yankee Rowe, see "Electric Operations - Nuclear Generation - Decommissioning." NUCLEAR INSURANCE The NRC's nuclear property insurance rule requires nuclear plant licensees to obtain a minimum of $1.06 billion in insurance coverage. The rule requires that, although such policies may provide traditional property coverage, proceeds from the policy following an accident in which estimated stabilization and decontamination expenses exceed $100 million will first be applied to pay such expenses. The insurance carried by the licensees of the Millstone units, Seabrook 1, CY, MY and VY meets the requirements of this rule. 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 of 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 System companies have maintained diversified sources of supply for these materials and services, relying on no single source of supply for any one component of the fuel cycle. The majority of the System companies' uranium enrichment services requirements are provided under a long term contract with the U.S. Enrichment Corporation, a wholly-owned government corporation. The majority of Seabrook 1's uranium enrichment services requirements, however, are furnished by 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. As a result of the Energy Policy Act, the U.S. commercial nuclear power industry is required to pay to the DOE, via a special assessment for the costs of the decontamination and decommissioning of uranium enrichment plants owned by the U.S. government, no more than $150 million for 15 years beginning in 1993. Each domestic nuclear utility will make a payment based on its pro rata share of all enrichment services received by the U.S. commercial nuclear power industry from the U.S. Government through October 1992. Each year, the U. S. Department of Energy (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 $51 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. Costs associated with nuclear plant operations include amounts for disposal of nuclear waste, including spent fuel, and for the ultimate decommissioning of the plants. The System companies include in their nuclear fuel expense spent fuel disposal costs accepted by the DPUC, the NHPUC and the 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, the NHPUC and the 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. In late 1993 and 1994, DOE indicated that it was not likely to meet its statutory and contractual obligations to accept spent fuel in 1998. In June 1994, the DPUC joined with the Connecticut 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. The State of New Hampshire, among others, subsequently joined in this lawsuit. NU and its affiliates did not join a companion lawsuit filed by fourteen utilities seeking similar relief. Nuclear utilities and state regulators are presently considering additional steps which 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 wastes and spent fuel on-site or make some other provisions for their storage. With the addition of new storage racks or through fuel consolidation, 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 2000. 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 addition of new racks, Seabrook 1 is expected to have spent fuel storage capacity until at least 2010. MY's present storage capacity of the spent fuel pool at the unit will be reached in 1999, and after 1996 the available capacity of the pool will not accommodate a full-core removal. After consideration of available technologies, MYAPC elected to provide additional capacity by replacing the fuel racks in the spent fuel pool at the unit. On March 15, 1994, the NRC authorized this plan. 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 effective February 1992, YAEC is planning to construct 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. LOW-LEVEL RADIOACTIVE WASTE In accordance with the provisions of the federal Low-Level Radioactive Waste Policy Act of 1980, as amended (the Waste Policy Act), on December 31, 1992 the disposal site at Beatty, Nevada closed, and the Richland, Washington facility closed to disposal of low-level radioactive wastes (LLRW) from outside its compact region. On July 1, 1994, the Barnwell, South Carolina LLRW facility ceased accepting LLRW for disposal from states situated outside its compact region. The NU System is currently implementing plans for the temporary on-site storage of LLRW generated at its nuclear facilities. The costs associated with temporary on-site storage of LLRW are not material. The System has plans that will allow for the storage of LLRW until a permanent disposal facility becomes available. The System can manage its Connecticut LLRW by volume reduction, storage or shipment at least through 1999. In addition, an NRC policy memorandum provides additional guidance on interim LLRW storage by removing any time limitations on the on-site storage of LLRW and by allowing for modification and expansion of storage facilities without prior NRC approval. The Millstone units and CY incurred approximately $6.8 million in off-site disposal costs in 1994. The Connecticut Hazardous Waste Management Service (the Service), a state quasi-public corporation, is charged with coordinating the establishment of a facility for disposal of LLRW originating in Connecticut. On February 1, 1993, the Connecticut legislature approved a site selection plan under which communities are urged to volunteer a site for a facility in return for financial and other incentives. The volunteer process is being continued through 1996. The Service's activities in this regard are funded by assessments on Connecticut's LLRW generators. Due to the change to a volunteer process, there was no assessment for the 1994-1995 fiscal year and the state projects no assessment for the 1995-1996 and 1996-1997 fiscal years. Management cannot predict whether and when a disposal site will be designated in Connecticut. The Service currently projects that a disposal site will be designated by 2002. Since January 1, 1989, the State of New Hampshire has been barred from shipping Seabrook LLRW to the operating disposal facilities in South Carolina, Nevada and Washington for failure to meet the milestones required by the Waste Policy Act. Seabrook 1 has never shipped LLRW but has capacity to store at least five years' worth of the LLRW generated on-site, with the capability to expand this on-site capacity if necessary. The Seabrook station accrued approximately $2.0 million in off-site disposal costs in 1994. New Hampshire is pursuing options for out-of-state disposal of LLRW generated at Seabrook. MY has been storing its LLRW on-site since January 1993. VY and MY each has on-site storage capacity for at least five years' production of LLRW from its respective plants. Maine and Vermont are in the process of implementing an agreement with Texas to provide access to a LLRW facility that is to be developed in that state. 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, 1994 dollars, and include costs allocable to NAEC's share of Seabrook acquired from VEG&T. CL&P PSNH WMECO NAEC System (Millions) Millstone 1 $332.8 $ - $ 78.1 $ - $ 410.9 Millstone 2 267.3 - 62.7 - 330.0 Millstone 3 237.5 12.8 54.9 - 305.2 Seabrook 1* 15.5 - - 137.3 52.8 ------ ----- ------ ------ -------- Total $853.1 $12.8 $195.7 $137.3 $1,198.9 ====== ===== ====== ====== ======== --------------- * The Seabrook decommissioning estimate currently is under review by the New Hampshire Nuclear Decommissioning Finance Committee (NDFC). As of December 31, 1994, 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 $ 81.5 $ - $ 27.4 $ - $108.9 Millstone 2 52.1 - 18.5 - 70.6 Millstone 3 37.2 1.8 10.2 - 49.2 Seabrook 1 1.2 - - 10.3 11.5 ------ ---- ------ ----- ------ Total $172.0 $1.8 $ 56.1 $10.3 $240.2 ====== ==== ===== ===== ====== 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 multi-year 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 approximately 16 percent contingency factor for each unit. The estimated aggregate System cost of decommissioning the Millstone units is approximately $1.05 billion in December 1994 dollars. WMECO has established independent trusts to hold all decommissioning expense collections from customers. In its 1990 WMECO multi-year 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. The decommissioning cost estimates for the Millstone 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. Although allowances for decommissioning have increased significantly in recent years, collections from customers in future years will need to increase to offset the effects of any insufficient rate recoveries in previous years. New Hampshire enacted a law in 1981 requiring the creation of a state-managed fund to finance decommissioning of any units in that state. In 1992, the NDFC established approximately $323 million (in 1991 dollars) as the decommissioning cost estimate for immediate and complete dismantlement of Seabrook 1 upon its retirement. North Atlantic prepared a revised decommissioning estimate in 1994. The revised estimate is currently under review by the NDFC. Public hearings were held in the fourth quarter of 1994. Approval of the estimate is expected in late April, 1995. On the basis of North Atlantic's 1994 revised estimate, the total System decommissioning cost for Seabrook 1 is $152.8 million in December 1994 dollars. The NHPUC is authorized to permit the utilities subject to its jurisdiction that own an interest in Seabrook 1 to recover from their customers on a per-kilowatt hour basis amounts paid into the decommissioning fund over a period of years. 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" for further information on the Rate Agreement. YAEC, MYAPC, VYNPC and CYAPC 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, 1994 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 $ 31.3 $13.2 $ 8.2 $ 52.7 Yankee Rowe* 100.0 28.6 28.6 157.2 CY 124.9 18.1 34.4 177.4 MY 40.6 16.9 10.1 67.6 ------ ----- ----- ----- Total $298.8 $76.8 $81.3 $454.9 ====== ===== ===== ====== --------------- * The costs shown include all decommissioning costs as well as other closing costs associated with the early retirement of Yankee Rowe. As of December 31, 1994, the balances (at market) in the external decommissioning trust funds for the Yankee Units were as follows: CL&P PSNH WMECO System (Millions) VY $ 10.8 $ 4.5 $ 2.8 $ 18.1 Yankee Rowe 26.4 7.6 7.6 41.6 CY 51.6 7.5 14.2 73.3 MY 13.0 5.4 3.3 21.7 ------ ----- ----- ----- Total $101.8 $25.0 $27.9 $154.7 ====== ===== ===== ====== In October 1994, YAEC submitted a decommissioning cost estimate as part of its decommissioning plan with the NRC. Following the receipt of NRC approval, this estimate will be filed with FERC. The estimate increased the system's ownership share of decommissioning YAEC's nuclear facility by approximately $36 million in January 1, 1994 dollars. At December 31, 1994, the estimated remaining costs amounted to $408.2 million, of which the System's share was approximately $157.1 million. Management expects that CL&P, PSNH and WMECO will continue to be allowed to recover such FERC approved costs from their customers. YAEC has begun component removal activities related to the decommissioning of its nuclear facility. Based on the revised decommissioning estimate and the remaining decommissioning costs in 1994 dollars, approximately nine percent of such removal activities has been completed. Management believes that, although Yankee Rowe was shut down eight years before the end of the unit's operating license, CL&P, PSNH and WMECO will recover their investments in YAEC, along with any other associated costs. CYAPC accrues decommissioning costs on the basis of immediate dismantlement at retirement. The most current estimated decommissioning cost, based on a 1992 study, is approximately $362.0 million in year-end 1994 dollars. 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. MYAPC estimates the cost of decommissioning MY at $338.3 million in December 31, 1994 dollars based on a study completed in July 1993. VYNPC estimates the cost of decommissioning VY at $329.6 million in December 31, 1994 dollars based on a study completed in March 1994. For further information regarding the decommissioning of the System nuclear units, see "Nuclear Decommissioning" in the notes to NU's, CL&P's, PSNH's, WMECO's and NAEC's financial statements. NON-UTILITY BUSINESSES GENERAL In addition to its core electric utility businesses in Connecticut, New Hampshire and Massachusetts, in recent years the System has begun a diversification of its business activities into two energy-related fields: private power development and energy management services. PRIVATE POWER DEVELOPMENT In 1988, NU organized a subsidiary corporation, Charter Oak, through which the System participates as a developer and investor in domestic and international private power projects. With the passage of the Energy Policy Act, Charter Oak can invest in EWG and FUCO power projects anywhere in the world. Management currently does not permit Charter Oak to invest in facilities which are located within the System service territory or to sell its electric output to any of the System electric utility companies. Charter Oak has made strategic alliances with several experienced developers to pursue development opportunities nationwide and internationally. Charter Oak owns, through a wholly-owned special purpose subsidiary, a ten percent equity interest in a 220 MW natural gas-fired combined cycle cogeneration QF in Texas. Charter Oak also owns 56 MW of the 1,875 MW Teesside natural gas-fired cogeneration facility in the United Kingdom. Charter Oak is pursuing other project development opportunities in both the domestic and international markets with a combined capacity over 1,000 MW. Charter Oak is currently participating in the development stage of projects in Texas, the West Coast, Latin America and the Pacific Rim. Specifically, Charter Oak is engaged in constructing a 114 MW natural gas-fired project located in the Republic of Argentina (Argentina) and plans to begin construction of a 20 MW wind project in Costa Rica in the spring of 1995. Charter Oak's share of these projects is 38 MW and 13 MW, respectively. Although Charter Oak has no full-time employees, nine NUSCO employees are dedicated to Charter Oak activities on a full-time basis. Other NUSCO employees provide services as required. NU's total investment in Charter Oak was approximately $31.0 million as of December 31, 1994. NU currently is committed to invest an additional $15 million in Charter Oak to fund completion of the natural gas-fired project in Argentina. ENERGY MANAGEMENT SERVICES In 1990, NU organized a subsidiary corporation, HEC, to acquire substantially all of the assets and personnel of an existing, non-affiliated energy management services company. In general, the energy management services that HEC provides are performed for customers pursuant to contracts to reduce the customers' energy costs and/or conserve energy and other resources. HEC also provides demand side management consulting services to utilities. HEC's energy management and consulting services are directed primarily to the commercial, industrial and institutional markets and utilities in New England and New York. NU's initial equity investment in HEC was approximately $4 million and NU has made additional capital contributions of approximately $300,000 through December 31, 1994. 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 or 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) provides that every "point source" discharger of pollutants into navigable waters must obtain a National Pollutant Discharge Elimination System (NPDES) permit from the U.S. Environmental Protection Agency (EPA) or state environmental agency specifying the allowable quantity and characteristics of its effluent. The System's steam-electric generating plants 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. 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 discharge permit for the three Millstone nuclear units, issued in 1992, the Connecticut Department of Environmental Protection (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. On January 14, 1994, CDEP approved the Millstone feasibility report submitted to it in 1993 and required that Millstone station continue efforts to schedule refueling outages to coincide with the period of high winter flounder larvae abundance and that the station continue to monitor the Niantic River winter flounder population in accordance with existing NPDES permit conditions. 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 will be completed in 1995. If they indicate that Merrimack Station's once-through cooling system interferes with the establishment of a balanced aquatic community, 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 or significant and substantial harm to the environment by discharging oil or hazardous substances into the navigable waters of the United States and adjoining shorelines. Pursuant to OPA 90, EPA has authority to regulate nontransportation-related fixed onshore facilities and the 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 $890 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 further regulating emissions of sulfur dioxide (SO2) and nitrogen oxides (NOX) for the purpose of controlling acid rain, toxic air pollutants and other pollutants, requiring installation of continuous emissions monitors (CEMs) and expanding permitting provisions. Existing and additional federal and state air quality regulations could hinder or possibly preclude the construction of new, or modification of existing, fossil units in the System's service area, could raise the capital and operating cost of existing units, and may affect the operations of the System's work centers and other facilities. 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. The CAAA identifies NOX emissions as a precursor of ambient ozone for the northeastern region of the United States, which currently exceeds ambient air quality standard for ozone. Pursuant to the CAAA, Connecticut, New Hampshire and Massachusetts must implement plans to address ozone nonattainment. All three states have issued final regulations to implement Phase I (RACT) reduction requirements. The System has developed compliance strategies and estimates of costs. The capital cost to comply with Phase I requirements will 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 will be achieved using currently available technology and combustion efficiency improvements. Compliance costs for Phase II, effective in 1999, are expected to result in an additional cost of $10 to $15 million. These Phase II costs take into consideration capital expenditures during Phase I and expanded capital costs for available technology. In December 1993, PSNH reached a revised agreement regarding NOX emissions with various environmental groups and the New Hampshire Business and Industrial Association. The agreement was submitted to the New Hampshire Air Resources Division (NHARD) in the form of proposed regulations. The agreement provides for aggressive unit specific NOX emission rate limits for PSNH's generating facilities, effective May 31, 1995. The agreement no longer requires a PSNH 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. On May 20, 1994, NHARD promulgated the New Hampshire NOX reduction rule. The System will comply with the requirements of this rule by installing controls on the units. The additional requirements for Merrimack Unit 2 for 1999 will 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 are required to reduce their emissions beginning January 1, 1995. The only System units subject to the Phase I reduction requirements are PSNH's Merrimack Units 1 and 2. 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. 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. The System expects that its allocated allowances will substantially exceed its expected SO2 emissions for 2000 and subsequent years. Current estimates indicate the System will have approximately 25,000 tradeable SO2 allowances available annually at a market value of approximately $150 per allowance. On July 20, 1994 the DPUC issued an order that, with some restrictions, allows CL&P to retain for its shareholders 15 percent of the net proceeds from the sale of SO2 allowances. New Hampshire and Massachusetts have each instituted acid rain control laws that limit SO2 emissions. The System expects to meet the new SO2 limitations by using natural gas and lower sulfur coal in its plants. The System could incur additional costs for the lower sulfur fuels it may burn to meet the requirements of this legislation. Under the existing fuel adjustment clauses in Connecticut, New Hampshire and Massachusetts, the System would be able to recover the additional fuel costs of compliance with the CAAA and state laws from its customers. 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 (acid rain) requirements for NOX limitations will not have a significant impact on System costs due to the more stringent state NOX limitations 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 imposes new stringent discharge limitations on hazardous air pollutants. EPA is required to study toxic emissions and mercury emissions from power plants. Pending completion of these studies, power plants are exempt from the hazardous air pollutant requirements. Should EPA or Congress determine that power plant 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 offsite 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 typically several million dollars annually. These costs are already included in capital and operation and maintenance 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 DEP 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 DEP. The System estimates that it will incur approximately $2 million in total costs of 30-year maintenance monitoring, and closure of the container storage areas for these sites in the future, but the ultimate amount will depend on EPA's final disposition. Underground Storage Tanks. Federal and state regulations regulate underground tanks storing petroleum products or hazardous substances. To reduce its environmental and financial liabilities, the System has been permanently removing all non-essential underground vehicle fueling tanks. Costs for this program are not substantial. 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. In recent years it has been determined that deposited or buried wastes, under certain circumstances, could cause groundwater contamination or 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. At December 31, 1994, 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 $11 million. The costs for these known sites could rise to as much as $16 million 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 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 one Superfund site in Kentucky and three 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. The System is no longer involved with the Beacon Heights, Connecticut Superfund site, at which a coalition of major parties had attempted to join "Northeast Utilities (Connecticut Light and Power)" as defendants. In January 1994, the Beacon Heights Coalition filed a response with the federal district court indicating that it would not continue to pursue NU (CL&P) as a defendant in this litigation. Accordingly, it is not likely that CL&P will incur any cleanup costs for this site. 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. 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. To date, the costs have not been material with respect to System earnings or financial position. PSNH has committed approximately $280,000 as its share of the costs to clean up Superfund sites at municipal landfills in Dover and North Hampton, New Hampshire. Some additional costs may be incurred at these sites and at the Somersworth site 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, Connecticut Department of Environmental Protection (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 $600,000 to date 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 residues, which, when not sold for roofing or road construction, 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. The need for site remediation is being evaluated. The level of cleanup will be established in cooperation with CDEP, which is currently developing cleanup standards and guidelines 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 are currently being evaluated to clean up the site. These options include institutional controls, excavation and limited removal of contamination, which would reduce the potential environmental and health risks and secure the site. 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 will require remediation. Several options are being evaluated to process surface soils and degrade subsurface contamination to remediate the site. Levels of cleanup will be coordinated with the CDEP. 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 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 formerly owned and operated a coal gasification plant which was sold in 1945. PSNH completed a site investigation in December 1994. Results indicate that off-site coal tar/creosote contamination is present in the adjacent water bodies. The cost of remediation at this site is estimated at $1.8 million. 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 1995. Other New Hampshire sites include a municipal landfill in Peterborough and the inactive Dover Point site owned by PSNH in Dover, New Hampshire. PSNH's liability at the landfill is not expected to be significant and its liability at the Dover Point site 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. Except for the Holyoke site, the System does not expect that its share of the remaining remediation costs for most of these sites will be material. 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 west 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 $400,000 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 estimated costs for remediation of this site range from $2 to $3 million. 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 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 life-cycle cost analysis of overhead and underground transmission lines, which was mandated by PA-176. This Act was adopted by the General Assembly in part due to public EMF concerns. EMF has become increasingly important as a factor in facility siting decisions in many states. Several bills involving EMF were introduced in Massachusetts in 1994, with no action taken. These bills were similar to ones introduced in previous years, on which no action was taken. 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 thirteen hydroelectric projects 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. At the time of relicensing and for certain matters during the term of an existing license, FERC can direct changes in hydro project operation, maintenance and design to accommodate environmental, recreational, or navigational needs. At present, the U.S. Fish and Wildlife Service is considering a petition to place the Atlantic Salmon on the endangered species list. If such designation is granted, System hydroelectric projects along the Connecticut River, the Merrimack River and their tributaries may be required to make operational and/or design changes to mitigate any adverse effects on the Atlantic Salmon. The System cannot estimate the cost of such mitigation actions at this time. FERC recently 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, 1994, the System companies had approximately 9,395 full and part time employees on their payrolls, of which approximately 2,601 were employed by CL&P, approximately 1,390 by PSNH, approximately 619 by WMECO, approximately 112 by HWP, approximately 1,312 by NNECO, approximately 2,456 by NUSCO and approximately 905 by North Atlantic. NU, NAEC and Charter Oak have no employees. Approximately 2,325 employees of CL&P, PSNH, WMECO, North Atlantic and HWP are covered by union agreements, which expire between October 1994 and May 1996. The two union agreements that expired on October 1, 1994 cover 370 employees of WMECO and HWP and are currently under negotiation. Management cannot predict the timing or terms of these new contracts. SUBSEQUENT EVENTS COMPETITION AND MARKETING - RETAIL MARKETING On March 23, 1995, the Energy and Technology Committee of the Connecticut General Assembly passed a bill that would create a task force to study restructuring of the electric industry in Connecticut. If enacted, the bill would require a preliminary report to the committee by February 1, 1996, and a final report by January 1, 1997. The bill now goes to the state Senate and House of Representatives where CL&P will be proposing changes. RATES CONNECTICUT RETAIL RATES On March 22, 1995, the System introduced its plan, entitled "Path to a Competitive Future," for the future of the electric industry and related regulation in Connecticut in a filing submitted to the DPUC in its investigation into the potential restructuring of the electric utility industry initiated earlier this year. The plan is a comprehensive four-phase approach to enhancing CL&P's customer satisfaction and market efficiency in Connecticut. It calls for several significant changes in electricity pricing, in the ability to introduce new products and services, in methods of rate-setting, and in the composition of NEPOOL. The two-year first phase began in early 1995. The second and third phases, which involve the transition to a more efficient market, would each last an estimated four to six years. The final stage--a fully competitive market for electricity--could begin once all issues relating to traditional utility regulation have been thoroughly addressed and relevant transition costs have been recovered from customers. Other similar approaches, tailored to the specific needs of their service territories, are to be introduced this spring by NU's other operating company subsidiaries, PSNH and WMECO, in ongoing restructuring proceedings in New Hampshire and Massachusetts, respectively. NEW HAMPSHIRE RETAIL RATES On March 17, 1995 a status conference was held with the NHPUC relating to PSNH's negotiations with the wood-fired NUGs. The parties reported that an agreement in principle had been reached with all but one of the owners of the wood-fired NUGs. It is expected that settlement agreements and purchase power contracts with the settling owners will be drafted, executed and filed with the NHPUC as soon as possible. The NHPUC will consider approval of the settlements in proceedings to begin in the late Spring of 1995. Negotiations are continuing with the nonsettling owner, who owns two plants. FINANCING PROGRAM - FINANCING LIMITATIONS The amount, in millions, of short-term debt outstanding as of March 20, 1995 was $91.5 for NU, $88.3 for CL&P, $0 for PSNH, $14.3 for WMECO, $0 for HWP, $0 for NAEC, $0 for NNECO, $17.2 for RRR, $4.5 for Quinnehtuk and $2.2 for HEC, or a total of $218. ELECTRIC OPERATIONS - NUCLEAR GENERATION NUCLEAR PLANT PERFORMANCE The average capacity factor for the operating nuclear units in the United States for calendar 1994 was 72.5 percent. MILLSTONE UNITS Management's ongoing evaluation of the current Millstone 2 extended refueling and maintenance outage, which has been under way since October 1, 1994, has concluded that based on currently available information, the unit is now expected to resume operations in May 1995, following an NRC assessment of the unit's readiness to restart. CONNECTICUT YANKEE The CY planned refueling and maintenance outage which began on January 28, 1995 has been extended for approximately two weeks due to overall work progress and emergent work. The plant is expected to return to service in early April 1995. MAINE YANKEE MY, like other pressurized water reactors, has been experiencing degradation of its steam generator tubes, principally in the form of circumferential cracking which, until early 1995, was believed to be limited to a relatively small number of steam generator tubes. In the past the detection of defects has resulted in the plugging of those tubes to prevent their subsequent use. During the refueling and maintenance shutdown that commenced in early February 1995, MYAPC detected an increased rate of degradation of MY's steam generator tubes, in excess of the number expected, and is currently evaluating several courses of action to address the matter. This circumstance is likely to adversely affect the operation of MY and may result in substantial cost to MYAPC. MYAPC cannot now predict what course of action it will choose or to what extent the operation of MY will be affected. See "Nuclear Generation- General" for information about the ownership interests of CL&P, PSNH and WMECO in MYAPC. 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, PSNH's outstanding term loan and revolving credit agreement borrowings are secured by a second lien, junior to the lien of the first mortgage indenture, on PSNH 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, 1994, the System companies owned 103 transmission and 429 distribution substations that had an aggregate transformer capacity of 25,001,996 kilovoltamperes (kVa) and 9,145,129 kVa, respectively; 3,054 circuit miles of overhead transmission lines ranging from 69 kilovolt (kV) to 345 kV, and 194 cable miles of underground transmission lines ranging from 69 kV to 138 kV; 32,507 pole miles of overhead and 1,893 conduit bank miles of underground distribution lines; and 384,367 line transformers in service with an aggregate capacity of 15,625,000 kVa. Electric Generating Plants As of December 31, 1994, 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 Plant name Year Capability* Owner (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 46,688 CT Yankee (Haddam,CT) Nuclear 1968 201,204 ME Yankee (Wiscasset,ME) Nuclear 1972 94,832 VT Yankee (Vernon,VT) Nuclear 1972 44,570 --------- Total Nuclear-Steam Plants (7 units) 2,226,729 Total Fossil-Steam Plants (9 units) 1954-73 1,803,000 Total Hydro-Conventional (25 units) 1903-55 98,930 Total Hydro-Pumped Storage (7 units) 1928-73 905,150 Total Internal Combustion (16 units) 1966-86 413,200 --------- Total CL&P Generating Plant (64 units) 5,447,009 ========= 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 18,737 --------- Total Nuclear-Steam Plants (4 units) 120,035 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) 1968-70 107,050 --------- Total PSNH Generating Plant (36 units) 1,298,660 ========= Claimed Plant name Year Capability* Owner (location) Type Installed (kilowatts) ----- ---------- ---- --------- ----------- 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 11,741 --------- Total Nuclear-Steam Plants (6 units) 520,287 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) 1,006,897 ========= NAEC Seabrook (Seabrook,NH) Nuclear 1990 413,793 ========= 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 Millstone(Waterford,CT) SYSTEM Unit 1 Nuclear 1970 647,700 Unit 2 Nuclear 1975 874,500 Unit 3 Nuclear 1986 779,293 Seabrook (Seabrook,NH) Nuclear 1990 460,481 CT Yankee (Haddam,CT) Nuclear 1968 285,768 ME Yankee (Wiscasset,ME) Nuclear 1972 158,054 VT Yankee (Vernon,VT) Nuclear 1972 75,048 --------- Total Nuclear-Steam Plants (7 units) 3,280,844 Total Fossil-Steam Plants (18 units) 1952-78 3,061,065 Total Hydro-Conventional (87 units) 1903-83 320,910** Total Hydro-Pumped Storage (7 units) 1928-73 1,110,350 Total Internal Combustion (24 units) 1966-86 583,750 --------- Total NU SYSTEM Generating Plant Including Regional Yankees (143 units) 8,356,919 ========= Excluding Regional Yankees (140 units) 7,838,049 ========= *Claimed capability represents winter ratings as of December 31, 1994. **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. 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 1996 at the earliest. 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. Massachusetts Municipal Wholesale Electric Company / 30th Amendment to NEPOOL Agreement Settlement NU's operating subsidiaries, CL&P, PSNH, WMECO, HWP and HP&E (collectively, the Company) and a number of other utilities that are members of NEPOOL, as defendants, are involved in two pending actions relating to pool planning and future transmission service issues under the NEPOOL Agreement. An action in Suffolk Superior Court in Massachusetts was brought by a number of the Massachusetts electric municipal systems and the Massachusetts Municipal Wholesale Electric Company requesting damages and injunctive relief. FERC subsequently commenced an action when the Company and 26 other participants filed an amendment to the NEPOOL Agreement with FERC that concerns many of the issues raised in the Massachusetts litigation. On February 10, 1995, FERC issued an order accepting a withdrawal of the amendment to the NEPOOL Agreement. The withdrawal was part of a settlement agreement signed by substantially all of the parties and intervenors, which will also result in the withdrawal by the settling plaintiffs of their Superior Court complaint after the FERC action is terminated and no longer subject to appeal. The 30-day period in which to appeal from the FERC order expired without the filing of requests for rehearing, and the order has become final. 3. 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 -------------------------- 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. The FERC decision is subject to rehearing and can be appealed to the United States Court of Appeals. In early February 1995, several petitions for rehearing were filed. Should CL&P ultimately prevail, the benefits to CL&P customers would be approximately $13 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's ruling that the DPUC should decide this issue. CL&P has answered interrogatories issued by the DPUC and further DPUC proceedings on this dispute are expected. The amount in dispute for the period 1992 through August 1994 is approximately $470,000. However, assuming SCRRRA were permitted to charge the municipal rate for an assumed project generation of 14.5 MW per hour (i.e., 5% greater than 13.85 MW), the amount in dispute could be as much as $4.5 million (cumulative present value) for the remaining term of the contract with SCRRRA. This dispute will not be resolved by the FERC decision on the municipal rate statute because each of the contract rates is greater than CL&P's current avoided costs. On June 20, 1994, the Connecticut General Assembly overrode Governor Weicker's veto of a bill that purportedly resolves the non-participant towns and excess capacity disputes against CL&P. CL&P has a number of options in response to this legislation including challenging its constitutionality in either federal or state court. The law took effect on October 1, 1994, but has not yet been applied against CL&P in either of these proceedings. 4. 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. On May 9, 1994, the City's appeal was dismissed by the Hartford Superior Court on jurisdictional grounds, and the City appealed that dismissal to the Connecticut Appellate Court. The Supreme Court of Connecticut transferred the jurisdictional issue to itself on August 2, 1994. Oral argument is expected to be scheduled in the spring of 1995, and a decision is expected by September 1995. 5. Connecticut Indian Land Claims Numerous lawsuits asserting land claims in Connecticut have been filed in either state and federal court or threatened by a group called the Golden Hill Paugussett Tribe of Indians (the Paugussetts). These actions could impact the title to certain NU system real estate in the eight affected Connecticut towns. Title to the properties of thousands of other owners, including homeowners, has been similarly threatened. However, the only case to specifically name CL&P as a defendant, a class action suit affecting approximately 1,500 property owners in Southbury, was dismissed by the trial court, and the dismissal was subsequently upheld on appeal by the Connecticut Supreme Court on the grounds that the plaintiff lacked standing to act on behalf of the Paugussetts. The outcome of the present or potential litigation either by the Paugussetts or by other groups claiming to be "Indian tribes" cannot be predicted at this time. However, a number of possible defenses exist to Indian land claims in Connecticut, and the Paugussetts' success on the merits appears unlikely. 6. 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. 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 on July 8, 1994. On September 6, 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, which Petition is expected to be heard April 3, 1995. 7. Other Legal Proceedings The following sections of Item 1 "Business" discuss additional legal proceedings: "Rates" for information about CL&P's rate and fuel clause adjustment clause proceedings and the Seabrook Power Contract; "Electric Operations -- Generation and Transmission" for information about proceedings relating to power transmission issues; "Electric Operations -- Nuclear Generation" for information related to Seabrook joint owners, 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; and "FINANCIAL CONDITION -- Property Taxes" in the NU 1994 Annual Report for information about proceedings involving utility property tax appeal 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 ticker symbol is "NU," although it is frequently presented as "Noeast 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 ---- ------- ---- --- 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 1993 First $28 7/8 $25 1/2 Second 28 3/4 25 1/4 Third 28 1/8 26 1/4 Fourth 27 3/8 22 As of January 31, 1995, there were 137,978 common shareholders of record of NU. As of the same date, there were a total of 134,210,261 common shares issued, including approximately 9.1 million shares held in an ESOP trust. NU declared and paid quarterly dividends of $0.44 in 1994 and $0.44 in 1993. On January 24, 1995, the Board of Trustees declared a dividend of $0.44 per share, payable on March 31, 1995 to holders of record on March 1, 1995. 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 32 of NU's 1994 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 pages 48 and 49 of NU's 1994 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 40 of CL&P's 1994 Annual Report, which information is incorporated herein by reference. PSNH. Reference is made to information under the heading "Selected Financial Data" contained on pages 37 and 38 of PSNH's 1994 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 1994 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 1994 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 16 through 23 in NU's 1994 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 32 through 39 in CL&P's 1994 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 29 through 35 in PSNH's 1994 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 1994 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 18 through 20 in NAEC's 1994 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 24 through 47 in NU's 1994 Annual Report to Shareholders, 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 1 through 31 and page 40 in CL&P's 1994 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 1 through 28 and page 39 in PSNH's 1994 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 1 through 26 and page 33 in WMECO's 1994 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 1 through 17 and page 21 in NAEC's 1994 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 are pages 1 through 13 of the definitive proxy statement for solicitation of proxies by NU's Board of Trustees, dated April 3, 1995 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 --------------------- --------- ---------- --------- William B. Ellis CHB, T 06/15/76 04/26/77 Bernard M. Fox 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 EVP, CFO, D 06/01/87 06/01/87 William B. Ellis CH, D 06/15/76 06/15/76 Bernard M. Fox VC, 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 John B. Keane VP, T, 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 W. Noyes 07/01/87 - John F. Opeka D - 06/10/85 PSNH. First First Positions Elected Elected Name Held an Officer a Director ------------------- --------- ---------- ---------- Robert E. Busch EVP, CFO 06/05/92 John C. Collins D - 10/19/92 William B. Ellis CH, D 06/05/92 06/05/92 William T. Frain, Jr. P, COO, D 03/18/71 02/01/94 Bernard M. Fox VC, CEO, D 06/05/92 06/05/92 Cheryl W. Grise D 02/06/95 Gerald Letendre D - 10/19/92 Hugh C. MacKenzie D - 02/01/94 Jane E. Newman D - 10/19/92 John W. Noyes VP, CONT 06/05/92 - 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, CAD, D 09/06/88 01/01/89 Robert E. Busch EVP, CFO, D 06/01/87 06/01/87 William B. Ellis CH, D 06/15/76 06/15/76 Bernard M. Fox VC, 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 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 W. Noyes VP, CONT 04/01/92 - John F. Opeka D - 06/10/85 NAEC. First First Positions Elected Elected Name Held an Officer a Director --------------------- --------- ---------- ---------- Robert E. Busch P, CFO, D 10/21/91 10/16/91 William B. Ellis CH, D 10/21/91 10/16/91 Ted C. Feigenbaum SVP, D 10/21/91 10/16/91 Bernard M. Fox VC, CEO, D 10/21/91 10/16/91 William T. Frain, Jr. D - 02/01/94 Cheryl W. Grise SVP, D 10/21/91 01/01/94 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 W. Noyes VP, CONT 10/21/91 - John F. Opeka EVP, D 10/21/91 10/16/91 KEY: 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 COO - Chief Operating Officer T - Trustee CONT - Controller TR - Treasurer D - Director VC - Vice Chairman VP - Vice President Name Age Business Experience During Past 5 Years ----------------- --- --------------------------------------- Robert G. Abair (1) 56 Elected Vice President and Chief Administrative Officer of WMECO in 1988. Robert E. Busch (2) 48 Elected President and Chief Financial Officer of NAEC in 1994; elected Executive Vice President and Chief Financial Officer of NU, CL&P, PSNH, and WMECO in 1992; previously 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) 50 Chief Executive Officer, The Hitchcock Clinic, Dartmouth - Hitchcock Medical Center since 1977. William B. Ellis (4) 54 Elected Chairman of the Board of NU in 1993; elected Chairman of CL&P, NAEC, PSNH and WMECO in 1993; previously Chairman of the Board and Chief Executive Officer of NU and Chairman and Chief Executive Officer of CL&P and WMECO since 1987, NAEC since 1991 and PSNH since 1992. Ted C. Feigenbaum (5) 44 Elected Senior Vice President of NAEC in 1991; previously Senior Vice President and Chief Nuclear Officer of PSNH June, 1992 to August, 1992; previously 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; Senior Vice President and Chief Operating Officer - New Hampshire Yankee Division of PSNH (1989-1990). Bernard M. Fox (6) 52 Elected Vice Chairman of CL&P and WMECO, and Vice Chairman and Chief Executive Officer of NAEC, in 1994; previously Chief Executive Officer of NU, CL&P, PSNH, WMECO and NAEC in 1993; previously President and Chief Operating Officer of NU, CL&P and WMECO in 1990 and NAEC since 1991; Vice Chairman of PSNH since 1992; previously President and Chief Operating and Financial Officer of NU, CL&P and WMECO since 1987. William T. Frain, Jr.(7) 53 Elected President and Chief Operating Officer of PSNH in 1994; previously Senior Vice President of PSNH since 1992; previously Treasurer of PSNH since 1991 and Vice President of PSNH since 1982. Cheryl W. Grise 42 Elected Senior Vice President-Human Resources and Administrative Services of CL&P, WMECO and NAEC in 1994; previously Vice President-Human Resources of NAEC since 1992 and of CL&P and WMECO since 1991. John B. Keane (8) 48 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, PSNH, WMECO and NAEC since February 1, 1993; previously 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 (9) 62 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 53 President, Diamond Casting & Machine Co., Inc. since 1972. Hugh C. MacKenzie (10) 52 Elected 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 (11) 49 President, Coastal Broadcasting Corporation since 1992; previously Assistant to the President of the United States for Management and Administration from 1989 to 1991. John W. Noyes 47 Elected Vice President and Controller of NU, CL&P, PSNH, WMECO and NAEC in 1992; previously Vice President of CL&P and WMECO since 1987. John F. Opeka (12) 54 Elected Executive Vice President - Nuclear of NAEC in 1991 and of NUSCO in 1986, previously Executive Vice President - Nuclear of CL&P and WMECO from 1986 to 1993. Robert P. Wax 46 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 Connecticut Yankee Atomic Power Company. (3) Director of Fleet Bank - New Hampshire. (4) Director of Nuclear Electric Insurance Limited, Connecticut Mutual Life Insurance Company, The Hartford Steam Boiler Inspection and Insurance Company and Radian Corporation (a subsidiary of Hartford Steam Boiler) and the Greater Hartford Chamber of Commerce; Chairman of the Board of the Capitol Region Growth Council, Inc.; Director Emeritus of Connecticut Yankee Atomic Power Company; Member of The National Museum of Natural History of The Smithsonian Institution and the Science Advisory Board of The Nature Conservancy. (5) Director of Maine Yankee Atomic Power Company. (6) Director of The Institute of Living, The Institute of Nuclear Power Operations, The Connecticut Business and Industry Association, Mount Holyoke College, Shawmut National Corp., CIGNA Corporation, Connecticut Yankee Atomic Power Company and The Dexter Corporation. (7) 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. (8) Director of Maine Yankee Atomic Power Company, Vermont Yankee Nuclear Power Corporation, Yankee Atomic Electric Company and Connecticut Yankee Atomic Power Company. (9) Director of Mid-Conn Bank. (10) Director of Connecticut Yankee Atomic Power Company. (11) Director of Perini Corporation, NYNEX Telecommunications and Consumers Water Company. (12) Director of Connecticut Yankee Atomic Power Company and Yankee Atomic Electric 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 are pages 8 through 13 of the definitive proxy statement for solicitation of proxies by NU's Board of Trustees, dated April 3, 1995 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 five highest-paid executive officers of Northeast Utilities, in accordance with rules of the SEC:
Annual Compensation Long Term Compensation ------------------------------ ------------------------------ Awards Payouts --------------------- -------- Name and Year Salary Bonus ($) Other Restricted Options/ Long All Other Principal ($) (Note 1) Annual Stock Stock Term Compensa- Position Compen- Award(s) Apprecia- Incentive tion ($) sation ($) tion Program (Note 2) ($) Rights(#) Payouts ($) ---------------- ------- ------- ---------- ------- ---------- --------- -------- --------- Bernard M. Fox 1994 544,459 (Note 3) None None None 115,771 4,500 (Note 4) 1993 478,775 180,780 None None None 61,155 7,033 (Note 5) 1992 424,517 54,340 None None None 19,493 6,860 -------------------------------------------------------------------------------------------------------- William B. Ellis 1994 457,769 (Note 3) None None None 185,003 4,500 (Note 4) 1993 521,250 160,693 None None None 87,363 None (Note 5) 1992 522,212 97,029 None None None 30,707 None -------------------------------------------------------------------------------------------------------- Robert E. Busch 1994 346,122 (Note 3) None None None 44,073 4,500 (Note 5) 1993 255,915 78,673 None None None 32,337 7,072 1992 236,654 27,934 None None None 10,040 6,866 -------------------------------------------------------------------------------------------------------- John F. Opeka 1994 283,069 (Note 3) None None None 54,556 4,500 (Note 5) 1993 277,304 58,259 None None None 40,014 6,875 1992 268,958 19,644 None None None 14,017 6,813 -------------------------------------------------------------------------------------------------------- Hugh C. MacKenzie 1994 245,832 (Note 3) None None None 40,449 4,500 (Note 5) 1993 192,502 51,765 None None None 28,000 5,775 1992 178,818 22,045 None None None 7,196 5,322 --------------------------------------------------------------------------------------------------------
Notes: 1. Awards under the 1992 short-term program of the Northeast Utilities Executive Incentive Plan (EIP) were paid in 1993 in the form of unrestricted stock. Awards under the 1993 short-term EIP program were paid in 1994 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 401(k) 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. Based on preliminary estimates of corporate performance, and assuming that the individual performance levels of Messrs. Busch, Opeka and MacKenzie approximate those of other system officers, it is estimated that the five executive officers listed in the table above would receive the following awards: Mr. Fox - $303,000; Mr. Ellis - $127,000; Mr. Busch - $165,000; Mr. Opeka - $81,000; and Mr. MacKenzie - $108,000. 4. Mr. Fox served as President and Chief Operating Officer until July 1, 1993, when he became President and Chief Executive Officer. Mr. Ellis served as Chairman of the Board and Chief Executive Officer until July 1, 1993, when he became Chairman of the Board. 5. The titles for these executive officers are listed by company in "Item 10. Directors and Executive Officers of the Registrants." 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 makes up for benefits lost through application of certain tax code limitations on the benefits that may be provided under the Retirement Plan, and is available to all officers. 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 above is currently eligible for a target benefit. If an executive officer were not eligible for a target benefit at the time of retirement, a lower level of retirement benefits would be paid. 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. FINAL YEARS OF CREDITED SERVICE AVERAGE COMPENSATION 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 above, 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, 1994, the five executive officers named in the Summary Compensation Table above had the following years of credited service for retirement compensation purposes: Mr. Fox - 30, Mr. Ellis - 18, Mr. Busch - 21, Mr. Opeka - 24, and Mr. MacKenzie - 29. Assuming that retirement were to occur at age 65 for these officers, retirement would occur with 43, 29, 38, 35 and 41 years of credited service, respectively. In 1992 Northeast Utilities entered into agreements with Messrs. Ellis and Fox to provide for an orderly Chief Executive Officer succession. The agreement with Mr. Ellis calls for him to work with the Board and Mr. Fox to effect the orderly transition of his responsibilities to Mr. Fox. In accordance with the agreement, Mr. Ellis stepped down as Chief Executive Officer as of July 1, 1993. The agreement anticipates his retirement as of August 1, 1995. The agreement provides that, upon his retirement, Mr. Ellis will be entitled to receive from Northeast Utilities and its subsidiaries a target benefit under the Supplemental Plan. His target benefit will be based on the greater of his actual final average compensation or an amount determined as if his salary had increased each year since 1991 at a rate equal to the average rate of the increases of all other target benefit participants and as if he had received incentive awards each year based on this modified salary, but with the same performance as the Chief Executive Officer at the time. The agreement also provides specified death and disability benefits for the period before Mr. Ellis's 1995 retirement. The agreement with Mr. Fox states that if he 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 terminates two years after Northeast Utilities gives Mr. Fox a notice of termination, but no earlier than the date he becomes 55. The agreements do not address the officers' normal compensation and benefits, which are to be determined by the Committee and the Board in accordance with their customary practices. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT NU. Incorporated herein by reference are pages 6 through 13 of the definitive proxy statement for solicitation of proxies by NU's Board of Trustees, dated April 3, 1995 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 28, 1995, 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) 5,323 shares NU Common Robert E. Busch(4) 7,301 shares NU Common John C. Collins (5)(6) 25 shares NU Common William B. Ellis (7) 10,360 shares NU Common Ted C. Feigenbaum(8) 299 shares NU Common Bernard M. Fox (9) 19,911 shares NU Common William T. Frain, Jr. 1,108 shares NU Common Cheryl W. Grise 2,291 shares NU Common John B. Keane (4) 1,374 shares NU Common Francis L. Kinney (10) 2,415 shares NU Common Gerald Letendre (5) 0 shares NU Common Hugh C. MacKenzie(11)(12) 5,902 shares NU Common Jane E. Newman (5) 0 shares NU Common John W. Noyes 3,272 shares NU Common John F. Opeka (4)(11)(13) 18,271 shares NU Common Robert P. Wax (5) 1,963 shares Amount beneficially owned by Directors and Executive Officers as a group - CL&P 77,528 shares - PSNH 70,404 shares - WMECO 77,528 shares - NAEC 72,504 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 28, 1995 there were 134,210,358 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 only. (4) Messrs. Busch, Keane and Opeka are Directors of CL&P, WMECO and NAEC only. (5) Messrs. Collins, Letendre and Wax and Ms. Newman are Directors of PSNH only. (6) Mr. Collins shares voting and investment power with his wife for 25 shares. (7) Mr. Ellis shares voting and investment power with his wife for 1,208 shares. (8) Mr. Feigenbaum is a Director and an Executive Officer of NAEC only. (9) 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. (10) Mr. Kinney shares voting and investment power with his wife for 525 shares. (11) Messrs. MacKenzie and Opeka are not officers of PSNH, but in their capacity as officers (with their stated titles) of NUSCO, an affiliate of PSNH, they perform policy-making functions for PSNH. (12) Mr. MacKenzie shares voting and investment power with his wife for 1,361 shares. (13) Mr. Opeka shares voting and investment power with his wife for 1,718 shares. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS NU. Incorporated herein by reference is page 15 of the definitive proxy statement for solicitation of proxies by NU's Board of Trustees, dated April 3, 1995 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 1994 with respect to CL&P, PSNH, WMECO and NAEC. PART IV 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: During the fourth quarter of 1994, the companies filed Form 8-Ks dated December 31, 1994 disclosing the following: o The primary reasons for lower composite nuclear capacity factors in 1994. 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 23, 1995 By /s/William B. Ellis -------------- --------------------------- William B. Ellis Chairman of the Board 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 23, 1995 Trustee and Chairman /s/William B. Ellis -------------- of the Board ------------------------- William B. Ellis March 23, 1995 Trustee, President /s/Bernard M. Fox -------------- and Chief Executive ------------------------- Officer Bernard M. Fox March 23, 1995 Executive Vice /s/Robert E. Busch -------------- President and Chief ------------------------- Financial Officer Robert E. Busch March 23, 1995 Vice President and /s/John B. Keane -------------- Treasurer ------------------------- John B. Keane March 23, 1995 Vice President and /s/John W. Noyes -------------- Controller ------------------------- John W. Noyes NORTHEAST UTILITIES SIGNATURES (CONT'D) Date Title Signature ---- ----- --------- March 23, 1995 Trustee /s/Cotton Mather Cleveland -------------- --------------------------- Cotton Mather Cleveland March 23, 1995 Trustee /s/George David -------------- --------------------------- George David March 23, 1995 Trustee /s/Donald J. Donahue -------------- --------------------------- Donald J. Donahue March 23, 1995 Trustee /s/Eugene D. Jones -------------- --------------------------- Eugene D. Jones March 23, 1995 Trustee /s/Gaynor N. Kelley -------------- --------------------------- Gaynor N. Kelley March 23, 1995 Trustee /s/Elizabeth T. Kennan -------------- --------------------------- Elizabeth T. Kennan March 23, 1995 Trustee /s/Denham C. Lunt, Jr. -------------- --------------------------- Denham C. Lunt, Jr. March 23, 1995 Trustee /s/William J. Pape II -------------- --------------------------- William J. Pape II March 23, 1995 Trustee /s/Robert E. Patricelli -------------- --------------------------- Robert E. Patricelli NORTHEAST UTILITIES SIGNATURES (CONT'D) Date Title Signature ---- ----- --------- March 23, 1995 Trustee /s/Norman C. Rasmussen -------------- --------------------------- Norman C. Rasmussen March 23, 1995 Trustee /s/John F. Swope -------------- --------------------------- John F. Swope 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 23, 1995 By /s/William B. Ellis -------------- --------------------- William B. Ellis 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 23, 1995 Chairman and Director /s/William B. Ellis -------------- -------------------------- William B. Ellis March 23, 1995 Vice Chairman and /s/Bernard M. Fox -------------- Director -------------------------- Bernard M. Fox March 23, 1995 President and Director /s/Hugh C. MacKenzie -------------- -------------------------- Hugh C. MacKenzie March 23, 1995 Executive Vice /s/Robert E. Busch -------------- President, Chief -------------------------- Financial Officer Robert E. Busch and Director March 23, 1995 Vice President and /s/John W. Noyes -------------- Controller -------------------------- John W. Noyes THE CONNECTICUT LIGHT AND POWER COMPANY SIGNATURES (CONT'D) Date Title Signature ---- ----- --------- March 23, 1995 Director /s/Robert G. Abair -------------- -------------------------- Robert G. Abair March 23, 1995 Director /s/William T. Frain, Jr. -------------- -------------------------- William T. Frain, Jr. March 23, 1995 Director /s/Cheryl W. Grise -------------- -------------------------- Cheryl W. Grise March 23, 1995 Director /s/John B. Keane -------------- -------------------------- John B. Keane March 23, 1995 Director /s/John F. Opeka -------------- -------------------------- John F. Opeka 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 23, 1995 By /s/William B. Ellis -------------- ------------------------- William B. Ellis 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 23, 1995 Chairman and Director /s/William B. Ellis -------------- -------------------------- William B. Ellis March 23, 1995 Vice Chairman, Chief /s/Bernard M. Fox -------------- Executive Officer and -------------------------- Director Bernard M. Fox March 23, 1995 President, Chief /s/William T. Frain, Jr. -------------- Operating Officer -------------------------- and Director William T. Frain, Jr. March 23, 1995 Executive Vice -------------- President and /s/Robert E. Busch Chief Financial -------------------------- Officer Robert E. Busch March 23, 1995 Vice President and /s/John W. Noyes -------------- Controller -------------------------- John W. Noyes PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE SIGNATURES (CONT'D) Date Title Signature ---- ----- --------- March 23, 1995 Director /s/John C. Collins -------------- -------------------------- John C. Collins March 23, 1995 Director /s/Cheryl W. Grise -------------- -------------------------- Cheryl W. Grise Director -------------- -------------------------- Gerald Letendre March 23, 1995 Director /s/Hugh C. MacKenzie -------------- -------------------------- Hugh C. MacKenzie March 23, 1995 Director /s/Jane E. Newman -------------- -------------------------- Jane E. Newman March 23, 1995 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 23, 1995 By /s/William B. Ellis -------------- -------------------- William B. Ellis 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 23, 1995 Chairman and Director /s/William B. Ellis -------------- -------------------------- William B. Ellis March 23, 1995 Vice Chairman and /s/Bernard M. Fox -------------- Director -------------------------- Bernard M. Fox March 23, 1995 President and Director /s/Hugh C. MacKenzie -------------- -------------------------- Hugh C. MacKenzie March 23, 1995 Executive Vice /s/Robert E. Busch -------------- President, Chief -------------------------- Financial Officer Robert E. Busch and Director March 23, 1995 Vice President and /s/John W. Noyes -------------- Controller -------------------------- John W. Noyes WESTERN MASSACHUSETTS ELECTRIC COMPANY SIGNATURES (CONT'D) Date Title Signature ---- ----- --------- March 23, 1995 Director /s/Robert G. Abair -------------- -------------------------- Robert G. Abair March 23, 1995 Director /s/William T. Frain, Jr. -------------- -------------------------- William T. Frain, Jr. March 23, 1995 Director /s/Cheryl W. Grise -------------- -------------------------- Cheryl W. Grise March 23, 1995 Director /s/John B. Keane -------------- -------------------------- John B. Keane March 23, 1995 Director /s/John F. Opeka -------------- -------------------------- John F. Opeka 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 23, 1995 By /s/William B. Ellis -------------- --------------------- William B. Ellis 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 23, 1995 Chairman and Director /s/William B. Ellis -------------- -------------------------- William B. Ellis March 23, 1995 Vice Chairman, Chief /s/Bernard M. Fox -------------- Executive Officer and -------------------------- Director Bernard M. Fox March 23, 1995 President, Chief /s/Robert E. Busch -------------- Financial Officer -------------------------- and Director Robert E. Busch March 23, 1995 Vice President and /s/John W. Noyes -------------- Controller -------------------------- John W. Noyes NORTH ATLANTIC ENERGY CORPORATION SIGNATURES (CONT'D) Date Title Signature ---- ----- --------- March 23, 1995 /s/Ted C. Feigenbaum -------------- Director -------------------------- Ted C. Feigenbaum March 23, 1995 Director /s/William T. Frain, Jr. -------------- -------------------------- William T. Frain, Jr. March 23, 1995 Director /s/Cheryl W. Grise -------------- -------------------------- Cheryl W. Grise March 23, 1995 Director /s/John B. Keane -------------- -------------------------- John B. Keane March 23, 1995 Director /s/Hugh C. MacKenzie -------------- -------------------------- Hugh C. MacKenzie March 23, 1995 Director /s/John F. Opeka -------------- -------------------------- John F. Opeka 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 17, 1995. Our reports on the financial statements include an explanatory paragraph with respect to the change in methods of accounting for property taxes, postretirement benefits other than pensions, and employee stock ownership plans, 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 17, 1995 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation by reference of our reports 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 10, 1995 INDEX TO FINANCIAL STATEMENT SCHEDULES Schedule Page -------- ---- I. Financial Information of Registrant: Northeast Utilities (Parent) Balance Sheets 1994 and 1993 S-4 Northeast Utilities (Parent) Statements of Income 1994, 1993, and 1992 S-5 Northeast Utilities (Parent) Statements of Cash Flows 1994, 1993, and 1992 S-6 II. Valuation and Qualifying Accounts and Reserves 1994, 1993, and 1992: Northeast Utilities and Subsidiaries S-7 -- S-9 The Connecticut Light and Power Company and Subsidiaries S-10 -- S-12 Public Service Company of New Hampshire S-13 -- S-16 Western Massachusetts Electric Company S-17 -- S-19 All other schedules of the companies' for which provision is made in the applicable regulations of the Securities and Exchange Commission are not required under the related instructions or are not applicable, and therefore have been omitted. SCHEDULE I NORTHEAST UTILITIES (PARENT) FINANCIAL INFORMATION OF REGISTRANT BALANCE SHEETS AT DECEMBER 31, 1994 AND 1993 (Thousands of Dollars)
1994 1993 ---------- ---------- ASSETS ------ Other Property and Investments: Investments in subsidiary companies, at equity............................................... $2,625,228 $2,505,950 Investments in transmission companies, at equity...... 26,106 26,535 Other, at cost........................................ 636 1,710 ----------- ----------- 2,651,970 2,534,195 ----------- ----------- Current Assets: Cash.................................................. 42 72 Notes receivable from affiliated companies............ 1,975 19,625 Taxes receivable...................................... - 485 Receivables from affiliated companies................. 2,598 32,638 Prepayments........................................... 228 73 ----------- ----------- 4,843 52,893 ----------- ----------- Deferred Charges: Accumulated deferred income taxes..................... 7,749 5,859 Unamortized debt expense.............................. 31 45 Other................................................. 26 42 ----------- ----------- 7,806 5,946 ----------- ----------- Total Assets..................................... $2,664,619 $2,593,034 =========== =========== CAPITALIZATION AND LIABILITIES ------------------------------ Capitalization: Common Shareholders' Equity: Common shares, $5 par value--Authorized 225,000,000 shares; 134,210,226 shares issued and 124,962,981 shares outstanding in 1994 and 134,207,025 shares issued and 124,326,836 outstanding in 1993..................... $ 671,051 $ 671,035 Capital surplus, paid in.............................. 904,371 901,740 Deferred benefit plan--employee stock ownership plan.. (213,324) (228,205) Retained earnings..................................... 946,988 879,518 ----------- ----------- Total common shareholders' equity................... 2,309,086 2,224,088 Long-term debt........................................ 224,000 236,000 ----------- ----------- Total capitalization................................ 2,533,086 2,460,088 ----------- ----------- Current Liabilities: Notes payable to banks................................ 104,000 72,500 Long-term debt and preferred stock--current portion... 12,000 9,000 Accounts payable...................................... 962 5,048 Accounts payable to affiliated companies.............. 2,944 42,459 Accrued taxes......................................... 7,454 - Accrued interest...................................... 3,623 3,311 Other................................................. 17 13 ----------- ----------- 131,000 132,331 ----------- ----------- Other Deferred Credits.................................. 533 615 ----------- ----------- Total Capitalization and Liabilities $2,664,619 $2,593,034 =========== ===========
SCHEDULE I NORTHEAST UTILITIES (PARENT) FINANCIAL INFORMATION OF REGISTRANT STATEMENTS OF INCOME YEARS ENDED DECEMBER 31, 1994, 1993, AND 1992 (Thousands of Dollars Except Share Information)
1994 1993 1992 ------------- ------------- ------------- Operating Revenues............... $ - $ - $ - ------------- ------------- ------------- Operating Expenses: Other.......................... 13,114 2,677 (22,915) Federal income taxes........... (10,736) (7,564) 12,736 ------------- ------------- ------------- Total operating expenses...... 2,378 (4,887) (10,179) ------------- ------------- ------------- Operating Income (Loss).......... (2,378) 4,887 10,179 ------------- ------------- ------------- Other Income: Equity in earnings of subsidiaries.................. 309,769 263,725 238,624 Equity in earnings of transmission companies........ 3,418 3,736 4,141 Other, net..................... 679 1,302 6,439 ------------- ------------- ------------- Other income, net............ 313,866 268,763 249,204 ------------- ------------- ------------- Income before interest charges..................... 311,488 273,650 259,383 ------------- ------------- ------------- Interest Charges................. 24,614 23,697 3,329 ------------- ------------- ------------- Net Income ...................... 286,874 249,953 256,054 Tax benefit of Employee Stock Ownership Plan dividends........ - - 7,348 ------------- ------------- ------------- Earnings For Common Shares....... $ 286,874 $ 249,953 $ 263,402 ============= ============= ============= Earnings Per Common Share........ $ 2.30 $ 2.02 $ 2.02 ============= ============= ============= Common Shares Outstanding (average)....................... 124,678,192 123,947,631 130,403,488 ============= ============= =============
SCHEDULE I NORTHEAST UTILITIES (PARENT) FINANCIAL INFORMATION OF REGISTRANT STATEMENT OF CASH FLOWS YEARS ENDED DECEMBER 31, 1994, 1993, 1992 (Thousands of Dollars)
1994 1993 1992 -------------- -------------- -------------- Cash Flows From Operating Activities: Net income $ 286,874 $ 249,953 $ 256,054 Adjustments to reconcile to net cash from operating activities: Equity in earnings of subsidiary companies (309,769) (263,725) (238,624) Cash dividends received from subsidiary companies 201,403 191,297 196,267 Deferred income taxes (1,890) (3,199) 7,382 Other sources of cash 3,007 197 19,244 Other uses of cash (169) (3,915) (5,943) Changes in working capital: Receivables and accrued utility revenues 30,525 (25,012) 34,621 Accounts payable (43,601) 27,066 (4,528) Other working capital (excludes cash) 7,615 (3,010) (4,203) -------------- -------------- -------------- Net cash flows from operating activities 173,995 169,652 260,270 -------------- -------------- -------------- Cash Flows From Financing Activities: Issuance of common shares 14,551 22,252 271,128 Issuance of long-term debt - - 75,000 Net increase in short-term debt 31,500 2,000 70,500 Reacquisitions and retirements of long-term debt (9,000) (5,000) - Cash dividends on common shares (219,317) (218,179) (229,074) -------------- -------------- -------------- Net cash flows (used for) from financing activities (182,266) (198,927) 187,554 -------------- -------------- -------------- Investment Activities: NU System Money Pool 17,650 32,975 130,400 Investment in subsidiaries (10,912) (4,853) (592,715) Other investment activities, net 1,503 1,152 (83) -------------- -------------- -------------- Net cash flows used for investments 8,241 29,274 (462,398) -------------- -------------- -------------- Net increase (decrease) in cash for the period (30) (1) (14,574) Cash - beginning of period 72 73 14,647 -------------- -------------- -------------- Cash - end of period $ 42 $ 72 $ 73 ============== ============== ============== Supplemental Cash Flow Information Cash paid during the year for: Interest, net of amounts capitalized during construction $ 24,235 $ 23,808 $ (11,419) ============== ============== ============== Income taxes (refund) $ (16,786) $ - $ (4,277) ============== ============== ==============
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 ========= ========= ========= ========= ========= RESERVES NOT APPLIED AGAINST ASSETS: Injuries and damages (b) $ 15,719 $ 8,437 $ - $ 6,433 (c) $ 17,723 ========= ========= ========= ========= ========= Medical insurance (d) $ 8,657 $ (2,365)(e)$ - $ - $ 6,292 ========= ========= ========= ========= ========= (a) Amounts written off, net of recoveries. (b) Provided to cover claims for injuries to employees, workmen's compensation, bodily injury to others, and property damage. (c) Principally payments for various injuries and damages and expenses in connection therewith. (d) Provided to cover claims for employee medical insurance. (e) Reflects change in medical insurance programs.
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 ========= ========= ========= ========= ========= RESERVES NOT APPLIED AGAINST ASSETS: Injuries and damages (b) $ 14,059 $ 9,231 $ - $ 7,571 (c) $ 15,719 ========= ========= ========= ========= ========= Medical insurance (d) $ 9,430 $ 42,442 $ - $ 43,215 (e) $ 8,657 ========= ========= ========= ========= ========= (a) Amounts written off, net of recoveries. (b) Provided to cover claims for injuries to employees, workmen's compensation, bodily injury to others, and property damage. (c) Principally payments for various injuries and damages and expenses in connection therewith. (d) Provided to cover claims for employee medical insurance. (e) Principally payments for various employee medical expenses and expenses in connection therewith.
NORTHEAST UTILITIES AND SUBSIDIARIES SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES YEAR ENDED DECEMBER 31, 1992 (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 $ 11,607 $ 20,005 $ 2,826 (a)$ 21,183 (b)$ 13,255 ========= ========= ========= ========= ========= RESERVES NOT APPLIED AGAINST ASSETS: Injuries and damages (c) $ 9,465 $ 8,275 $ 3,138 (a)$ 6,819 (d)$ 14,059 ========= ========= ========= ========= ========= Medical insurance (e) $ 6,869 $ 39,693 $ 1,150 (a)$ 38,282 (f)$ 9,430 ========= ========= ========= ========= ========= (a) Acquired as part of Northeast Utilities acquisition of Public Service Company of New Hampshire on June 5, 1992. (b) Amounts charged off as uncollectible after deducting customers' deposits and recoveries of accounts previously charged off. (c) Provided to cover claims for injuries to employees, workmen's compensation, bodily injury to others, and property damage. (d) Principally payments for various injuries and damages and expenses in connection therewith. (e) Provided to cover claims for employee medical insurance. (f) Principally payments for various employee medical expenses and expenses in connection
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 ========= ========= ========= ========= ========= RESERVES NOT APPLIED AGAINST ASSETS: Injuries and damages (b) $ 9,653 $ 6,052 $ - $ 5,197 (c) $ 10,508 ========= ========= ========= ========= ========= Medical insurance (d) $ 2,367 $ (667)(e)$ - $ - $ 1,700 ========= ========= ========= ========= ========= (a) Amounts charged off as uncollectible after deducting customers' deposits and recoveries of accounts previously charged off. (b) Provided to cover claims for injuries to employees, workmen's compensation, bodily injury to others, and property damage. (c) Principally payments for various injuries and damages and expenses in connection therewith. (d) Provided to cover claims for employee medical insurance. (e) Reflects change in medical insurance programs.
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 ========= ========= ========= ========= ========= RESERVES NOT APPLIED AGAINST ASSETS: Injuries and damages (b) $ 8,359 $ 7,115 $ - $ 5,821 (c) $ 9,653 ========= ========= ========= ========= ========= Medical insurance (d) $ 3,496 $ 19,846 $ - $ 20,975 (e) $ 2,367 ========= ========= ========= ========= ========= (a) Amounts charged off as uncollectible after deducting customers' deposits and recoveries of accounts previously charged off. (b) Provided to cover claims for injuries to employees, workmen's compensation, bodily injury to others, and property damage. (c) Principally payments for various injuries and damages and expenses in connection therewith. (d) Provided to cover claims for employee medical insurance. (e) Principally payments for various 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, 1992 (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 $ 9,560 $ 14,837 $ - $ 16,039 (a)$ 8,358 ========= ========= ========= ========= ========= RESERVES NOT APPLIED AGAINST ASSETS: Injuries and damages (b) $ 7,369 $ 6,600 $ - $ 5,610 (c)$ 8,359 ========= ========= ========= ========= ========= Medical insurance (d) $ 3,429 $ 19,770 $ - $ 19,703 (e)$ 3,496 ========= ========= ========= ========= ========= (a) Amounts charged off as uncollectible after deducting customers' deposits and recoveries of accounts previously charged off. (b) Provided to cover claims for injuries to employees, workmen's compensation, bodily injury to others, and property damage. (c) Principally payments for various injuries and damages and expenses in connection therewith. (d) Provided to cover claims for employee medical insurance. (e) Principally payments for various 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: Injuries and damages $ 2,045 $ 600 $ - $ 371 (b) $ 2,274 ========= ========= ========= ========= ========= Medical insurance $ 1,915 $ (915)(c)$ - $ - $ 1,000 ========= ========= ========= ========= ========= (a) Amounts written off, net of recoveries. (b) Principally payments for various injuries and damages and expenses in connection therewith. (c) Reflects change in medical insurance programs.
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: Injuries and damages $ 2,770 $ 192 $ - $ 917 (b) $ 2,045 ========= ========= ========= ========= ========= Medical insurance $ 1,650 $ 265 $ - $ - $ 1,915 ========= ========= ========= ========= ========= (a) Amounts written off, net of recoveries. (b) Principally payments for various injuries and damages and expenses in connection therewith.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES FOR THE PERIOD JANUARY 1, 1992 THROUGH JUNE 4, 1992 (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 $ 2,834 $ 1,581 $ - $ 1,589 (a)$ 2,826 ========= ========= ========= ========= ========= RESERVES NOT APPLIED AGAINST ASSETS: Injuries and damages $ 1,615 $ 1,618 $ - $ 95 (b)$ 3,138 ========= ========= ========= ========= ========= Medical insurance $ 1,050 $ 100 $ - $ - $ 1,150 ========= ========= ========= ========= ========= (a) Amounts written off, net of recoveries. (b) Nonoperating reserve transferred to operating.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES FOR THE PERIOD JUNE 5, 1992 THROUGH DECEMBER 31, 1992 (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 $ 2,826 $ 1,617 $ - $ 1,663 (b)$ 2,780 ========= ========= ========= ========= ========= RESERVES NOT APPLIED AGAINST ASSETS: Injuries and damages $ 3,138 $ (277)$ - $ 91 (c)$ 2,770 ========= ========= ========= ========= ========= Medical insurance $ 1,150 $ 500 $ - $ - $ 1,650 ========= ========= ========= ========= ========= (a) Public Service Company of New Hampshire was acquired by Northeast Utilities on June 5, 1992. (b) Amounts written off, net of recoveries. (c) Nonoperating reserve transferred to operating.
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: Injuries and damages (b) $ 2,760 $ 1,551 $ - $ 617 (c) $ 3,694 ========= ========= ========= ========= ========= Medical insurance (d) $ 467 $ (117)(e)$ - $ - $ 350 ========= ========= ========= ========= ========= (a) Amounts written off, net of recoveries. (b) Provided to cover claims for injuries to employees, workmen's compensation, bodily injury to others, and property damage. (c) Principally payments for various injuries and damages and expenses in connection therewith. (d) Provided to cover claims for employee medical insurance. (e) Reflects change in medical insurance programs.
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: Injuries and damages (b) $ 1,612 $ 1,750 $ - $ 602 (c) $ 2,760 ========= ========= ========= ========= ========= Medical insurance (d) $ 741 $ 4,017 $ - $ 4,291 (e) $ 467 ========= ========= ========= ========= ========= (a) Amounts written off, net of recoveries. (b) Provided to cover claims for injuries to employees, workmen's compensation, bodily injury to others, and property damage. (c) Principally payments for various injuries and damages and expenses in connection therewith. (d) Provided to cover claims for employee medical insurance. (e) Principally payments for various employee medical expenses and expenses in connection therewith.
WESTERN MASSACHUSETTS ELECTRIC COMPANY SCHEDULE II VALUATION AND QUALIFYING ACCOUNTS AND RESERVES YEAR ENDED DECEMBER 31, 1992 (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 $ 1,977 $ 3,303 $ - $ 3,163 (a)$ 2,117 ========= ========= ========= ========= ========= RESERVES NOT APPLIED AGAINST ASSETS: Injuries and damages (b) $ 1,496 $ 1,200 $ - $ 1,084 (c)$ 1,612 ========= ========= ========= ========= ========= Medical insurance (d) $ 667 $ 3,916 $ - $ 3,842 (e)$ 741 ========= ========= ========= ========= ========= (a) Amounts written off, net of recoveries. (b) Provided to cover claims for injuries to employees, workmen's compensation, bodily injury to others, and property damage. (c) Principally payments for various injuries and damages and expenses in connection therewith. (d) Provided to cover claims for employee medical insurance.
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 1994 Annual Report on Form 10-K for NU and herein incorporated by reference from the 1994 NU Form 10-K, File No. 1-5324 into the 1994 Annual Reports on Form 10-K for CL&P, PSNH, WMECO and NAEC. # - Filed with the 1994 Annual Report on Form 10-K for NU and herein incorporated by reference from the 1994 NU Form 10-K, File No. 1-5324 into the 1994 Annual Report on Form 10-K for CL&P. @ - Filed with the 1994 Annual Report on Form 10-K for NU and herein incorporated by reference from the 1994 NU Form 10-K, File No. 1-5324 into the 1994 Annual Report on Form 10-K for PSNH. ** - Filed with the 1994 Annual Report on Form 10-K for NU and herein incorporated by reference from the 1994 NU Form 10-K, File No. 1-5324 into the 1994 Annual Report on Form 10-K for WMECO. ## - Filed with the 1994 Annual Report on Form 10-K for NU and herein incorporated by reference from the 1994 Form 10-K, File No. 1-5324 into the 1994 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 22, 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. ** 3.4.2 By-laws of WMECO, as amended to February 13, 1995. 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 19 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) 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 October 1, 1992. (Exhibit 4.32, File No. 33-59430) 4.2.10 July 1, 1993. (Exhibit A.10(b), File No. 70-8249) 4.2.11 July 1, 1993. (Exhibit A.10(b), File No. 70-8249) 4.2.12 December 1, 1993. (Exhibit 4.2.14, 1993 NU Form 10-K, File No. 1-5324) 4.2.13 February 1, 1994. 1(Exhibit 4.2.15, 1993 NU Form 10-K, File No. 1-5324) 4.2.14 February 1, 1994. (Exhibit 4.2.16, 1993 NU Form 10-K, File No. 1-5324) # 4.2.15 June 1, 1994. # 4.2.16 October 1, 1994. 4.2.17 Financing Agreement between Industrial Development Authority of the State of New Hampshire and CL&P (Pollution Control Bonds) dated as of December 1, 1986. (Exhibit C.1.47, 1986 NU Form U5S, File No. 30-246) 4.2.18 Financing Agreement between Industrial Development Authority of the State of New Hampshire and CL&P Pollution Control Bonds) dated as of October 1, 1988. (Exhibit C.1.55, 1988 NU Form U5S, File No. 30-246) 4.2.19 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) 4.2.20 Loan and Trust Agreement among Business Finance Authority of the State of New Hampshire and CL&P (Pollution Control Bonds) dated as of December 1, 1992. (Exhibit C.2.33, 1992 NU Form U5S, File No. 30-246) 4.2.21 Series A (Tax Exempt Refunding) PCRB Loan Agreement between Connecticut Development Authority and CL&P (Pollution Control Bonds) dated as of September 1, 1993. (Exhibit 4.2.21, 1993 NU Form 10-K, File No. 1-5324) 4.2.22 Series B (Tax Exempt Refunding) PCRB Loan Agreement between Connecticut Development Authority and CL&P (Pollution Control Bonds) dated as of September 1, 1993. (Exhibit 4.2.22, 1993 NU Form 10-K, File No. 1-5324) 4.2.23 Series A (Tax Exempt Refunding) PCRB Letter of Credit and Reimbursement Agreement (Pollution Control Bonds) dated as of September 1, 1993. (Exhibit 4.2.23, 1993 NU Form 10-K, File No. 1-5324) 4.2.24 Series B (Tax Exempt Refunding) PCRB Letter of Credit and Reimbursement Agreement (Pollution Control Bonds) dated as of September 1, 1993. (Exhibit 4.2.24, 1993 NU Form 10-K, File No. 1-5324) 4.2.25 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) 4.2.26 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) 4.2.27 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 May 1, 1991. (Exhibit 4.12, PSNH Current Report on Form 8-K dated February 10, 1992, File No. 1-6392) 4.3.3 Term Credit Agreement dated as of May 1, 1991. (Exhibit 4.11, PSNH Current Report on Form 8-K dated February 10, 1992, File No. 1-6392) 4.3.4 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) 4.3.5 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) 4.3.6 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) 4.3.7 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) 4.3.7.1 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) 4.3.8 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) 4.3.8.1 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) 4.3.9 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 October 1, 1992. (Exhibit 4.3.9, 1993 NU Form 10-K, File No. 1-5324) 4.3.9.1 Amended and Restated Letter of Credit dated December 17, 1992. (Exhibit 4.3.9.1, 1993 NU Form 10-K, File No. 1-5324) 4.3.10 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, 1991. (Exhibit 4.8, PSNH Current Report on Form 8-K dated February 10, 1992, File No. 1-6392) 4.3.10.1 Amended and Restated Letter of Credit dated December 15, 1993. (Exhibit 4.3.10.1, 1993 NU Form 10-K, File No. 1-5324) 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 March 1, 1968. (Exhibit 2.6, File No. 2-68808) 4.4.4 September 1, 1990. (Exhibit 4.3.15, 1990 NU Form 10-K, File No. 1-5324.) 4.4.5 December 1, 1992. (Exhibit 4.15, File No. 33-55772) 4.4.6 January 1, 1993. (Exhibit 4.5.13, 1992 NU Form 10-K, File No. 1-5324) 4.4.7 March 1, 1994. (Exhibit 4.4.11, 1993 NU Form 10-K, File No. 1-5324) 4.4.8 March 1, 1994. (Exhibit 4.4.12, 1993 NU Form 10-K, File No. 1-5324) 4.4.9 Series A (Tax Exempt Refunding) PCRB Loan Agreement between Connecticut Development Authority and WMECO (Pollution Control Bonds) dated as of September 1, 1993. (Exhibit 4.4.13, 1993 NU Form 10-K, File No. 1-5324) 4.4.10 Series A (Tax Exempt Refunding) PCRB Letter of Credit and Reimbursement Agreement (Pollution Control Bonds) 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 Note Indenture dated as of May 15, 1991. (Exhibit 4.10, PSNH Current Report on Form 8-K dated February 10, 1992, File No. 1-6392) 4.5.3 First Supplemental Indenture dated as of June 5, 1992 between NAEC, PSNH and United States Trust Company of New York, Trustee. (Exhibit 4.6.3, 1992 NU Form 10-K, File No. 1-5324) 10 Material Contracts #@** 10.1 Stockholder Agreement dated as of July 1, 1964 among the stockholders of Connecticut Yankee Atomic Power Company (CYAPC). #@** 10.2 Form of Power Contract dated as of July 1, 1964 between CYAPC and each of CL&P, HELCO, PSNH and WMECO. #@** 10.2.1 Form of Additional Power Contract dated as of April 30, 1984, between CYAPC and each of CL&P, PSNH and WMECO. 10.2.2 Form of 1987 Supplementary Power Contract dated as of April 1, 1987, between CYAPC and each (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. 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. 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. 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. 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). 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 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) * 10.17 Agreement (composite) for joint ownership, construction and operation of New Hampshire nuclear, as amended through the November 1, 1990 twenty-third amendment. 10.17.1 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) 10.17.2 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) 10.17.2.1 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) 10.18 Amended and Restated Agreement for Seabrook Project Disbursing Agent dated as of November 1, 1990. (Exhibit 10.4.7, File No. 33-35312) 10.18.1 Form of First Amendment to Exhibit 10.18. (Exhibit 10.4.8, File No. 33-35312) 10.18.2 Form (Composite) of Second Amendment to Exhibit 10.18. (Exhibit 10.18.2, 1993 NU Form 10-K, File No. 1-5324) 10.19 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) 10.19.1 Amendment to Exhibit 10.19 dated June 30, 1975. (Exhibit 5.48, File No. 2-55458) 10.19.2 Amendment to Exhibit 10.19 dated as of August 16, 1976. (Exhibit 5.19, File No. 2-58251) 10.19.3 Amendment to Exhibit 10.19 dated as of December 31, 1978. (Exhibit 5.10.3, File No. 2-64294) 10.20 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) 10.20.1 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) 10.20.2 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) 10.20.3 Form of Annual Renewal of Service Contract. (Exhibit 10.20.3, 1993 NU Form 10-K, File No. 1-5324) 10.21 Memorandum of Understanding between CL&P, HELCO, Holyoke Power and Electric Company (HP&E), Holyoke Water Power Company (HWP) and WMECO dated as of June 1, 1970 with respect to pooling of generation and transmission. (Exhibit 13.32, File No. 2-38177) 10.21.1 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) **#10.21.2 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. 10.22 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.) 10.22.1 Twenty-sixth Amendment to Exhibit 10.22 dated as of March 15, 1989. (Exhibit 10.15.1, 1990 NU Form 10-K, File No. 1-5324) 10.22.2 Twenty-seventh Amendment to Exhibit 10.22 dated as of October 1, 1990. (Exhibit 10.15.2, 1991 NU Form 10-K, File No. 1-5324) 10.22.3 Twenty-eighth Amendment to Exhibit 10.22 dated as of September 15, 1992. (Exhibit 10.18.3, 1992 NU Form 10-K, File No. 1-5324) 10.22.4 Twenty-ninth Amendment to Exhibit 10.22 dated as of May 1, 1993. (Exhibit 10.22.4, 1993 NU Form 10-K, File No. 1-5324) 10.23 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.) 10.24 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) 10.24.1 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) #@**10.25 Simulator Financing Lease Agreement, dated as of February 1, 1985, by and between ComPlan and NNECO. #@**10.26 Simulator Financing Lease Agreement, dated as of May 2, 1985, by and between The Prudential Insurance Company of America and NNECO. 10.27 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) 10.27.1 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) 10.28 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) 10.29 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.) 10.30 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) 10.30.1 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) 10.30.2 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) 10.31 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) 10.31.1 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) 10.32 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 2 decommissioning costs. (Exhibit 10.81, 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 10.42.1, 1992 NU Form 10-K, File No. 1-5324) 10.33 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) 10.33.1 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) 10.34 NU Executive Incentive Plan, effective as of January 1, 1991. (Exhibit 10.44, NU 1991 Form 10-K, File No. 1-5324) 10.35 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) 10.35.1 Amendment 1 to Exhibit 10.35, effective as of August 1, 1993. (Exhibit 10.35.1, 1993 NU Form 10-K, File No. 1-5324) 10.35.2 Amendment 2 to Exhibit 10.35, effective as of January 1, 1994. (Exhibit 10.35.2, 1993 NU Form 10-K, File No. 1-5324) 10.36 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) 10.36.1 First Amendment to Exhibit 10.36 dated February 7, 1992. (Exhibit 10.36.1, 1993 NU Form 10-K, File No. 1-5324) 10.36.2 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) 10.36.3 Second Amendment to Exhibit 10.36 dated April 9, 1992. (Exhibit 10.36.3, 1993 NU Form 10-K, File No. 1-5324) 10.37 Management Succession Agreement. (Exhibit 10.47, NU Form 10-Q for the Quarter Ended June 30, 1992, 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) 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 16 - 50) 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 (Exhibit 22, 1992 NU Form 10-K, File 1-5324) 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. EX-3.4.1 2 THE COMMONWEALTH OF MASSACHUSETTS FEDERAL ID MICHAEL JOSEPH CONNOLLY Secretary of State NO. 04-1961130 ONE ASHBURTON PLACE, BOSTON, MASS, 02108 RESTATED ARTICLES OF ORGANIZATION General Laws, Chapter 164, Section 8C This certificate must be submitted to the Secretary of the Commonwealth within sixty days after the date of the vote of stockholders adopting the restated articles of organization. The fee for filing this certificate is prescribed by General Laws, Chapter 156B, Section 114. Make check payable to The Commonwealth of Massachusetts. We, Hugh C. MacKenzie, President Mark A. Joyse, Assistant Clerk of WESTERN MASSACHUSETTS ELECTRIC COMPANY located at, 174 Brush Hill Avenue, West Springfield, Massachusetts 01089 do hereby certify that the following restatement of the articles of organization of the corporation was duly adopted by unanimous consent on , 1995, by vote of 1,072,471 shares of common out of 1,072,471 shares outstanding, (Class of Stock) being all of each class of stock outstanding and entitled to vote thereon 1. The name by which the corporation shall be known is: WESTERN MASSACHUSETTS ELECTRIC COMPANY 2. The purpose for which the corporation is formed are as follows: See attached RIDER 2A, pages 1-2 3. The total number of shares and the par value, if any, of each class of stock which the corporate is authorized to issue is as follows: WITHOUT PAR VALUE WITH PAR VALUE CLASS OF STOCK NUMBER OF SHARES NUMBER OF SHARES PAR VALUE 7.72% Preferred Stock, 200,000 $100 Series B Preferred 7.60% Class A, 1,200,000 $ 25 Preferred Stock, 1987 Series Dutch Auction Rate Transferable Securities Class A, 2,140,000 $ 25 Preferred Stock, 1988 Series Common 1,072,471 $ 25 *4. If more than one class is authorized, a description of each of the difference classes of stock with, if any, the preferences, voting powers, qualifications, special or relative rights or privileges as to each class thereof and any series now established: See attached RIDER 4A, pages 1-28 *5. The restrictions, if any, imposed by the articles or organization upon the transfer of shares of stock of any class are as follows: None *6. Other lawful provisions, if any, for the conduct and regulation of the business and affairs of the corporation, for its voluntary dissolution, or for limiting, defining, or regulating the powers of the corporation, or of its directors or stockholders, or of any class of stockholders: See attached RIDER 6A, page 1 *If there are no such provisions, state "None". WESTERN MASSACHUSETTS ELECTRIC COMPANY RESTATED ARTILCES OF ORGANIZATION RIDER 2A To make, purchase, transmit, distribute, and sell electricity. To generate, by means of water power, steam power, atomic energy, or other means, electricity within or without the Commonwealth of Massachusetts; to purchase from others electricity generated within or without the said Commonwealth; and to sell or distribute and sell electricity within or without the said Commonwealth. To supply electricity in bulk within or without the said Commonwealth. To transmit, within or without the said Commonwealth, electricity for itself and for others. To manufacture, by such means as may be necessary or desirable for the purpose, steam, and to sell or distribute and sell steam within or without the said Commonwealth. To construct, operate, and maintain, within or without the said Commonwealth, works and structures, including, without limitation, dams, reservoirs, canals, power houses, water conduits, cables, transmission lines, substations and other facilities used or useful for the purpose of generating and transmitting electricity and for incidental beneficial uses, including recreational and water supply purposes. To hold, purchase, convey, sell, mortgage or lease, within or without the said Commonwealth, real or personal property, including without limiting the generality of the foregoing the right to hold property as a tenant-in-common with others. To purchase, hold, display, lease, sell or otherwise obtain receipts from, and to install and service within the Commonwealth, merchandise, equipment, utensils, and chattels of any description incidental or auxiliary to the use of electricity distributed to its consumers, or necessary or expedient in the protection or management of its property used in its business. To carry on and conduct from time to time all activities to which its utility properties may be usefully applied, subject to all requisite regulatory approvals. To loan its funds or invest its funds in the stocks, bonds, certificates of participation, or other securities of any domestic or foreign corporation, association, or trust, subject to all requisite regulatory approvals. To guarantee the performance of any contract or obligation of domestic or foreign corporations, associations, or trusts, any obligation of which or any interest in which is held by this corporation or in the affairs of which this corporation has an interest, subject to all requisite regulatory approvals. To indemnify, to the extent permitted by law, its officers and directors, past or present, against all liability and expenses incurred in connection with the defense or disposition of any action, suit or proceeding, actual or threatened, whether civil or criminal, in which they may be involved by reason of being or having been directors or officers. To do every act and thing necessary, convenient, or proper for the accomplishment of any of the purposes herein enumerated, or incidental to any of the powers herein stated. It is expressly intended that no specific enumeration in the foregoing clauses shall restrict in any way any general language, that none of the purposes set forth in any of the above clauses shall be limited or restricted in any way by the terms of any other clause, that each purpose may be pursued independently of any other purpose from time to time and whenever deemed desirable, and that the corporation shall have and possess all the rights, privileges, and powers now or hereafter conferred by the laws of the Commonwealth of Massachusetts upon electric companies organized under such laws. WESTERN MASSACHUSETTS ELECTRIC COMPANY RESTATED ARTILCES OF ORGANIZATION RIDER 4A CAPITAL STOCK PROVISIONS PART ONE AMOUNT AND CLASSES OF AUTHORIZED STOCK The Company's capital stock includes a class of capital stock designated "Common Stock," a class of capital stock designated "Preferred Stock," and a class of capital stock designated "Class A Preferred Stock." The authorized number of shares of Common Stock is 1,072,471 shares of the par value of $25 per share. The authorized number of shares of Preferred Stock is 200,000 shares of the par value of $100 per share. The authorized number of shares of Class A Preferred Stock is 3,340,000 shares of the par value of $25 per share. The Preferred Stock and the Class A Preferred Stock are hereinafter for convenience of reference sometimes collectively referred to as the "Senior Stock," and either class may hereinafter individually be referred to as "Senior Stock." Shares of Preferred Stock and shares of Class A Preferred Stock shall rank on a parity in respect of dividends or payment in case of liquidation, and, to the extent not fixed and determined by these Articles of Organization or the Company's By-laws or otherwise by law, shall have the same rights, preferences and powers. The general terms, limitations and relative rights and preferences of each share of Preferred Stock and each share of Class A Preferred Stock shall be determined in accordance with the following Sections: Section 1. Issuance of Senior Stock Shares of Preferred Stock may be issued from time to time in one or more series on such terms and for such consideration as may be determined by the Board of Directors. Shares of Class A Preferred Stock may be issued from time to time in one or more series on such terms and for such consideration as may be determined by the Board of Directors. The variations in the relative rights and preferences as between the different series of either class of Senior Stock, the series designation, dividend rate, redemption prices, and any other terms or limitations shall be determined by the Board of Directors to the extent not fixed and determined by law or by these Articles of Organization or the Company's By-laws. Section 2. Dividends A. The holders of either class of the Senior Stock shall receive, but only when and as declared by the Board of Directors, cumulative dividends at the rate provided for the particular series and payable on such dividend payment dates in each year as said Board may determine, such dividends to be payable to holders of record on such dates as may be fixed by said Board but not more than 45 days before each dividend date, provided, however, that dividends shall not be declared and set apart for payment, or paid, on Senior Stock of any one class and series, for any dividend period, unless dividends have been or are contemporaneously declared and set apart for payment, or paid, on Senior Stock of all series for all dividend periods terminating on the same or an earlier date. B. Dividends on each share of Senior Stock shall be cumulative from the date of issue thereof or from such earlier date as the Board of Directors may determine therefor. Unless full cumulative dividends to the last preceding dividend date shall have been paid or set apart for payment on all outstanding shares of Senior Stock, no dividend shall be paid on any junior stock. The term "junior stock" means Common Stock or any other stock of the Company subordinate to the Senior Stock in respect of dividends or payments in liquidation. C. So long as any shares of Senior Stock are outstanding, the Company shall not declare any dividends or make any other distributions in respect of outstanding shares of any junior stock of the Company, other than dividends or distributions in shares of junior stock, or purchase or otherwise acquire for value any outstanding shares of junior stock (the declaration of any such dividend or the making of any such distribution, purchase or acquisition being herein called a "junior stock payment") in contravention of the following: (1) If and so long as the junior stock equity (hereinafter defined), adjusted to reflect the proposed junior stock payment, at the end of the calendar month immediately preceding the calendar month in which the proposed junior stock payment is to be made is less than 20% of total capitalization (hereinafter defined) at that date, as so adjusted, the Company shall not make such junior stock payment in an amount which, together with all other junior stock payments made within the year ending with and including the date on which the proposed junior stock payment is to be made, exceeds 50% of the net income of the Company available for dividends on junior stock for the 12 full calendar months immediately preceding the calendar month in which such junior stock payment is made, except in an amount not exceeding the aggregate of junior stock payments which under the restrictions set forth above in this paragraph (1) could have been, and have not been, made. (2) If and so long as the junior stock equity, adjusted to reflect the proposed junior stock payment, at the end of the calendar month immediately preceding the calendar month in which the proposed junior stock payment is to be made, is less than 25% but not less than 20% of the total capitalization at that date, as so adjusted, the Company shall not make such junior stock payment in an amount which, together with all other junior stock payments made within the year ending with and including the date on which the proposed junior stock payment is to be made, exceeds 75% of the net income of the Company available for dividends on the junior stock for the 12 full calendar months immediately preceding the calendar month in which such junior stock payment is made, except in an amount not exceeding the aggregate of junior stock payments which under the restrictions set forth above in this paragraph (2) could have been, and have not been, made. D. The term "junior stock equity" means the aggregate of the part value of or stated capital represented by, the outstanding shares of junior stock, all earned surplus, capital or paid-in surplus, and any premiums on the junior stock then carried on the books of the Company, less: (1) the excess, if any, of the aggregate amount payable on involuntary liquidation of the Company upon all outstanding shares of Senior Stock over the sum of (i) the aggregate par or stated value of such shares and (ii) any premiums thereon; (2) any amounts on the books of the Company known, or estimated if not known, to represent the excess, if any, of recorded value over original cost of used or useful utility plant; and (3) any intangible items set forth on the asset side of the balance sheet of the Company as a result of accounting convention, such as unamortized debt discount and expense; provided, however, that no deductions shall be required to be made in respect of items referred to in clauses (2) and (3) of this subsection D in cases in which such items are being amortized or are provided for, or are being provided for, by reserves. E. The term "total capitalization" means the aggregate of: (1) the principal amount of all outstanding indebtedness of the Company maturing more than 12 months after the date of issue thereof; and (2) the par value or stated capital represented by, and any premiums carried on the books of the Company in respect of, the outstanding shares of all classes of the capital stock of the Company, earned surplus, and capital or paid-in surplus, less any amounts required to be deducted pursuant to clauses (2) and (3) of subsection D of this Section 2 in the determination of junior stock equity. Section 3. Redemption or Purchase of Senior Stock A. All or any part of any series of Senior Stock may by vote of the Board of Directors be called for redemption at any time at the redemption price provided for the particular series and in the manner hereinbelow provided. Subject to the provisions of subsection B of this Section 3, all or any part of any series of Senior Stock may be called for redemption without calling all or any part of any other series of Senior Stock. If less than all of any series of Senior Stock is so called, the Transfer Agent shall determine by lot or in some other manner approved by the Board of Directors the shares of such series of Senior Stock to be called. B. No call for redemption of less than all shares of Senior Stock outstanding shall be made if the Company shall be in arrears in respect of payment of dividends on any shares of Senior Stock outstanding. C. The sums payable in respect of any shares of Senior Stock so called shall be payable at the office of an incorporated bank or trust company in good standing. Notice of such call stating the redemption date shall be mailed not less than 30 days before the redemption date to each holder of record of shares of Senior Stock so called at his address as it appears upon the books of the Company. D. The Company shall, before the redemption date, deposit with said bank or trust company all sums payable with respect to shares of Senior Stock so called. After such mailing and deposit the holders of shares of Senior Stock so called for redemption shall cease to have any right to future dividends or other rights or privileges as stockholders in respect of such shares and shall be entitled to look for payment on and after the redemption date only to the sums so deposited with said bank or trust company for their respective amounts. Shares so redeemed may be reissued but only subject to the limitations imposed upon the issue of Senior Stock. E. The Company may at any time purchase all or any of the then outstanding shares of Senior Stock of any class and series upon the best terms reasonably obtainable, but not exceeding the then current redemption price of such shares, except that no such purchase shall be made if the Company shall be in arrears in respect of payment of dividends on any shares of Senior Stock outstanding or if there shall exist an event of default as defined in Section 5 hereof. Section 4. Amounts Payable on Liquidation A. The holders of any series of Senior Stock shall receive upon any voluntary liquidation, dissolution or winding up of the Company the then current redemption price of the particular series and if such action is involuntary $100 per share in the case of the Preferred Stock and $25 per share in the case of the Class A Preferred Stock, plus in each case all dividends accrued and unpaid to the date of such payment, before any payment in liquidation is made on any junior stock. B. If the net assets of the Company available for distribution on liquidation to the holders of Senior Stock shall be insufficient to pay said amounts in full, then such net assets shall be distributed among the holders of Senior Stock, who shall receive a common percentage of the full respective preferential amounts. Section 5. Voting Powers A. Except as provided in these Articles of Organization or in the Company's By-laws or as provided by law, the holders of Senior Stock shall have no voting power or right to notice of any meeting. B. Whenever the holders of the Senior Stock shall have the right to vote or consent to an action as provided in these Articles of Organization or the Company's By-laws or as provided by law, both classes of Senior Stock shall (except as provided below) vote together as a single class, each outstanding share of Preferred Stock entitled to vote and each outstanding share of Class A Preferred Stock entitled to vote having such voting rights as are proportionate to the ratio of (i) the par value represented by such share to (ii) the par value represented by all shares of Senior Stock then outstanding. Whenever only one class of the Senior Stock shall have the right to vote or consent to an action as provided in these Articles of Organization or the Company's By-laws or as provided by law, or whenever each class of the Senior Stock shall be entitled or be required to vote as a separate class on a matter, each outstanding share of such class entitled to vote shall be entitled to one vote on each such matter. C. Whenever dividends on any share of Senior Stock shall be in arrears in an amount equal to or exceeding four quarterly dividend payments, or whenever there shall have occurred some default in the observance of any of the provisions of this Article, or some default on which action has been taken by debentureholders, bondholders or the trustee of any deed of trust or mortgage of the Company, or whenever the Company shall have been declared bankrupt or a receiver of its property shall have been appointed (any of said conditions being herein called an "event of default"), then the holders of Senior Stock shall be given notice of all stockholders' meetings and shall have the right voting together as a class to elect the smallest number of directors necessary to constitute a majority of the Board of Directors of the Company and the exclusive right voting together as a class to amend the by-laws to make such appropriate increase in the number of directorships as may be required to effect such election. When all arrears of dividends shall have been paid and such event of default shall have been terminated, all the rights and powers of the holders of Senior Stock to receive notice and to vote shall cease, subject to being again revived on any subsequent event of default. D. Whenever the right to elect directors shall have accrued to the holders of Senior Stock the Company shall call a meeting of stockholders for the election of directors and, if necessary, the amendment of the by-laws to permit the holders of Senior Stock to exercise their rights pursuant to subsection C of this Section 5, such meeting to be held not less than 45 days and not more than 90 days after the accrual of such rights. When such rights shall cease, the Company shall, within seven days from the delivery to the Company of a written request therefor by any stockholder, cause a meeting of the stockholders to be held within 30 days from the delivery of such request for the purpose of electing a new Board of Directors. Forthwith, upon the election of such new Board of Directors, the directors in office immediately prior to such election (other than persons elected directors in such election) shall be deemed removed from office without further action by the Company. Section 6. Action Requiring Certain Consent of Senior Stockholders A. So long as any Senior Stock is outstanding, the Company, without the affirmative vote or written consent of at least a majority in interest of the Senior Stock then outstanding voting or giving consent together as a class shall not: (1) Issue or assume any unsecured notes, unsecured debentures or other securities representing unsecured debt (other than for the purpose of refunding or renewing outstanding unsecured securities issued or assumed by the Company resulting in equal or longer maturities or redeeming or otherwise retiring all outstanding shares of Senior Stock) if immediately after such issue or assumption (a) the total outstanding principal amount of all unsecured notes, unsecured debentures or other securities representing unsecured debt of the Company will thereby exceed 20% of the aggregate of all outstanding secured debt of the Company and the capital stock, premiums thereon, and surplus of the Company, as stated on its books, or (b) the total outstanding principal amount of all unsecured debt of the Company of maturities of less than 10 years will thereby exceed 10% of the aggregate of all outstanding secured debt of the Company and the capital stock, premiums thereon, and surplus of the Company, as stated on its books. For the purposes of this subsection A, the payment due upon the maturity of unsecured debt having an original single stated maturity of 10 years or more shall not be regarded as unsecured debt with a maturity of less than 10 years until within three years of the maturity thereof, and none of the payments due upon any unsecured serial debt having an original stated maturity for the final serial payment of 10 years or more shall be regarded as unsecured debt of a maturity of less than 10 years until within three years of the maturity of the final serial payment. (2) Issue, sell or otherwise dispose of any shares of the then authorized but unissued Senior Stock or any other stock ranking on a parity with or having a priority over Senior Stock in respect of dividends or of payments in liquidation, or reissue, sell or otherwise dispose of any reacquired shares of Senior Stock or such other stock, other than to refinance an equal par value or stated value of Senior Stock or of stock ranking on a parity with or having priority over Senior Stock in respect of dividends or of payments in liquidation, if: (a) For a period of 12 consecutive calendar months within 15 calendar months immediately preceding the calendar month in which any such shares shall be issued, the Income before Interest Charges of the Company for said period available for the payment of interest determined in accordance with the systems of accounts then prescribed for the Company by the Department of Public Utilities of the Commonwealth of Massachusetts (or by such other official body as may then have authority to prescribe such systems of accounts) but in any event after deducting depreciation charges and taxes (including income taxes) and including, in any case in which such stock is to be issued, sold or otherwise disposed of in connection with the acquisition of any property, the Income before Interest Charges of the property to be so acquired, computed as nearly as practicable in the manner specified above, shall not have been at least one and one-half (1 1/2) times the sum of (i) the interest charges for one year on all indebtedness which shall then be outstanding (excluding interest charges on any indebtedness, proposed to be retired in connection with the issue, sale or other disposition of such shares), and (ii) an amount equal to all annual dividend requirements on all outstanding shares of Senior Stock and all other stock, if any, ranking on a parity with or having priority over Senior Stock in respect of dividends or of payments in liquidation, including the shares proposed to be issued, but not including any shares proposed to be retired in connection with such issue, sale or other disposition; or if (b) Such issue, sale or disposition would bring the aggregate of the amount payable in connection with an involuntary liquidation of the Company with respect to all shares of Senior Stock and all shares of stock, if any, ranking on a parity with or having priority over Senior Stock in respect of dividends or of payments in liquidation to an amount in excess of the sum of the junior stock equity. If for the purposes of meeting the requirements of this clause (b), it shall have been necessary to take into consideration any earned surplus of the Company, the Company shall not thereafter pay any dividends on or make any distributions in respect of, or make any payment for the purchase or other acquisition of, junior stock which would result in reducing the junior stock equity to an amount less than the amount payable on involuntary liquidation of the Company in respect of Senior Stock and all shares ranking on a parity with or having a priority over Senior Stock in respect of dividends or of payments in liquidation at the time outstanding. If during the period for which Income before Interest Charges is to be determined for the purpose set forth in this paragraph (2), the amount, if any, required to be expended by the Company during such period for property additions pursuant to a renewal and replacement fund or similar fund established under any indenture of mortgage or deed of trust of the Company shall exceed the amount deducted during such period in the determination of such Income before Interest Charges on account of depreciation and amortization of electric plan acquisition adjustments, such excess shall also be deducted in determining such Income before Interest Charges. B. So long as any Senior Stock is outstanding, the Company, without the affirmative vote or written consent of at least two-thirds in interest of the Senior Stock then outstanding voting or giving consent together as a class shall not authorize any shares of any class of stock having a priority over the Senior Stock in respect of dividends or of payments in liquidation or issue any shares of any such prior ranking stock more than 12 months after the date of the vote or consent authorizing such prior ranking stock. C. The provisions of this Article of these Articles of Organization may be changed only by the affirmative vote or written consent of at least two-thirds in interest of the issued and outstanding shares of each class of capital stock of the Company voting or giving their consent in each case separately as a class; provided, however, that if any such change or proposed change would affect only one class of Senior Stock, then such change may be effected only by the affirmative vote or written consent of at least two-thirds in interest of the issued and outstanding shares of Common Stock and at least two-thirds in interest of the issued and outstanding shares of the class of Senior Stock that is affected, voting or giving their consent in each case separately as a class; and provided further, however, the holders of Senior Stock shall not be entitled to vote on an increase in the number of authorized shares of Preferred Stock or Class A Preferred Stock. In no event shall any reduction of the dividend rate or of the amounts payable upon redemption or liquidation with respect to any share of Senior Stock be made without the consent of the holder thereof, and no such reduction in respect of the shares of any particular series of Senior Stock shall be made without the consent of all the holders of shares of such series. D. No share of Senior Stock shall be deemed to be "outstanding" within the meaning of this Section 6 or of Section 7 if, at or prior to the time when the approval herein or therein referred to would otherwise be required, provision shall be made for its redemption, including a deposit complying with the requirements of subsection D of Section 3. Section 7. Merger, Consolidation or Sale of All Assets Except with the affirmative vote or written consent of a majority in interest of Senior Stock then outstanding voting or giving consent together as a class, the Company shall not merge or consolidate with or into any other corporation or sell or otherwise dispose of all or substantially all of its assets (except by mortgage or pledge) unless such merger, consolidation, sale or other disposition, or the issuance or assumption of securities in the effectuation thereof shall have been ordered, approved or permitted under the Public Utility Holding Company Act of 1935. Section 8. No Preemptive Right Except as otherwise expressly provided by law, the holders of Senior Stock shall have no preemptive right to subscribe to any further issue of additional shares of Senior Stock or of any other class of stock now or hereafter authorized, nor for any future issue of bonds, debentures, notes or other evidence of indebtedness or other security convertible into stock. If it is expressly required by law that, notwithstanding the provisions of the preceding sentence, any such further or future issue be offered proportionately to the stockholders, the holders of Preferred Stock only shall be entitled to subscribe for new or additional Preferred Stock, the holders of Class A Preferred Stock only shall be entitled to subscribe for new or additional Class A Preferred Stock and the holders of Common Stock only shall be entitled to subscribe for new or additional Common Stock; and notice of such increase as required by law need be given and the new shares need be offered proportionately only to the stockholders who are so entitled to subscribe. Section 9. Immunity of Directors, Officers and Agents No director, officer or agent of the Company shall be held personally responsible for any action taken in good faith though subsequently adjudged to be in violation of this Article. Section 10. Transfer Agent The Company shall always have at least one transfer agent for Senior Stock, which shall be an incorporated bank or trust company of good standing. PART TWO PROVISIONS WITH RESPECT TO THE SERIES OF PREFERRED STOCK 1. 7.72% Preferred Stock, Series B ------------------------------- There shall be a series of Preferred Stock designated "7.72% Preferred Stock, Series B," and consisting of 200,000 shares with an aggregate par value of $20,000,000 and a par value per share of $100. The dividend rate and redemption prices as to said 7.72% Preferred Stock, Series B, shall be as follows: (a) Dividends on said 7.72% Preferred Stock, Series B, shall be at the rate of 7.72% per share per annum, and no more, and shall be cumulative from October 1, 1971. Said dividends, when declared, shall be payable on the first days of January, April, July and October in each year. (b) Redemption Prices of said 7.72% Preferred Stock, Series B, shall be $109.30 per share if redeemed on or before October 1, 1976, $107.37 per share if redeemed after October 1, 1976 and on or before October 1, 1981, $105.44 per share if redeemed after October 1, 1981 and on or before October 1, 1986, and $103.51 per share if redeemed after October 1, 1986, plus in all cases that portion of the quarterly dividend accrued thereon to the redemption date and all unpaid dividends thereon, if any, provided, however, that none of the 7.72% Preferred Stock, Series B shall be redeemed prior to October 1, 1976, if such redemption is for the purpose of or in anticipation of refunding such 7.72% Preferred Stock, Series B through the use, directly or indirectly, of finds borrowed by the Company or of the proceeds of the issue by the Company of shares of any stock ranking prior to or on a parity with the 7.72% Preferred Stock, Series B as to dividends or assets, if such borrowed funds or such shares have an effective interest cost or effective dividend cost to the Company (computed in accordance with generally accepted financial principles), as the case may be, of less than 7.69% per annum. 4. Adjustable Rate Preferred Stock, Series D There shall be a series of Preferred Stock designated "Adjustable Rate Preferred Stock, Series D", and consisting of 350,000 shares with an aggregate par value of $35,000,000 and a par value per share of $100. The dividend rate provisions, redemption prices and sinking fund provisions as to said Adjustable Rate Preferred Stock, Series D, shall be as follows: (a)The dividend per share on said Adjustable Rate Preferred Stock, Series D, shall be (1) at the rate of 12% per annum per share for the Initial Dividend Payment Period (as herein defined) (2) at the rate of forty-one hundredth (40/100th) of one percentage point above the Applicable Rate (as herein defined), from time to time in effect, for each subsequent quarterly Dividend Period (as herein defined); provided, however, the dividend rate for any Dividend Period (including the Initial Dividend Payment Period) shall not be at a rate of less than 8% per annum per share or greater than 13% per annum per share. Dividends shall be cumulative from the date of issuance. Except as provided below in this paragraph, the "Applicable Rate" for any Dividend Period shall be the highest of (i) the Treasury Bill Rate, (ii) the Ten Year Constant Maturity Rate and (iii) the Twenty Year Constant Maturity Rate (each as hereinafter defined) for such Dividend Period. If the Company determines in good faith that for any reason one or more of such rates cannot be determined for a particular Dividend Period, then the Applicable Rate for such Dividend Period shall be the higher of whichever of such rates can be so determined. If the Company determines in good faith that none of such rates can be determined for a particular Dividend Period, then the Applicable Rate in effect for the preceding Dividend Period shall be continued for such Dividend Period. Except as provided below in this paragraph, the "Treasury Bill Rate" for each Dividend Period shall be the arithmetic average of the two most recent weekly per annum market discount rates (or the one weekly per annum market discount rate, if only one such rate shall be published during the relevant Calendar Period (as defined below)) for three-month U.S. Treasury bills, as published weekly by the Federal Reserve Board or its successor agency during the Calendar Period immediately prior to the ten calendar days immediately preceding the Dividend Payment Date for the dividend period immediately prior to the Dividend Period for which the dividend rate on the Adjustable Rate Preferred Stock, Series D is being determined. If the Federal Reserve Board or its successor agency does not publish such a weekly per annum market discount rate during such Calendar Period, then the Treasury Bill Rate for such Dividend Period shall be the arithmetic average of the two most recent weekly per annum market discount rates (or the one weekly per annum market discount rate, if one such rate shall be published during the relevant Calendar Period) for three-month U.S. Treasury bills, as published weekly during such Calendar Period by any Federal Reserve Bank or by any U.S. Government department or agency selected by the Company. If a per annum market discount rate for three-month U.S. Treasury bills shall not be published by the Federal Reserve Board or its successor agency or by any Federal Reserve Bank or by any U.S. Government department or agency during such Calendar Period, then the Treasury Bill Rate for such Dividend Period shall be the arithmetic average of the two most recent weekly per annum market discount rates (or the one weekly per annum market discount rate, if one such rate shall be published during the relevant Calendar Period) for all of the U.S. Treasury bills then having maturities of not less than 80 nor more than 100 days, as published during such Calendar Period by the Federal Reserve Board or its successor agency or, if the Federal Reserve Board or its successor agency shall not publish such rates, by any Federal Reserve Bank or by any U.S. Government department or agency selected by the Company. If the Company determines in good faith that for any reason no such U.S. Treasury bill rates are published as provided above during such Calendar Period, then the Treasury Bill Rate for such Dividend Period shall be the arithmetic average of the per annum market discount rates based upon the closing bids during such Calendar Period for each of the issues of marketable non-interest bearing U.S. Treasury securities with a maturity of not less than 80 nor more than 100 days from the date of each such quotation, as quoted daily for each business day in New York City (or less frequently if daily quotations shall not be generally available) to the Company by at least three recognized U.S. Government securities dealers selected by the Company. If the Company determines in good faith that for any reason the Company cannot determine the Treasury Bill Rate for any Dividend Period as provided above in this paragraph, the Treasury Bill Rate for such Dividend Period shall be the arithmetic average of the per annum market discount rates based upon the closing bids during the related Calendar Period for each of the issues of marketable interest-bearing U.S. Treasury securities with a maturity of not less than 80 nor more than 100 days from the date of each such quotation, as quoted daily for each business day in New York City (or less frequently if daily quotations shall not be generally available) to the Company by at least three recognized U.S. Government securities dealers selected by the Company. Except as provided below in this paragraph, the "Ten Year Constant Maturity Rate" for each Dividend Period shall be the arithmetic average of the two most recent weekly per annum Ten Year Average Yields (or the one weekly per annum Ten Year Average Yield, if only one such Yield shall be published during the relevant Calendar Period as provided below), as published weekly by the Federal Reserve Board or its successor agency during the Calendar Period immediately prior to the ten calendar days immediately preceding the Dividend Payment Date prior to the Dividend Period for which the dividend rate on the Adjustable Rate Preferred Stock, Series D is being determined. If the Federal Reserve Board or its successor agency does not publish such a weekly per annum Ten Year Average Yield during such Calendar Period, then the Ten Year Constant Maturity Rate for such Dividend Period shall be the arithmetic average of the two most recent weekly per annum Ten Year Average Yields (or the one weekly per annum Ten Year Average Yield, if only one such Yield shall be published during such Calendar Period), as published weekly during such Calendar Period by any Federal Reserve Bank or by any U.S. Government department or agency selected by the Company. If a per annum Ten Year Average Yield shall not be published by the Federal Reserve Board or its successor agency or by any Federal Reserve Bank or by any U.S. Government department or agency during such Calendar Period, then the Ten Year Constant Maturity Rate for such Dividend Period shall be the arithmetic average of the two most recent weekly per annum average yields to maturity (or the one weekly average yield to maturity, if only one such yield shall be published during such Calendar Period) for all of the actively traded marketable U.S. Treasury fixed interest rate securities (other than Special Securities (as defined below)) then having maturities of not less than eight nor more than twelve years, as published during such Calendar Period by the Federal Reserve Board or its successor agency or, if the Federal Reserve Board or its successor agency shall not publish such yields, by any Federal Reserve Bank or by any U.S. Government department or agency selected by the Company. If the Company determines in good faith that for any reason the Company cannot determine the Ten Year Constant Maturity Rate for any Dividend Period as provided above in this paragraph, then the Ten Year Constant Maturity Rate for such Dividend Period shall be the arithmetic average of the per annum average yields to maturity based upon the closing bids during such Calendar Period for each of the issues of actively traded marketable U.S. Treasury fixed interest rate securities (other than Special Securities) with a final maturity date not less than eight nor more than twelve years from the date of each such quotation, as quoted daily for each business day in New York City (or less frequently if daily quotations shall not be generally available) to the Company by at least three recognized U.S. Government securities dealers selected by the Company. Except as provided below in this paragraph, the "Twenty Year Constant Maturity Rate" for each Dividend Period shall be the arithmetic average of the two most recent weekly per annum Twenty Year Average Yields (or the one weekly per annum Twenty Year Average Yield, if only one such Yield shall be published during the relevant Calendar Period), as published weekly by the Federal Reserve Board or its successor agency during the Calendar Period immediately prior to the ten calendar days immediately preceding the Dividend Payment Date prior to the Dividend Period for which the dividend rate on the Adjustable Rate Preferred Stock, Series D is being determined. If the Federal Reserve Board or its successor agency does not publish such a weekly per annum Twenty Year Average Yield during such Calendar Period, then the Twenty Year Constant Maturity Rate for such Dividend Period shall be the arithmetic average of the two most recent weekly per annum Twenty Year Average Yields (or the one weekly per annum Twenty Year Average Yield, if only one such Yield shall be published during such Calendar Period), as published weekly during such Calendar Period by any Federal Reserve Bank or by any U.S. Government department or agency selected by the Company. If a per annum Twenty Year Average Yield shall not be published by the Federal Reserve Board or its successor agency or by any Federal Reserve Bank or by any U.S. Government department or agency during such Calendar Period, then the Twenty Year Constant Maturity Rate for such Dividend Period shall be the arithmetic average of the two most recent weekly per annum average yields to maturity (or the one weekly average yield to maturity, if only one such yield shall be published during such Calendar Period) for all of the actively traded marketable U.S. Treasury fixed interest rate securities (other than Special Securities) then having maturities of not less than eighteen nor more than twenty-two years, as published during such Calendar Period by the Federal Reserve Board or its successor agency or, if the Federal Reserve Board or its successor agency shall not publish such yields, by any Federal Reserve Bank or by any U.S. Government department or agency selected by the Company. If the Company determines in good faith that for any reason the Company cannot determine the Twenty Year Constant Maturity Rate for any Dividend Period as provided above in this paragraph, then the Twenty Year Constant Maturity Rate for such Dividend Period shall be the arithmetic average of the per annum average yields to maturity based upon the closing bids during such Calendar Period for each of the issues of actively traded marketable U.S. Treasury fixed interest rate securities (other than Special Securities) with a final maturity date not less than eighteen nor more than twenty-two years from the date of each such quotation, as quoted daily for each business day in New York City (or less frequently if daily quotations shall not be generally available) to the Company by at least three recognized U.S. Government securities dealers selected by the Company. The Treasury Bill Rate, the Ten Year Constant Maturity Rate and the Twenty Year Constant Maturity Rate shall each be rounded to the nearest five one-hundredths of a percentage point. The "Initial Dividend Payment Period" shall be that period beginning on April 19, 1983 (the date of issuance) and continuing through and including June 30, 1983. The initial dividend payment date shall be July 1, 1983. A "Dividend Period" shall mean the three month period beginning April 1, July 1, October 1, and January 1 in each year. A "Dividend Payment Date" shall mean the first day of April, July, October, and January in each year, commencing October 1, 1983. The amount of dividends per share payable for each Dividend Period shall be computed by dividing the dividend rate for such Dividend Period by four and applying such rate against the par value per share of the Adjustable Rate Preferred Stock, Series D. The amount of dividends payable for the Initial Dividend Period or any period shorter than a full quarterly Dividend Period shall be computed on the basis of 30-day months, a 360-day year and the actual number of days elapsed in such period. The dividend rate with respect to each Dividend Period will be calculated as promptly as practicable by the Company according to the appropriate method described herein. The mathematical accuracy of each such calculation will be confirmed in writing by independent accountants of recognized standing. The Company will cause each dividend rate to be published in a newspaper of general circulation in New York City prior to the commencement of the new Dividend Period to which it applies and will cause notice of such dividend rate to be enclosed with the dividend payment checks next mailed to the holders of the Adjustable Rate Preferred Stock, Series D. As used herein, the term "Calendar Period" means a period of fourteen calendar days; the term "Special Securities" means securities which can, at the option of the holder, be surrendered at face value in payment of any Federal estate tax or which provide tax benefits to the holder and are priced to reflect such tax benefits or which were originally issued at a deep or substantial discount; the term "Ten Year Average Yield" means the average yield to maturity for actively traded marketable U.S. Treasury fixed interest rate securities (adjusted to constant maturities of ten years); and the term "Twenty Year Average Yield" means the average yield to maturity for actively traded marketable U.S. Treasury fixed interest rate securities (adjusted to constant maturities of twenty years). (b)The redemption prices of the Adjustable Rate Preferred Stock, Series D, shall be $112.00 per share if redeemed on or before April 1, 1988, $103.00 per share if redeemed after April 1, 1988 but on or before April 1, 1993, or $100.00 per share if redeemed after April 1, 1993. In each case the redemption price will also include accrued dividends to the date of redemption. None of the Adjustable Rate Preferred Stock, Series D shall be redeemed prior to April 1, 1988 if such redemption is for the purpose of or in anticipation of refunding the Adjustable Rate Preferred Stock, Series D through the use, directly or indirectly, of borrowed funds or of the proceeds of the issue by the Company of shares of any stock ranking prior to or on a parity with the Adjustable Rate Preferred Stock, Series D as to dividends or assets, if such borrowed funds or such shares have an effective interest cost or effective dividend cost (computed in accordance with generally accepted financial principles), as the case may be, of less than 12.36 % per annum per share. (c) As and for a sinking fund for the Adjustable Rate Preferred Stock, Series D, commencing on April 1, 1988 and on or before each April 1 in each year thereafter so long as any shares of the Adjustable Rate Preferred Stock, Series D remain outstanding, the Company shall, to the extent of any funds of the Company legally available therefor and except as otherwise restricted by the Company's Statement of Preferred Stock Provisions, redeem 17,500 shares of Adjustable Rate Preferred Stock, Series D (or such lesser number of such shares as remain outstanding) at $100 per share plus accrued dividends to the date of redemption; provided, however, that if in any year the Company does not redeem the full number of shares of Adjustable Rate Preferred Stock, Series D required to be redeemed pursuant to this sinking fund, the deficiency shall be made good on the next April 1 on which the Company has funds legally available for, and is otherwise permitted to effect, the redemption of shares of Adjustable Rate Preferred Stock, Series D, pursuant to this sinking fund. The number of shares of Adjustable Rate Preferred Stock, Series D, redeemed on any April 1 shall be reduced by the number of such shares purchased and cancelled by the Company during the preceding twelve-month period or redeemed during such period pursuant to subsection (b) hereof. Any shares so redeemed or purchased or cancelled may be given the status of authorized but unissued shares of Preferred Stock, but none of such shares shall be reissued as shares of Adjustable Rate Preferred Stock, Series D. The Company shall have the option, which shall be noncumulative, to redeem on April 1, 1988 and on each April 1 thereafter up to an additional 17,500 shares of Adjustable Rate Preferred Stock, Series D, at the sinking fund redemption price. No such optional sinking fund shall operate to reduce the number of shares of the Adjustable Rate Preferred Stock, Series D, required to be redeemed pursuant to the mandatory sinking fund provisions hereinabove set forth. In the event that the Company shall at any time fail to make a full mandatory sinking fund payment on any sinking fund payment date, the Company shall not pay any dividends or make any other distributions in respect of outstanding shares of any junior stock (as that term is defined in Subsection A of Section of Article XVI of the by-laws of the Company) of the Company, other than dividends or distributions in shares of junior stock, or purchase or otherwise acquire for value any outstanding shares of junior stock, until all such payments have been made. 2. 7.60% Class A Preferred Stock, 1987 Series ------------------------------------------ There shall be a series of Preferred Stock designated "7.60% Class A Preferred Stock, 1987 Series," and consisting of 1,200,000 shares with an aggregate par value of $30,000,000 and a par value per share of $25. The dividend rate and redemption prices as to said 7.60% Class A Preferred Stock, 1987 Series, shall be as follows: (a) Dividends on said 7.60% Class A Preferred Stock, 1987 Series, shall be at the rate of 7.60% per share per annum, and no more, and shall be cumulative from the date of issuance. Said dividends, when declared, shall be payable on the first days of February, May, August and November in each year, commencing May 1, 1987. (b) For each of the twelve month periods commencing February 1, 1987, the redemption prices of said 7.60% Class A Preferred Stock, 1987 Series, shall be the amount per share set forth below: Twelve Twelve Months Redemption Months Redemption Beginning Price Beginning Price February 1 Per Share February 1 Per Share 1987 $26.90 2000 $25.26 1988 26.90 2001 25.13 1989 26.90 2002 25.00 1990 26.90 2003 25.00 1991 26.90 2004 25.00 1992 26.27 2005 25.00 1993 26.14 2006 25.00 1994 26.02 2007 25.00 1995 25.89 2008 25.00 1996 25.76 2009 25.00 1997 25.64 2010 25.00 1998 25.51 2011 25.00 1999 25.38 plus in all cases that portion of the quarterly dividend accrued thereon to the redemption date and all unpaid dividends thereon, if any; provided, however, that none of the 7.60% Class A Preferred Stock, 1987 Series, shall be redeemed prior to February 1, 1992, if such redemption is for the purpose of or in anticipation of refunding such 7.60% Class A Preferred Stock, 1987 Series, through the use, directly or indirectly, of funds borrowed by the Company or of the proceeds of the issue by the Company of shares of any stock ranking prior to or on a parity with the 7.60% Class A Preferred Stock, 1987 Series, as to dividends or assets, if such borrowed funds or such shares have an effective interest cost or effective dividend cost to the Company (computed in accordance with generally accepted financial principles), as the case may be, of less than 7.69% per annum. (c) As and for a sinking fund for said 7.60% Class A Preferred Stock, 1987 Series, commencing on February 1, 1992, and on each February 1 in each year thereafter so long as any shares of the 7.60% Class A Preferred Stock, 1987 Series, remain outstanding, the Company shall, to the extent of any funds of the Company legally available therefor and except as otherwise restricted by the Company's Statement of Preferred Stock Provisions, redeem 60,000 shares of 7.60% Class A Preferred Stock, 1987 Series (or such lesser number of such shares as remain outstanding) at $25 per share plus accrued dividends to the date of redemption; provided, however, that if in any year the Company does not redeem the full number of shares of 7.60% Class A Preferred Stock, 1987 Series, required to be redeemed pursuant to this sinking fund, the deficiency shall be made good on the next succeeding February 1 on which the Company has funds legally available for, and is otherwise permitted to effect, the redemption of shares of 7.60% Class A Preferred Stock, 1987 Series, pursuant to this sinking fund. At the option of the Company, the number of shares of 7.60% Class A Preferred Stock, 1987 Series, redeemed on any February 1 may be reduced by the number of such shares purchased and canceled by the Company during the preceding twelve-month period or redeemed during such period pursuant to subsection (b) hereof. Any shares so redeemed or purchased and canceled may be given the status of authorized but unissued shares of Senior Stock, but none of such shares shall be reissued as shares of 7.60% Class A Preferred Stock, 1987 Series. The Company shall have the option, which shall be noncumulative, to redeem on February 1, 1992 and on each February 1 thereafter up to an additional 60,000 shares of 7.60% Class A Preferred Stock, 1987 Series, at the sinking fund redemption price. No such optional sinking fund shall operate to reduce the number of shares of the 7.60% Class A Preferred Stock, 1987 Series, required to be redeemed pursuant to the mandatory sinking fund provisions hereinabove set forth. In the event that the Company shall at any time fail to make a full mandatory sinking fund payment on any sinking fund payment date, the Company shall not pay any dividends or make any other distributions in respect of outstanding shares of any junior stock (as that term is defined in this Article and the By-laws of the Company)of the Company, other than dividends or distributions in shares of junior stock, or purchase or otherwise acquire for value any outstanding shares of junior stock, until all such payments have been made. 3. Dutch Auction Rate Transferable Securities Class A Preferred ------------------------------------------------------------ Stock, 1988 Series ------------------ There shall be a series of Class A Preferred Stock designated "Dutch Auction Rate Transferable Securities Class A Preferred Stock, 1988 Series" (the "1988 DARTS") consisting of 2,140,000 shares with an aggregate par value of $53,500,000 and a par value per share of $25. The provisions governing the issue and sale of the 1988 DARTS in Units, certification, dividend rights, redemption, reacquisition, auction procedures, and other preferences, qualifications and special or relative rights or privileges with respect to the 1988 DARTS shall be as follows: (1) Units The 1988 DARTS shall be issued and sold by the Company only in units of 4,000 shares per unit ("Units"). No partial Units shall be issued and sold by the Company, and no fractional shares of the 1988 DARTS shall be issued and sold, no transfer of the 1988 DARTS in less than whole Units shall be made, nor shall any transfer in less than whole Units be registered on the transfer books of the Company or be effective for any purpose. (2) Certification Except as otherwise provided by law, all outstanding DARTS shall be represented by a certificate or certificates registered in the name of a nominee of the Securities Depository (as defined in Section (6)(a)(xxi) below), and no person acquiring Units shall be entitled to receive a certificate representing the 1988 DARTS. The nominee of the Securities Depository shall be the sole holder of record of the 1988 DARTS. Each purchaser of Units will receive dividends, distributions and notices according to the procedures of the Securities Depository and, if such purchaser is not a member of the Securities Depository, of such purchaser's Agent Member (as defined in Section (6)(a)(ii) below). (3) Dividend Rights (a) Dividends on the 1988 DARTS shall be paid, when, as and if declared by the Board of Directors of the Company out of funds legally available therefor, at the rate per annum determined as set forth below in subsection (c) of this Section (3) and no more (the "Applicable Rate"), payable on the respective dates set forth below. (b) Dividends on the 1988 DARTS shall accrue from the date of original issuance and shall be payable commencing on May 3, 1988, and on each succeeding seventh Tuesday thereafter, except that if any of such Tuesday, the Monday preceding such Tuesday, or the Wednesday following such Tuesday is not a Business Day (as defined below), then (i) the dividend payment date shall be the first Business Day after such Tuesday that is immediately followed by a Business Day and is preceded by a Business Day that is the preceding Monday or a day after such Monday, or (ii) if the Securities Depository shall make available to its participants and members, in funds immediately available in New York City on dividend payment dates, the amount due as dividends on such dividend payment dates (and the Securities Depository shall have so advised the Trust Company (as defined in Section (6)(a)(xxx) below)), then the dividend payment date shall be the first Business Day on or after such Tuesday that is preceded by a Business Day that is the preceding Monday or a day after such Monday. "Business Day" means a day on which the New York Stock Exchange is open for trading and which is not a day on which banks in New York City are authorized by law to close. Each dividend payment date determined as provided above is referred to herein as the "Dividend Payment Date." Although any particular Dividend Payment Date may not occur on the originally scheduled Tuesday because of the exceptions discussed above, the next succeeding Dividend Payment Date shall be, subject to such exceptions, the seventh Tuesday following the originally designated Tuesday Dividend Payment Date for the prior Dividend Period. As used herein, Dividend Period means the period commencing on a Dividend Payment Date for DARTS and ending on the day next preceding the next Dividend Payment Date. Notwithstanding the foregoing, in the event of a change in law altering the minimum holding period (currently found in Section 246(c) of the Internal Revenue Code of 1986, as amended (the "Code")) required for taxpayers to be entitled to the dividends received deduction on preferred stock held by non-affiliated corporations (currently found in Section 243(a) of the Code), the Company shall adjust the period of time between Dividend Payment Dates so as to adjust uniformly the number of days (such number of days without giving effect to the exceptions referred to above being hereinafter referred to as "Dividend Period Days") in Dividend Periods commencing after the date of such change in law to equal or exceed the then current minimum holding period; provided that the number of Dividend Period Days shall not exceed by more than nine days the length of such then current minimum holding period and shall be evenly divisible by seven, and the maximum number of Dividend Period Days in no event shall exceed 98 days. Upon any such change in the number of Dividend Period Days as a result of a change in law, the Company shall give notice of such change to all Existing Holders of Units. (c) The dividend rate on shares of the 1988 DARTS during the period from and after the date of original issuance to the Initial Dividend Payment Date (the "Initial Dividend Period") shall be 6.375 percent per annum. Commencing on the Initial Dividend Payment Date, the dividend rate on shares of the 1988 DARTS for each subsequent Dividend Period shall be at a rate per annum that results from the implementation of the Auction procedures set forth in Section (6) below. The amount of dividends per Unit for the 1988 DARTS payable for each Dividend Period shall be computed by multiplying the dividend rate for such series for each Dividend Period determined in accordance with subsection (c) above by a fraction the numerator of which shall be the number of days in such Dividend Period (calculated by counting the first day thereof but excluding the last day thereof) such Unit was outstanding and the denominator of which shall be 360, and multiplying the amount so obtained by $100,000 per Unit. (d) Prior to each Dividend Payment Date, the Company shall pay to the Trust Company sufficient funds for the payment of declared dividends. (e) For the purpose of determining whether and when holders of the Senior Stock are entitled to the rights to elect certain directors of the Company, described under Section 5C of this Article and the Company's By-laws, dividends on the DARTS shall be deemed to be in arrears "in an amount equal to or exceeding four quarterly dividend payments," if, at the time dividends are in arrears for four quarterly dividend payments for Senior Stock having quarterly dividend payments, dividends on the 1988 DARTS are in arrears for each Dividend Period beginning on or after the first day of the first of the four quarterly dividend periods as to which dividends on the Senior Stock having quarterly dividends are in arrears. (4) Redemption Provisions (a) At the option of the Company, the Units may be redeemed out of funds legally available therefor in whole on any Dividend Payment Date at a redemption price of $25 per share of the 1988 DARTS ($100,000 per Unit) plus accrued and unpaid dividends (whether or not earned or declared) to the redemption date. Only whole Units may be redeemed. See Section (5) below for restrictions on the reissue of Units after redemption. (b) In accordance with Section 3 of this Article and the Company's By-laws, notice of redemption shall be mailed to each record holder of Units and to the Trust Company not less than 30 days prior to the date fixed for redemption thereof. Each notice of redemption shall include a statement setting forth: (i) the redemption date, (ii) the number of Units to be redeemed, (iii) the redemption price, (iv) the place or places where Units are to be surrendered for payment of the redemption price, and (v) that dividends of the Units to be redeemed will cease to accrue on such redemption date. No defect in the notice of redemption or in the mailing thereof shall affect the validity of the redemption proceedings, except as required by applicable law. (c) If less than all of the outstanding Units are to be redeemed, the number of Units to be redeemed shall be determined by the Company and communicated to the Trust Company. In accordance with section 3A of this Article and the Company's By-laws, the Trust Company shall give notice to the Securities Depository and the Securities Depository will determine by lot under its usual operating procedures the number of Units, if any, to be redeemed from the account of the Agent Member of each Existing Holder. An Agent Member may determine to redeem Units from some Existing Holders without redeeming Units from the accounts of other Existing Holders. (5) Reacquisition Except in an Auction (as defined in Section (6)(a)(iii) below), the Company shall have the right, in accordance with Section 3E of this Article and the Company's By-laws, and where permitted by applicable law, to purchase or otherwise acquire Units upon the best terms reasonably obtainable, but not exceeding the then current redemption price of such Units, except that no such purchase shall be made if the Company shall be in arrears in respect to payment of dividends on any shares of Senior Stock outstanding or if there shall exist an event of default as defined in Section 5 of this Article and the Company's By-laws. Notwithstanding the provisions of this Article and the Company's By-laws, Units that have been redeemed, purchased or otherwise acquired by the Company shall not be reissued as 1988 DARTS and shall either be restored to authorized but unissued shares of the Company's Class A Preferred Stock or canceled at the Company's option. (6) Auction Procedures (a) Certain Definitions As used in these provisions establishing and designating the Dutch Auction Rate Transferable Securities Class A Preferred Stock, 1988 Series, the following terms shall have the following meanings, unless the context otherwise requires: (i) "Affiliate" shall mean any Person known to the Trust Company to be controlled by, in control of, or under common control with the Company. (ii) "Agent Member" shall mean the member of the Securities Depository that will act on behalf of a Bidder and is identified as such in such Bidder's Purchaser's Letter. (iii) "Auction" shall mean the periodic operation of the procedures set forth herein. (iv) "Auction Date" shall mean the Business Day next preceding a Dividend Payment Date. (v) "Available Units" shall have the meaning specified in paragraph (d)(i)(A) below. (vi) "Bid" shall have the meaning specified in paragraph (b)(i) below. (vii) "Bidder" shall have the meaning specified in paragraph (b)(i) below. (viii) "Board of Directors" shall mean the Board of Directors of the Company. (ix) "Broker-Dealer" shall mean any broker-dealer, or other entity permitted by law to perform the functions required of a Broker-Dealer herein, that has been selected by the Company and has entered into a Broker-Dealer Agreement with the Trust Company that remains effective. (x) "Broker-Dealer Agreement" shall mean an agreement between the Trust Company and a Broker-Dealer pursuant to which such Broker-Dealer agrees to follow the procedures specified herein. (xi) "DARTS" or "1988 DARTS" shall mean the 2,140,000 shares of Dutch Auction Rate Transferable Securities Class A Preferred Stock, 1988 Series, $25 Par Value, of the Company. (xii) "Existing Holder," when used with respect to Units, shall mean a Person who has signed a Purchaser's Letter and is listed as the beneficial owner of such Units in the records of the Trust Company. (xiii) "Hold Order" shall have the meaning specified in paragraph (b)(i) below. (xiv) "Maximum Applicable Rate," on any Auction Date, shall mean the percentage of the 60-day "AA" Composite Commercial Paper Rate (as defined below) in effect on such Auction Date, determined as set forth below based on the prevailing rating of the DARTS in effect at the close of business on the day preceding such Auction Date: Prevailing Rating Percentage AA/aa or Above........................... 110% A/a...................................... 120% BBB/baa.................................. 130% BB/ba.................................... 175% Below BB/ba.............................. 200% For purposes of this definition, the "prevailing rating" of the DARTS shall be (i) AA/aa or Above, if the DARTS have a rating of AA- or better by Standard & Poor's Corporation or its successor ("S&P") and aa3 or better by Moody's Investors Service, Inc. or its successor ("Moody's"), or the equivalent of both of such ratings by such agencies or a substitute rating agency or substitute rating agencies selected as provided below, (ii) if not AA/aa or Above, then A/a, if the DARTS have a rating of A- or better by S&P and a3 or better by Moody's or the equivalent of both of such ratings by such agencies or a substitute rating agency or substitute rating agencies selected as provided below, (iii) if not AA/aa or Above or A/a, then BBB/Baa, if the DARTS have a rating of BBB- or better by S&P and baa3 or better by Moody's or the equivalent of both of such ratings by such agencies or a substitute rating agency or substitute rating agencies selected as provided below, and (iv) if not AA/aa or Above, A/a or BBB/baa, then BB/ba, if the DARTS have a rating of BB- or better by S&P and Ba3 or better by Moody's, or the equivalent of both of such ratings by such agencies or a substitute rating agency or substitute rating agencies selected as provided below, and (v) if not AA/aa or Above, A/a, BBB/baa or BB/ba, then Below BB/ba. The Company shall take all reasonable action necessary to enable S&P and Moody's to provide a rating for the DARTS. If either S&P or Moody's shall not make such a rating available, or neither S&P nor Moody's shall make such a rating available, Salomon Brothers Inc and Morgan Stanley & Co. Incorporated, or their successors shall select a nationally recognized securities rating agency or two nationally recognized securities rating agencies to act as substitute rating agency or substitute rating agencies, as the case may be. (xv) "Minimum Applicable Rate," on any Auction Date, shall mean 59% of the 60-day "AA" Composite Commercial Paper Rate in effect on such Auction Date. (xvi) "Order" shall have the meaning specified in paragraph(b)(i) below. (xvii) "Outstanding" shall mean, as of any date, the DARTS theretofore issued by the Company except, without duplication, (A) any DARTS theretofore canceled or delivered to the Trust Company for cancellation, or redeemed by the Company, or as to which a notice of redemption shall have been given by the Company, (B) any DARTS as to which the Company or any Affiliate thereof shall be an Existing Holder and (C) any DARTS represented by any certificate in lieu of which a new certificate has been executed and delivered by the Company. (xviii) "Person" shall mean and include an individual, a partnership, a corporation, a trust, an unincorporated association, a joint venture or other entity or a government or any agency or political subdivision thereof. (xix) "Potential Holder" shall mean any Person, including any Existing Holder, (A) who shall have executed and delivered or caused to be delivered a Purchaser's Letter to the Trust Company and (B) who may be interested in acquiring Units (or, in the case of an Existing Holder, additional Units). (xx) "Purchaser's Letter" shall mean a letter addressed to the Company, the Trust Company, Broker-Dealer and other persons in which a Person agrees, among other things, to offer to purchase, purchase, offer to sell and/or sell Units as set forth herein. (xxi) "Securities Depository" shall mean The Depository Trust Company and its successors and assigns or any other securities depository selected by the Company which agrees to follow the procedures required to be followed by such securities depository in connection with the DARTS. (xxii) "Sell Order" shall have the meaning specified in paragraph (b)(i) below. (xxiii) "60-day 'AA' Composite Commercial Paper Rate," on any date, means (i) the interest equivalent of the 60-day rate on commercial paper placed on behalf of issuers whose corporate bonds are rated "AA" by S&P or the equivalent of such rating by S&P or another rating agency, as such 60-day rate is made available on a discount basis or otherwise by the Federal Reserve Bank of New York for the Business Day immediately preceding such date, or (ii) in the event that the Federal Reserve Bank of New York does not make available such a rate, then the interest equivalent of the 60-day rate on commercial paper placed on behalf of such issuers, as quoted on a discount basis or otherwise by Morgan Stanley & Co. Incorporated or, in lieu thereof, any affiliates or successor thereof (the "Commercial Paper Dealer"), to the Trust Company for the close of business on the Business Day immediately preceding such date. If the Commercial Paper Dealer does not quote a rate required to determine the 60-day "AA" Composite Commercial Rate, the 60-day "AA" Composite Commercial Paper Rate shall be determined on the basis of the quotation or quotations furnished by any Substitute Commercial Paper Dealer or Substitute Commercial Paper Dealers selected by the Company to provide such rate. If the Company, however, shall adjust the number of Dividend Period Days in the event of a change in the dividends received deduction minimum holding period contained in the Internal Revenue Code of 1986, as amended, with the result that (i) the Dividend Period Days shall be fewer than 70 days, such rate shall be the interest equivalent of the 60-day rate on such commercial paper, (ii) the Dividend Period Days shall be 70 or more days but fewer than 85 days, such rate shall be the arithmetic average of the interest equivalent of the 60-day and 90-day rates on such commercial paper, and (iii) the Dividend Period Days shall be 85 or more days but 98 or fewer days, such rate shall be the interest equivalent of the 90-day rate on such commercial paper. For the purposes of such definition, "interest equivalent" means the equivalent yield on a 360-day basis of a discount basis security to an interest-bearing security and "Substitute Commercial Paper Dealer" shall mean any commercial paper dealer that is a leading dealer in the commercial paper market, provided that neither such dealer nor any of its affiliates is a Commercial Paper Dealer. (xxiv) "Submission Deadline" shall mean 12:30 P.M., New York City time, on any Auction Date or such other time on any Auction Date by which Broker-Dealers are required to submit Orders to the Trust Company as specified by the Trust Company from time to time. (xxv) "Submitted Bid" shall have the meaning specified in paragraph (d)(i) below. (xxvi) "Submitted Hold Order" shall have the meaning specified in paragraph (d)(i) below. (xxvii) "Submitted Order" shall have the meaning specified in paragraph (d)(i) below. (xxviii) "Submitted Sell Order" shall have the meaning specified in paragraph (d)(i) below. (xxvix) "Sufficient Clearing Bids" shall have the meaning specified in paragraph (d)(i) below. (xxx) "Trust Company" shall mean Bankers Trust Company and its successor, and assigns or any other bank, trust company or other entity selected by the Company which agrees to follow the Auction Procedures described in this Section (6) for the purposes of determining the Applicable Rate for the DARTS. (xxxi) "Winning Bid Rate" shall have the meaning specified in paragraph (d)(i) below. (b) Orders by Existing Holders and Potential Holders (i) On or prior to each Auction Date: (A) each Existing Holder may submit to a Broker-Dealer information as to: (1) the number of Outstanding Units, if any, held by such Existing Holder which such Existing Holder desires to continue to hold without regard to the Applicable Rate for the next succeeding Dividend Period; (2) the number of Outstanding Units, if any, held by such Existing Holder which such Existing Holder desires to continue to hold, provided that the Applicable Rate for the next succeeding Dividend Period shall not be less than the rate per annum specified by such Existing Holder; and/or (3) the number of Outstanding Units, if any, held by such Existing Holder which such Existing Holder offers to sell without regard to the Applicable Rate for the next succeeding Dividend Period; and (B) Each Broker-Dealer, using a list of Potential Holders that shall be maintained in good faith for the purpose of conducting a competitive Auction shall contact Potential Holders, including Persons that are not Existing Holders, on such list to determine the number of Outstanding Units, if any, which each such Potential Holder offers to purchase, provided that the Applicable Rate for the next succeeding Dividend Period shall not be less than the rate per annum specified by such Potential Holder. For the purposes hereof, the communication to a Broker-Dealer of information referred to in clause (A) or (B) of this paragraph (b)(i) is hereinafter referred to as an "Order" and each Existing Holder and each Potential Holder placing an Order is hereinafter referred to as a "Bidder"; and Order containing the information referred to in clause (A)(1) of this paragraph (b)(i) is hereinafter referred to as a "Hold Order"; an Order containing the information referred to in clause (A)(2) or (B) of this paragraph (b)(i) is hereinafter referred to as a "Bid"; and an Order containing the information referred to in clause (A)(3) of this paragraph (b)(i) is hereinafter referred to as a "Sell Order." (ii) (A) A Bid by an Existing Holder shall constitute an irrevocable offer to sell: (1) the number of Outstanding Units specified in such Bid if the Applicable Rate determined on such Auction Date shall be less than the rate specified therein; or (2) such number or a lesser number of Outstanding Units to be determined as set forth in paragraph (e)(i)(D) if the Applicable Rate determined on such Auction Date shall be equal to the rate specified therein; or (3) a lesser number of Outstanding Units to be determined as set forth in paragraph (e)(ii)(C) if such specified rate shall be higher than Maximum Applicable Rate and Sufficient Clearing Bids do not exist. (B) A Sell Order by an Existing Holder shall constitute an irrevocable offer to sell: (1) the number of Outstanding Units specified in such Sell Order; or (2) such number or a lesser number of Outstanding Units to be determined as set forth in paragraph (e)(ii)(C) if Sufficient Clearing Bids do not exist. (C) A Bid by a Potential Holder shall constitute an irrevocable offer to purchase: (1) the number of Outstanding Units specified in such Bid if the Applicable Rate determined on such Auction Date shall be higher than the rate specified therein; or (2) such number of a lesser number of Outstanding Units to be determined as set forth in paragraph (e)(i)(E) if the Applicable Rate determined on such Auction Date shall be equal to the rate specified therein. (c) Submission of Orders by Broker-Dealers to Trust Company (i) Each Broker-Dealer shall submit in writing to the Trust Company prior to the Submission Deadline on each Auction Date all Orders obtained by such Broker-Dealer and specifying with respect to each Order: (A) the name of the Bidder placing such Order; (B) the aggregate number of Outstanding Units that are subject of such Order; (C) to the extent that such Bidder is an Existing Holder: (1) the number of Outstanding Units, if any, subject to any Hold Order placed by such Existing Holder; (2) the number of Outstanding Units, if any, subject to any Bid placed by such Existing Holder and the rate specified in such Bid; and (3) the number of Outstanding Units, if any, subject to any Sell Order placed by such Existing Holder; and (D) to the extent such Bidder is a Potential Holder, the rate specified in such Potential Holder's Bid. (ii) If any rate specified in any Bid contains more than three figures to the right of the decimal point, the Trust Company shall round such rate up to the next highest one-thousandth (.001) of 1%. (iii) If an Order or Orders covering all of the Outstanding Units held by an Existing Holder is not submitted to the Trust Company prior to the Submission Deadline, the Trust Company shall deem a Hold Order to have been submitted on behalf of such Existing Holder covering the number of Outstanding Units held by such Existing Holder and not subject to Orders submitted to the Trust Company. (iv) If one or more Orders covering in the aggregate more than the number of Outstanding Units held by an Existing Holder are submitted to the Trust Company, such Orders shall be considered valid as follows and in the following order or priority: (A) any Hold Order submitted on behalf of such Existing Holder shall be considered valid up to and including the number of Outstanding Units held by such Existing Holder; provided that if more than one Hold Order is submitted on behalf of such Existing Holder and the number of Units subject to such Hold Orders exceeds the number of Outstanding Units held by such Existing Holder, the number of Units subject to such Hold Orders shall be reduced pro rata so that such Hold Orders shall cover the number of Outstanding Units held by such Existing Holder; (B) (1) any Bid shall be considered valid up to and including the excess of the number of Outstanding Units held by such Existing Holder over the number of Units subject to Hold Orders referred to in paragraph (c)(iv)(A); (2) subject to clause (1) above, if more than one Bid with the same rate is submitted on behalf of such Existing Holder and the number of Outstanding Units subject to such Bids is greater than such excess, the number of Outstanding Units subject to such Bids shall be reduced pro rata so that such Bids shall cover the number of Outstanding Units equal to such excess; and (3) subject to clause (1) above, if more than one Bid with different rates is submitted on behalf of such Existing Holder, such Bids shall be considered valid in the ascending order of their respective rates and in any such event the number, if any, of such Outstanding shares subject to Bids not valid under this clause (B) shall be treated as the subject of a Bid by a Potential Holder; and (C) any Sell Order shall be considered valid up to and including the excess of the number of Outstanding Units held by such Existing Holder over the number of Outstanding Units subject to Hold Orders referred to in paragraph (c)(iv)(A) and Bids referred to in paragraph (c)(iv)(B). (v) If more than one Bid is submitted on behalf of any Potential Holder, each Bid submitted shall be a separate Bid with the rate and Units therein specified. (vi) If any rate specified in any Bid is lower than the Minimum Applicable Rate for the Dividend Period to which such Bid relates, such Bid shall be deemed to be a Bid specifying a rate equal to such Minimum Applicable Rate. (vii) Orders by Existing Holders and Potential Holders must specify numbers of Units in whole Units. Any Order that specifies a number of Units other than in whole shares will be invalid and will not be considered a Submitted Order for purposes of an Auction. (d) Determination of Sufficient Clearing Bids, Winning Bid Rate and Applicable Rate (i) Not earlier than the Submission Deadline on each Auction Date, the Trust Company shall assemble all Orders submitted or deemed submitted to it by the Broker-Dealers (each such Order as submitted or deemed submitted by a Broker-Dealer being hereinafter referred to individually as a "Submitted Hold Order" a "Submitted Bid" or a "Submitted Sell Order," as the case may be, or as a "Submitted Order") and shall determine: (A) the excess of the total number of Outstanding Units over the number of Outstanding Units that are the subject of Submitted Hold Orders (such excess being hereinafter referred to as the "Available Units"); (B) from the Submitted Orders, whether: (1) the number of Outstanding Units that are the subject of Submitted Bids by Potential Holders specifying one or more rates equal to or lower than the Maximum Applicable Rate exceeds or is equal to the sum of: (2) [a] the number of Outstanding Units that are the subject of Submitted Bids by Existing Holders specifying one or more rates higher than the Maximum Applicable Rate, and [b] the number of Outstanding Units that are subject to Submitted Sell Orders (if such excess of such equality exists (other than because the number of Outstanding Units in clauses [a] and [b] above are each zero because all of the Outstanding Units are the subject of Submitted Hold Orders), such Submitted Bids in clause (1) above being hereinafter referred to collectively as "Sufficient Clearing Bids"); and (C) if Sufficient Clearing Bids exist, the lowest rate specified in the Submitted Bids (the "Winning Bid Rate"), which if: (1) each Submitted Bid from Existing Holders specifying the Winning Bid Rate and all other Submitted Bids from Existing Holders specifying lower rates were rejected, thus entitling such Existing Holders to continue to hold the Units that are the subject of such Submitted Bids, and (2) each Submitted Bid from Potential Holders specifying the Winning Bid Rate and all other Submitted Bids from Potential Holders specifying lower rates were accepted, thus entitling the Potential Holders to purchase the Units that are the subject of such Submitted Bids, would result in the number of shares subject to all Submitted Bids specifying the Winning Bid Rate or a lower rate being at least equal to the Available Units. (ii) Promptly after the Trust Company has made the determinations pursuant to paragraph (d)(i), the Trust Company shall advise the Company of the Maximum Applicable Rate and the Minimum Applicable Rate and, based on such determinations, the Applicable Rate for the next succeeding Dividend Period as follows: (A) if Sufficient Clearing Bids exist, that the Applicable Rate for the next succeeding Dividend Period shall be equal to the Winning Bid Rate so determined; (B) if Sufficient Clearing Bids do not exist (other than because all of the Outstanding Units are the subject of Submitted Hold Orders), that the Applicable Rate for the next succeeding Dividend Period shall be equal to the Maximum Applicable Rate; or (C) if all the outstanding Units are the subject of Submitted Hold Orders, that the Applicable Rate for the next succeeding Dividend Period shall be equal to the Minimum Applicable Rate. (e) Acceptance and Rejection of Submitted Bids and Submitted Sell Orders and Allocation of Shares Based on the determinations made pursuant to paragraph (d)(i), the Submitted Bids and Submitted Sell Orders shall be accepted or rejected and the Trust Company shall take such other action as set forth below: (i) If Sufficient Clearing Bids have been made, subject to the provisions of paragraphs (e)(iii) and (e)(iv), Submitted Bids and Submitted Sell Orders shall be accepted or rejected in the following order or priority and all other Submitted bids shall be rejected: (A) the Submitted Sell Orders of Existing Holders shall be accepted and the Submitted Bid of each of the Existing Holders specifying any rate that is higher than the Winning Bid Rate shall be rejected, thus requiring each such Existing Holder to sell the Outstanding Units that are the subject of such Submitted Bid; (B) the Submitted Bid of each of the Existing Holders specifying any rate that is lower than the Winning Bid Rate shall be accepted, thus entitling each such Existing Holder to continue to hold the Outstanding Units that are the subject of such Submitted Bid; (C) the Submitted Bid of each of the Potential Holders specifying any rate that is lower than the Winning Bid Rate shall be accepted; (D) the Submitted Bid of each of the Existing Holders specifying a rate that is equal to the Winning Bid Rate shall be accepted, thus entitling each such Existing Holder to continue to hold the Outstanding Units that are the subject of such Submitted Bid, unless the number of Outstanding Units subject to all such Submitted Bids shall be greater than the number of Outstanding Units ("remaining shares") equal to the excess of the Available Units over the number of Outstanding Units subject to Submitted Bids described in paragraphs (e)(i)(B) and (e)(i)(C), in which event the Submitted Bids of each such Existing Holder shall be rejected, and each such Existing Holder shall be required to sell Outstanding Units, but only in an amount equal to the difference between (1) the number of Outstanding Units then held by such Existing Holder subject to such Submitted Bid and (2) the number of Units obtained by multiplying (x) the number of remaining shares by (y) a fraction the numerator of which shall be the number of Outstanding Units held by such Existing Holder subject to such Submitted Bid and the denominator of which shall be the sum of the number of Outstanding Units subject to such Submitted Bids made by all such Existing Holders that specified a rate equal to the Winning Bid Rate; and (E) the Submitted Bid of each of the Potential Holders specifying a rate that is equal to the Winning Bid Rate shall be accepted but only in an amount equal to the number of Outstanding Units obtained by multiplying (x) the difference between the Available Units and the number of Outstanding Units subject to the Submitted Bids described inparagraphs (e)(i)(B), (e)(i)(C) and (e)(i)(D) by (y) a fraction the numerator of which shall be the number of Outstanding shares of Units subject to such Submitted Bid and the denominator of which shall be the sum of the number of Outstanding Units subject to such Submitted Bids made by all such Potential Holders that specified rates equal to the Winning Bid Rate. (ii) If Sufficient Clearing Bids have been made (other than because all of the Outstanding Units are subject to Submitted Hold Orders), subject to the provisions of paragraphs (e)(iii) and (e)(iv), Submitted Orders shall be accepted or rejected as follows in the following order of priority and all other Submitted Bids shall be rejected: (A) the Submitted Bid of each Existing Holder specifying any rate that is equal to or lower than the Maximum Applicable Rate shall be accepted, thus entitling such Existing Holder to continue to hold the Outstanding Units that are the subject of such Submitted Bid; (B) the Submitted Bid of each Potential Holder specifying any rate that is equal to or lower than the Maximum Applicable Rate shall be accepted, thus requiring such Potential Holder to purchase the Outstanding Units that are the subject of such Submitted Bid; and (C) the Submitted Bids of each Existing Holder specifying any rate that is higher than the Maximum Applicable Rate shall be rejected and the Submitted Sell Orders of each Existing Holder shall be accepted, in both cases only in an amount equal to the difference between (1) the number of Outstanding Units then held by such Existing Holder subject to such Submitted Bid or Submitted Sell Order and (2) the number of Units obtained by multiplying (x) the difference between the Available Units and the aggregate number of Outstanding Units subject to Submitted Bids described in paragraphs (e)(ii)(A) and (e)(ii)(B) by (y) a fraction the numerator of which shall be the number of Outstanding Units held by such Existing Holder subject to such Submitted Bid or Submitted Sell Order and the denominator of which shall be the number of Outstanding Units subject to all such Submitted Bids and Submitted Sell Orders. (iii) If, as a result of the procedures described in paragraph (e)(i) or (e)(ii), any Existing Holder would be entitled or required to sell, or any Potential Holder would be entitled or required to purchase, a fraction of a Unit on any Auction Date, the Trust Company shall, in such manner as, in its sole discretion, it shall determine, round up or down the number of Units to be purchased or sold by any Existing Holder or Potential Holder on such Auction Date so that the number of Outstanding shares purchased or sold by each Existing Holder or Potential Holder on such Auction Date shall be whole Units. (iv) If, as a result of the procedures described in paragraph (e)(i), any Potential Holder would be entitled or required to purchase less than a whole Unit on any Auction Date, the Trust Company shall, in such manner as, in its sole discretion, it shall determine, allocate Units for purchase among Potential Holders so that only whole Units are purchased on such Auction Date by any Potential Holder, even if such allocation results in one or more of such Potential Holders not purchasing Units on such Auction Date. (v) Based on the results of each Auction, the Trust Company shall determine the aggregate number of Outstanding Units to be purchased and the aggregate number of Outstanding Units to be sold by Potential Holders and Existing Holders on whose behalf each Broker-Dealer submitted Bids or Sell Orders, and, with respect to each Broker-Dealer, to the extent that such aggregate number of Outstanding Units to be purchased and such aggregate number of Outstanding Units to be sold differ, determine to which other Broker-Dealer or Broker-Dealers acting for one or more purchasers such Broker-Dealer shall deliver, or from which other Broker-Dealer or Broker-Dealers acting for one or more sellers such Broker-Dealer shall receive, as the case may be, Outstanding Units. (f) Miscellaneous The Board of Directors may interpret the provisions of these Auction Procedures to resolve any inconsistency or ambiguity, and may remedy any formal defect or make any other change or modification which does not adversely affect the rights of Existing Holders of Units. An Existing Holder (A) may sell, transfer or otherwise dispose of Units only pursuant to a Bid or Sell Order in accordance with the procedures described in this paragraph or to or through a Broker-Dealer or to a Person that has delivered a signed copy of a Purchaser's Letter to the Trust Company, provided that in the case of all transfers other than pursuant to Auctions such Existing Holder, its Broker-Dealer or its Agent Member advises the Trust Company of such transfer and (B) shall have the ownership of the Units held by it maintained in book entry form by the Securities Depository in the account of its Agent Member, which in turn will maintain records of such Existing Holder's beneficial ownership. Neither the Company nor any Affiliate shall submit an Order, either directly or indirectly, in any Auction. Except as otherwise provided by law, all of the Outstanding Units shall be represented by a certificate registered in the name of the nominee of the Securities Depository and no Person acquiring Units shall be entitled to receive a certificate representing such Units. (g) Headings of Subdivisions The headings of the various subdivisions of these Auction Procedures are for convenience of reference only and shall not affect the interpretation of any of the provisions hereof. WESTERN MASSACHUSETTS ELECTRIC COMPANY RESTATED ARTICLES OF ORGANIZATION RIDER 6A Each meeting of the stockholders, annual or special, shall be held at such hour of the day, and at such place within the United States, or at such other place as shall then be permitted by law, as may be designated by the Board of Directors, by the Chairman of the Board or by the President. *We further certify that the foregoing restated articles of organization effect no amendments to the articles of organization of the corporation as heretofore amended, except amendments to the following articles: 3, 4 and 6 (*If there are no such amendments, state "None".) Briefly describe amendments in space below: Article 3 - Article 3 has been amended to eliminate the provisions with respect to the 9.60% Preferred Stock, Series A, the 16% Preferred Stock, Series C and the Adjustable Rate Preferred Stock, Series D. Each of these series has been retired or redeemed in its entirety. Article 4 - Article 4 has been amended to include the amount and classes of authorized stock and to delete references to specific sections of the Company's By-laws in favor of general references. These changes are ministerial only and do not affect any of the rights or obligations of the holders of shares of any class or series of the capital stock of the company. It also has been amended to eliminate the provisions with respect to the 9.60% Preferred Stock, Series A, the 16% Preferred Stock, Series C and the Adjustable Rate Preferred Stock, Series D. Each of these series has been retired or redeemed in its entirety. Article 6 - has been amended regarding the time and place for meetings of stockholders. IN WITNESS WHEREOF AND UNDER THE PENALTIES OF PERJURY, we have hereto signed our names this 17th day of February in the year 1995 \s\ Hugh C. MacKenzie President \s\ Mark A Joyse Assistant Clerk THE COMMONWEALTH OF MASSACHUSETTS RESTATED ARTICLES OF ORGANIZATION (General Laws, Chapter 164, Section 8c) I hereby approved the within restated articles of organization and, the filing fee in the amount of $ 500.00 having been paid, said articles are deemed to be filed with me this 23rd day of February, 1995. /s/William Francis Galvin Secretary of State TO BE FILED IN BY CORPORATION PHOTO COPY OF RESTATED ARTICLES OF ORGANIZATION TO BE SENT TO: Robert L. Dewees, Jr. Peabody & Brown 101 Federal Street Boston, MA 02110-1832 EX-3.4.2 3 BY-LAWS WESTERN MASSACHUSETTS ELECTRIC COMPANY Adopted February 11, 1937 (Amended February 18, 1942) January 13, 1943 October 19, 1945 January 15, 1947 August 18, 1948 November 17, 1954 February 26, 1960 September 9, 1960 February 27, 1962 July 8, 1964 May 19, 1966 December 5, 1967 June 3, 1970 August 2, 1971 October 13, 1971 October 20, 1975 December 16, 1981 March 1, 1982 April 12, 1983 December 15, 1983 (effective November 13, 1986) February 11, 1987 February 24, 1988 April 11, 1994 February 13, 1995 WESTERN MASSACHUSETTS ELECTRIC COMPANY BY-LAWS ARTICLE I STOCKHOLDERS' MEETINGS The annual meeting of the stockholders shall be held on the first Wednesday of March in each year, and special meetings of the stockholders shall be held whenever the Chairman of the Board, the President, or two Directors shall so order, or whenever called in any other manner as provided by law. Each meeting of the stockholders, annual or special, shall be held at such hour of the day, and at such place within the United States, or at such other place as shall then be permitted by law, as may be designated by the Board of Directors, by the Chairman of the Board or by the President. Notice of the time and place of every such meeting shall be given by the Clerk by mailing a notice to each stockholder of record at his address as shown on the books of the corporation not less than seven (7) days before the day named for the meeting. No business shall be in order at a special meeting except such as shall have been indicated in the notice of such meeting. In the event of any failure to call and hold the annual meeting as herein provided, a special meeting may be called and held in lieu of and for the purposes of such annual meeting. Any election had or business done at such substitute meeting shall be as valid and effectual as if had or done at a meeting called as an annual meeting and duly held on said date. A majority in interest of all the shares of stock of the corporation outstanding present in person or by proxy shall constitute a quorum for the transaction of business but less than a quorum may adjourn either sine die or to a date certain. No meeting of the stockholders shall be deemed to be invalid for want of notice provided every stockholder waives notice thereof by a writing filed either before or after such meeting with the records thereof. ARTICLE II OFFICERS The officers of the corporation shall be a Chairman of the Board of Directors, a President, an Executive Vice-president, one or more Vice- presidents, a Treasurer, a Clerk, a Board of not less than five (5) nor more than twenty-five (25) Directors, such other officers as the Board of Directors may appoint, including, if the Directors see fit, a Secretary and one or more Assistant Treasurers. The officers need not be stockholders. No two of the following offices may be held by the same person: Chairman of the Board of Directors, President, Executive Vice-president, and Vice- president, and the Treasurer shall not be an Assistant Treasurer. The business, property and affairs of the Company shall be managed by a Board of not less than three nor more than sixteen Directors. Within these limits, the number of positions on the Board of Directors for any year shall be the number fixed by resolution of the shareholders or of the Board of Directors, or, in the absence of such a resolution, shall be the number of Directors elected at the preceding Annual Meeting of Shareholders. The Directors so elected shall continue in office until their successors have been elected and qualified. ARTICLE III ELECTION OF OFFICERS The Directors, the clerk, and the Treasurer shall be elected by ballot each year at the annual meeting of the stockholders. The Chairman of the Board, the President, the Executive Vice-president, and each Vice- president shall be elected annually by, and the Chairman of the Board and the President shall be elected from, The Board of Directors. All such other officers as the Directors may appoint, as provided in Article II, shall be elected annually by the Board of Directors. Any vacancy in the office of Chairman of the Board, President, Executive Vice-president, Vice-president, Directors, Treasurer, Assistant Treasurer, or Clerk arising from non-election, resignation, declination, death, or any other cause, may be filled by the Board of Directors, except that whenever the number of Directors shall be increased at any special meeting of the stockholders the additional Directors so provided for shall be elected by ballot by the stockholders at the same meeting. Said Board may also elect an officer pro tempore to serve during the disability or absence of any officer. Officers chosen to fill vacancies shall hold their offices until new officers are duly chosen by the stockholders or Directors, as the case may be. ARTICLE IV DIRECTORS Meetings of the Board of Directors may be held at any time and place at the call of the Chairman of the Board, the President, or any two Directors. Notice of each meeting shall be given to each Director either by notice mailed to him at least forty-eight (48) hours before the time of such meeting, or by a telephone or telegraphic message sent to his place of business or residence, or other form of notice actually given to him twenty-four (24) hours before the time of such meetings. However, any meeting of the Board and all business transacted thereat shall be legal and valid without such notice if each member of the Board is present in person or waives notice thereof by writing filed with the records of the meeting or assents in writing to the recorded proceedings of the meeting. One-third of the directors then in office shall constitute a quorum, except that no quorum shall consist of less than two Directors. A number less than a quorum may adjourn from time to time until a quorum is present. In the event of such an adjournment, notice of the adjourned meeting shall be given to all Directors. The Board of Directors may at any time elect by ballot not less than five (5) of their members who shall constitute an Executive committee of the Board, and if such an Executive Committee is elected the Board of Directors shall make regulations defining the powers and duties of such Executive Committee and may delegate to it any or all of their powers in management of the property, business and affairs of the corporation except so far as is incompatible with these By-laws or with the laws of the Commonwealth. A majority of the Executive Committee shall constitute a quorum. Such Executive Committee shall elect a Chairman and Secretary and shall keep a record of its doings which at all reasonable times shall be open to inspection by each member of the Board of Directors. The Chairman of the Executive Committee shall submit its records to the Board of Directors at each regular or special meeting of the Board for such action as said Board may deem proper. The Directors as a Board shall have the management of the property, business and affairs of the corporation and they are hereby invested in such management with all the powers which the corporation itself possesses so far as such investing is not incompatible with the provisions of these By-laws or the laws of the Commonwealth. However, so long as the holders of the outstanding shares of the corporation's preferred stock voting as a class have not exercised their right to elect a majority of the Board of Directors of the corporation on the happening of any of the events of default specified in the preferred stock provisions of these By-laws, any right of the corporation to terminate, amend, rescind, waive, discharge, or in any other way alter or change the obligations of the corporation under any contract with Northeast Nuclear Energy Company covering the maintaining of an inventory of nuclear core elements for Unit Nos. 1, 2 or 3 of the Millstone Nuclear Power Station, including, without limitation, the Fuel Supply Contract dated as of December 1, 1972, (as it is to be amended by a Contract of Amendment to be dated as of October 1, 1975), by and among the corporation, The Hartford Electric Light Company, and the Connecticut Light and Power Company and Northeast Nuclear Energy Company, shall be reserved to the common stockholders of the corporation. They may appoint and remove at pleasure such subordinate officers and employees as may see to them wise. They may assign such powers and duties to any officers or subordinate officers or employees as may not be inconsistent with Laws or these By-laws. They shall have access to the books, vouchers and funds of the corporation in the custody of the Treasurer, shall determine upon the form of the corporate seal and of the certificates of stock, shall fix the salaries of the officers, and shall declare dividends from time to time as they may deem for the best interests of the corporation. They may make contributions to corporations, trusts, funds or foundations organized and operated exclusively for charitable, scientific or educational purposes, no part of the earnings of which inures to the benefit of any private shareholder or individual, in such amounts as they may deem reasonable up to but not exceeding in any fiscal year in the aggregate one-half of one percent of the capital and surplus of the corporation as at the close of the fiscal year last preceding the making of any such contribution. The Company shall indemnify each of its Directors and officers (including persons who serve at its request as Directors, officers, or in any other similar capacity of another organization in which it has any interest as a shareholder, creditor or otherwise) against all liabilities and expenses, including amounts paid in satisfaction of judgments, in compromise or as fines and penalties, and counsel fees, reasonably incurred by him in connection with the defense or disposition of any action, suit or other proceeding, whether civil or criminal, in which he may be involved or with which he may be threatened, while in office or thereafter, by reason of his being or having been such a Director or officer, except with respect to any matter as to which he shall have been adjudicated in such action, suit or proceeding not to have acted in good faith in the reasonable belief that his action was in the best interests of the corporation; provided, however, that as to any matter disposed of by a compromise payment by such Director or officer pursuant to a consent decree or otherwise, no indemnification either for said payment or for any other expenses shall be provided unless such compromise shall be approved as in the best interests of the corporation, after notice that it involves such indemnification, (a) by a disinterested majority of the Directors then in office; or (b) by a majority of the disinterested Directors then in office, provided that there has been obtained an opinion in writing of independent legal counsel to the effect that such Director or officer appears to have acted in good faith in the reasonable belief that his action was in the best interests of the corporation; or (c) by the holders of majority of the outstanding stock at the time entitled to vote for Directors, voting as a single class, exclusive of any stock owned by an interested Director or officer. In discharging his duty any such Director or officer, when acting in good faith, may rely upon the books of account of the corporation or of such other organization, reports made to the corporation or to such other organization by any of its officers or employees or by counsel, accountants, appraisers or other experts selected with reasonable care by the Board of Directors or officers, or upon other records of the corporation or of such other organization. Expenses incurred with respect to any such action, suit or proceeding may be advanced by the corporation prior to the final disposition of such action, suit or proceeding, upon receipt of an undertaking by or on behalf of the recipient to repay such amount unless it is ultimately determined that he is entitled to indemnification. The right of indemnification hereby provided shall not be exclusive of or affect any other right to which any Director or officer may be entitled. As used in this paragraph, the terms "Director" and "officer" include their respective heirs, executors and administrators, and an "interested" Director or officer is one against whom in such capacity the proceedings in question or another proceeding on the same or similar grounds is then pending. Nothing contained in this Article shall be found, in any action, suit or proceeding to be invalid or ineffective, the validity and the effect of the remaining parts shall not be affected. ARTICLE V CHAIRMAN OF THE BOARD OF DIRECTORS The Chairman of the Board of Directors shall preside at the meetings of the Board and shall act in a general advisory capacity to the Board in regard to all activities of the corporation, and shall have such other powers and perform such other duties as may from time to time be determined by the Board. ARTICLE VI THE PRESIDENT The President shall preside at all meetings of the stockholders and in the absence of the Chairman of the Board at all meetings of the Board of Directors. The President shall be the chief executive officer of the corporation and shall have full charge of its business and affairs and shall perform all the duties of this office prescribed by law and all powers and duties given him by the Board of Directors. ARTICLE VII EXECUTIVE VICE-PRESIDENT AND VICE-PRESIDENTS The Executive Vice-president shall have such powers and perform such duties as may be assigned to him by the Board of Directors or as may be delegated to him by the President. In the absence or disability of the President, or in case of an unfilled vacancy in that office, the Executive Vice-president shall perform the duties and exercise the powers of the President. The Vice-president or Vice-presidents shall perform such duties of a general or special nature as may be assigned to him or them by the Board of Directors or as may be delegated to him or them by or through the President. In case of the absence or disability of the Executive Vice-president, a Vice-president shall perform all the duties and have all the powers of the Executive Vice-president. If there are at any time two or more Vice-presidents, the one to act in place of the Executive Vice-president shall be selected by the Board of Directors, provided, however, that prior to the making of such selection by said Board a Vice-president to act as aforesaid may be appointed by the President, or if he is unable to make such appointment or fails to do so, by the Chairman of the Board, and the Vice-president so appointed shall continue to act as aforesaid until another Vice-president has been appointed for that purpose by the Board of Directors. ARTICLE VIII THE SECRETARY AND THE CLERK The Secretary shall have such duties as may from time to time be delegated to him by the Board of Directors. The Clerk shall be a resident of Massachusetts. He shall be sworn, and shall record all votes of the corporation in a book to be kept for the purpose. He shall attend all meetings of stockholders, of the Board of Directors, and of the Executive Committee. In the absence of the Clerk or if at any such meeting he shall be otherwise engaged, an Assistant Clerk if present shall record the votes taken at the meeting, and if no Assistant Clerk shall be present, a Clerk pro tempore shall be chosen for that purpose. The Clerk or any Assistant Clerk may furnish certified copies of any portion of the records of the corporation under its corporate seal. All Assistant Clerks shall be sworn. ARTICLE IX THE TREASURER The Treasurer when required by the Directors shall give bond with sureties acceptable to them for the faithful discharge of his duties and in such sum as the Directors may determine, and the premium may, by vote of the Board of Directors, be paid from the funds of the corporation. He shall be the transfer agent of the stock of the corporation unless a special transfer agent is appointed by the Directors, shall keep a record of the names and residences of all the stockholders, shall have the custody of the corporate seal and of all the moneys, funds and valuable papers and documents of the corporation except his own bond which shall be in the custody of the President. He shall deposit all the funds of the corporation in such bank or banks as the Directors shall designate to the credit of the corporation by its corporate name, subject to the checks of the corporation signed by its Treasurer or an Assistant Treasurer or such other officer or employee as may be designated for that purpose by the vote of the Directors, but with such requirements, if any, as to joint signatures and such other limitations, if any, of the authority as aforesaid of any signing officer or employee as the Directors may see fit to impose. He shall issue notes and accept drafts on behalf of the corporation only when authorized thereto by the Directors. He shall keep accurate books of account of the corporation's transactions which shall be the property of the corporation, which together with all its property in his custody shall be subject at all times to inspection and control of the Directors. ARTICLE X ASSISTANT TREASURER Each Assistant Treasurer, if any, shall have such powers and duties as may be given him by the Directors and shall give bond when required by the Directors with sureties acceptable to them for the faithful discharge of his duties in such sum as the Directors may determine, and the premiums may, by vote of the Board of Directors, be paid by the corporation. ARTICLE XI SALES, LEASES, AND CONVEYANCES OF REAL ESTATE The President and Treasurer may in their discretion, to the extent authorized by law and by vote of the Directors or of the Executive Committee, lease for any term of time and convey all of its real estate including water power and release or modify easements and other rights in real estate whether granted to or by the corporation; and all deeds, conveyances and leases of real estate including water power and releases and modifications of easements and of other rights in real estate of the corporation, unless otherwise provided by vote of the corporation, shall be made in the name of the corporation under its corporate seal, and be signed by the President, the Executive Vice-president, or any Vice-president thereto authorized by a vote of the Directors or of the Executive Committee and may be acknowledged by any person signing as aforesaid. ARTICLE XII CERTIFICATES OF STOCK-TRANSFERS Certificates of stock may be signed by the President or a Vice-president and the Treasurer or an Assistant Treasurer. Such certificates shall be in such form as the Directors may approve, and shall also bear the seal of the corporation which shall be in the form theretofore used by the corporation, or in a newer form adopted by the Directors. Shares of stock may be transferred by assignment thereof in writing, accompanied by delivery of the certificates; but no such transfer of stock shall affect the right of the corporation to pay any dividend thereon or to treat the holder of record as the holder in fact until the transfer has been recorded upon the books of the corporation or a new certificate has been issued to the person to whom the stock has been transferred. In case of the loss of a certificate, a duplicate may be issued on such reasonable terms as the Directors shall prescribe. ARTICLE XIII CLOSING OF TRANSFER BOOKS The transfer books of the corporation may be closed for not exceeding fifteen (15) days next prior to any meeting of the stock-holders and at such other times and for such reasonable periods as may be determined by the Board of Directors. ARTICLE XIV FISCAL YEAR The fiscal year of the corporation shall end on the thirty-first day of December in each year. ARTICLE XV TRANSFER AGENT AND REGISTRAR If the Board of Directors deem it advisable to have a transfer agent other than the Treasurer, they may appoint any Bank or Trust Company to that office. They may appoint the same or any other Bank or Trust Company as Registrar of stock certificates if it appear desirable to have the stock registered. They may terminate the authority of any Bank acting in either capacity whenever it shall seem wise. ARTICLE XVI SENIOR STOCK PROVISIONS The Company's capital stock includes a class of capital stock designated "Common Stock," a class of capital stock designated "Preferred Stock," and a class of capital stock designated "Class A Preferred Stock." The authorized shares of Common Stock, Preferred Stock and Class A Preferred Stock are the number of shares authorized in the Company's articles of organization, as amended from time to time. The Preferred Stock and the Class A Preferred Stock are hereinafter for convenience of reference sometimes collectively referred to as the "Senior Stock," and either class may hereinafter individually be referred to as "Senior Stock." Shares of Preferred Stock and shares of Class A Preferred Stock shall rank on a parity in respect of dividends or payment in case of liquidation, and, to the extent not fixed and determined by these by-laws or the Company's articles of organization or otherwise by law, shall have the same rights, preferences and powers. The general terms, limitations and relative rights and preferences of each share of Preferred Stock and each share of Class A Preferred Stock shall be determined in accordance with the following Sections: Section 1. Issuance of Senior Stock Shares of Preferred Stock may be issued from time to time in one or more series on such terms and for such consideration as may be determined by the Board of Directors. Shares of Class A Preferred Stock may be issued from time to time in one or more series on such terms and for such consideration as may be determined by the Board of Directors. The series designation, dividend rate, redemption prices, and any other terms, limitations and relative rights and preferences of each series of either class of Senior Stock shall be determined by the Board of Directors to the extent not fixed and determined by this Article or the Company's articles of organization. Section 2. Dividends A. The holders of either class of the Senior Stock shall receive, but only when and as declared by the Board of Directors, cumulative dividends at the rate provided for the particular series and payable on such dividend payment dates in each year as said Board may determine, such dividends to be payable to holders of record on such dates as may be fixed by said Board but not more than 45 days before each dividend date, provided, however, that dividends shall not be declared and set apart for payment, or paid, on Senior Stock of any one class and series, for any dividend period, unless dividends have been or are contemporaneously declared and set apart for payment, or paid, on Senior Stock of all series for all dividend periods terminating on the same or an earlier date. B. Dividends on each share of Senior Stock shall be cumulative from the date of issue thereof or from such earlier date as the Board of Directors may determine therefor. Unless full cumulative dividends to the last preceding dividend date shall have been paid or set apart for payment on all outstanding shares of Senior Stock, no dividend shall be paid on any junior stock. The term "junior stock" means Common Stock or any other stock of the Company subordinate to the Senior Stock in respect of dividends or payments in liquidation. C. So long as any shares of Senior Stock are outstanding, the Company shall not declare any dividends or make any other distributions in respect of outstanding shares of any junior stock of the Company, other than dividends or distributions in shares of junior stock, or purchase or otherwise acquire for value any outstanding shares of junior stock (the declaration of any such dividend or the making of any such distribution, purchase or acquisition being herein called a "junior stock payment") in contravention of the following: (1) If and so long as the junior stock equity (hereinafter defined), adjusted to reflect the proposed junior stock payment, at the end of the calendar month immediately preceding the calendar month in which the proposed junior stock payment is to be made is less than 20% of total capitalization (hereinafter defined) at that date, as so adjusted, the Company shall not make such junior stock payment in an amount which, together with all other junior stock payments made within the year ending with and including the date on which the proposed junior stock payment is to be made, exceeds 50% of the net income of the Company available for dividends on junior stock for the 12 full calendar months immediately preceding the calendar month in which such junior stock payment is made, except in an amount not exceeding the aggregate of junior stock payments which under the restrictions set forth above in this paragraph (1) could have been, and have not been, made. (2) If and so long as the junior stock equity, adjusted to reflect the proposed junior stock payment, at the end of the calendar month immediately preceding the calendar month in which the proposed junior stock payment is to be made, is less than 25% but not less than 20% of the total capitalization at that date, as so adjusted, the Company shall not make such junior stock payment in an amount which, together with all other junior stock payments made within the year ending with and including the date on which the proposed junior stock payment is to be made, exceeds 75% of the net income of the Company available for dividends on the junior stock for the 12 full calendar months immediately preceding the calendar month in which such junior stock payment is made, except in an amount not exceeding the aggregate of junior stock payments which under the restrictions set forth above in this paragraph (2) could have been, and have not been, made. D. The term "junior stock equity" means the aggregate of the part value of or stated capital represented by, the outstanding shares of junior stock, all earned surplus, capital or paid-in surplus, and any premiums on the junior stock then carried on the books of the Company, less: (1) the excess, if any, of the aggregate amount payable on involuntary liquidation of the Company upon all outstanding shares of Senior Stock over the sum of (i) the aggregate par or stated value of such shares and (ii) any premiums thereon; (2) any amounts on the books of the Company known, or estimated if not known, to represent the excess, if any, of recorded value over original cost of used or useful utility plant; and (3) any intangible items set forth on the asset side of the balance sheet of the Company as a result of accounting convention, such as unamortized debt discount and expense; provided, however, that no deductions shall be required to be made in respect of items referred to in clauses (2) and (3) of this subsection D in cases in which such items are being amortized or are provided for, or are being provided for, by reserves. E. The term "total capitalization" means the aggregate of: (1) the principal amount of all outstanding indebtedness of the Company maturing more than 12 months after the date of issue thereof; and (2) the par value or stated capital represented by, and any premiums carried on the books of the Company in respect of, the outstanding shares of all classes of the capital stock of the Company, earned surplus, and capital or paid-in surplus, less any amounts required to be deducted pursuant to clauses (2) and (3) of subsection D of this Section 2 in the determination of junior stock equity. Section 3. Redemption or Purchase of Senior Stock A. All or any part of any series of Senior Stock may by vote of the Board of Directors be called for redemption at any time at the redemption price provided for the particular series and in the manner hereinbelow provided. Subject to the provisions of subsection B of this Section 3, all or any part of any series of Senior Stock may be called for redemption without calling all or any part of any other series of Senior Stock. If less than all of any series of Senior Stock is so called, the Transfer Agent shall determine by lot or in some other manner approved by the Board of Directors the shares of such series of Senior Stock to be called. B. No call for redemption of less than all shares of Senior Stock outstanding shall be made if the Company shall be in arrears in respect of payment of dividends on any shares of Senior Stock outstanding. C. The sums payable in respect of any shares of Senior Stock so called shall be payable at the office of an incorporated bank or trust company in good standing. Notice of such call stating the redemption date shall be mailed not less than 30 days before the redemption date to each holder of record of shares of Senior Stock so called at his address as it appears upon the books of the Company. D. The Company shall, before the redemption date, deposit with said bank or trust company all sums payable with respect to shares of Senior Stock so called. After such mailing and deposit the holders of shares of Senior Stock so called for redemption shall cease to have any right to future dividends or other rights or privileges as stockholders in respect of such shares and shall be entitled to look for payment on and after the redemption date only to the sums so deposited with said bank or trust company for their respective amounts. Shares so redeemed may be reissued but only subject to the limitations imposed upon the issue of Senior Stock. E. The Company may at any time purchase all or any of the then outstanding shares of Senior Stock of any class and series upon the best terms reasonably obtainable, but not exceeding the then current redemption price of such shares, except that no such purchase shall be made if the Company shall be in arrears in respect of payment of dividends on any shares of Senior Stock outstanding or if there shall exist an event of default as defined in Section 5 hereof. Section 4. Amounts Payable on Liquidation A. The holders of any series of Senior Stock shall receive upon any voluntary liquidation, dissolution or winding up of the Company the then current redemption price of the particular series and if such action is involuntary $100 per share in the case of the Preferred Stock and $25 per share in the case of the Class A Preferred Stock, plus in each case all dividends accrued and unpaid to the date of such payment, before any payment in liquidation is made on any junior stock. B. If the net assets of the Company available for distribution on liquidation to the holders of Senior Stock shall be insufficient to pay said amounts in full, then such net assets shall be distributed among the holders of Senior Stock, who shall receive a common percentage of the full respective preferential amounts. Section 5. Voting Powers A. Except as provided in this Article or in the Company's articles of organization and as provided by law, the holders of Senior Stock shall have no voting power or right to notice of any meeting. B. Whenever the holders of the Senior Stock shall have the right to vote or consent to an action as provided in these Articles or the Company's articles of organization or as provided by law, both classes of Senior Stock shall (except as provided below) vote together as a single class, each outstanding share of Preferred Stock entitled to vote and each outstanding share of Class A Preferred Stock entitled to vote having such voting rights as are proportionate to the ratio of (i) the par value represented by such share to (ii) the par value represented by all shares of Senior Stock then outstanding. Whenever only one class of the Senior Stock shall have the right to vote or consent to an action as provided in these Articles or the Company's articles of organization or as provided by law, or whenever each class of the Senior Stock shall be entitled or be required to vote as a separate class on a matter, each outstanding share of such class entitled to vote shall be entitled to one vote on each such matter. C. Whenever dividends on any share of Senior Stock shall be in arrears in an amount equal to or exceeding four quarterly dividend payments, or whenever there shall have occurred some default in the observance of any of the provisions of this Article, or some default on which action has been taken by debentureholders, bondholders or the trustee of any deed of trust or mortgage of the Company, or whenever the Company shall have been declared bankrupt or a receiver of its property shall have been appointed (any of said conditions being herein called an "event of default"), then the holders of Senior Stock shall be given notice of all stockholders' meetings and shall have the right voting together as a class to elect the smallest number of directors necessary to constitute a majority of the Board of Directors of the Company and the exclusive right voting together as a class to amend the by-laws to make such appropriate increase in the number of directorships as may be required to effect such election. When all arrears of dividends shall have been paid and such event of default shall have been terminated, all the rights and powers of the holders of Senior Stock to receive notice and to vote shall cease, subject to being again revived on any subsequent event of default. D. Whenever the right to elect directors shall have accrued to the holders of Senior Stock the Company shall call a meeting of stockholders for the election of directors and, if necessary, the amendment of the by-laws to permit the holders of Senior Stock to exercise their rights pursuant to subsection C of this Section 5, such meeting to be held not less than 45 days and not more than 90 days after the accrual of such rights. When such rights shall cease, the Company shall, within seven days from the delivery to the Company of a written request therefor by any stockholder, cause a meeting of the stockholders to be held within 30 days from the delivery of such request for the purpose of electing a new Board of Directors. Forthwith, upon the election of such new Board of Directors, the directors in office immediately prior to such election (other than persons elected directors in such election) shall be deemed removed from office without further action by the Company. Section 6. Action Requiring Certain Consent of Senior Stockholders A. So long as any Senior Stock is outstanding, the Company, without the affirmative vote or written consent of at least a majority in interest of the Senior Stock then outstanding voting or giving consent together as a class shall not: (1) Issue or assume any unsecured notes, unsecured debentures or other securities representing unsecured debt (other than for the purpose of refunding or renewing outstanding unsecured securities issued or assumed by the Company resulting in equal or longer maturities or redeeming or otherwise retiring all outstanding shares of Senior Stock) if immediately after such issue or assumption (a) the total outstanding principal amount of all unsecured notes, unsecured debentures or other securities representing unsecured debt of the Company will thereby exceed 20% of the aggregate of all outstanding secured debt of the Company and the capital stock, premiums thereon, and surplus of the Company, as stated on its books, or (b) the total outstanding principal amount of all unsecured debt of the Company of maturities of less than 10 years will thereby exceed 10% of the aggregate of all outstanding secured debt of the Company and the capital stock, premiums thereon, and surplus of the Company, as stated on its books. For the purposes of this subsection A, the payment due upon the maturity of unsecured debt having an original single stated maturity of 10 years or more shall not be regarded as unsecured debt with a maturity of less than 10 years until within three years of the maturity thereof, and none of the payments due upon any unsecured serial debt having an original stated maturity for the final serial payment of 10 years or more shall be regarded as unsecured debt of a maturity of less than 10 years until within three years of the maturity of the final serial payment. (2) Issue, sell or otherwise dispose of any shares of the then authorized but unissued Senior Stock or any other stock ranking on a parity with or having a priority over Senior Stock in respect of dividends or of payments in liquidation, or reissue, sell or otherwise dispose of any reacquired shares of Senior Stock or such other stock, other than to refinance an equal par value or stated value of Senior Stock or of stock ranking on a parity with or having priority over Senior Stock in respect of dividends or of payments in liquidation, if: (a) For a period of 12 consecutive calendar months within 15 calendar months immediately preceding the calendar month in which any such shares shall be issued, the Income before Interest Charges of the Company for said period available for the payment of interest determined in accordance with the systems of accounts then prescribed for the Company by the Department of Public Utilities of the Commonwealth of Massachusetts (or by such other official body as may then have authority to prescribe such systems of accounts) but in any event after deducting depreciation charges and taxes (including income taxes) and including, in any case in which such stock is to be issued, sold or otherwise disposed of in connection with the acquisition of any property, the Income before Interest Charges of the property to be so acquired, computed as nearly as practicable in the manner specified above, shall not have been at least one and one-half (1 1/2) times the sum of (i) the interest charges for one year on all indebtedness which shall then be outstanding (excluding interest charges on any indebtedness, proposed to be retired in connection with the issue, sale or other disposition of such shares), and (ii) an amount equal to all annual dividend requirements on all outstanding shares of Senior Stock and all other stock, if any, ranking on a parity with or having priority over Senior Stock in respect of dividends or of payments in liquidation, including the shares proposed to be issued, but not including any shares proposed to be retired in connection with such issue, sale or other disposition; or if (b) Such issue, sale or disposition would bring the aggregate of the amount payable in connection with an involuntary liquidation of the Company with respect to all shares of Senior Stock and all shares of stock, if any, ranking on a parity with or having priority over Senior Stock in respect of dividends or of payments in liquidation to an amount in excess of the sum of the junior stock equity. If for the purposes of meeting the requirements of this clause (b), it shall have been necessary to take into consideration any earned surplus of the Company, the Company shall not thereafter pay any dividends on or make any distributions in respect of, or make any payment for the purchase or other acquisition of, junior stock which would result in reducing the junior stock equity to an amount less than the amount payable on involuntary liquidation of the Company in respect of Senior Stock and all shares ranking on a parity with or having a priority over Senior Stock in respect of dividends or of payments in liquidation at the time outstanding. If during the period for which Income before Interest Charges is to be determined for the purpose set forth in this paragraph (2), the amount, if any, required to be expended by the Company during such period for property additions pursuant to a renewal and replacement fund or similar fund established under any indenture of mortgage or deed of trust of the Company shall exceed the amount deducted during such period in the determination of such Income before Interest Charges on account of depreciation and amortization of electric plan acquisition adjustments, such excess shall also be deducted in determining such Income before Interest Charges. B. So long as any Senior Stock is outstanding, the Company, without the affirmative vote or written consent of at least two-thirds in interest of the Senior Stock then outstanding voting or giving consent together as a class shall not authorize any shares of any class of stock having a priority over the Senior Stock in respect of dividends or of payments in liquidation or issue any shares of any such prior ranking stock more than 12 months after the date of the vote or consent authorizing such prior ranking stock. C. The provisions of this Article may be changed only by the affirmative vote or written consent of at least two-thirds in interest of the issued and outstanding shares of each class of capital stock of the Company voting or giving their consent in each case separately as a class; provided, however, that if any such change or proposed change would affect only one class of Senior Stock, then such change may be effected only by the affirmative vote or written consent of at least two-thirds in interest of the issued and outstanding shares of Common Stock and at least two-thirds in interest of the issued and outstanding shares of the class of Senior Stock that is affected, voting or giving their consent in each case separately as a class; and provided further, however, the holders of Senior Stock shall not be entitled to vote on an increase in the number of authorized shares of Preferred Stock or Class A Preferred Stock. In no event shall any reduction of the dividend rate or of the amounts payable upon redemption or liquidation with respect to any share of Senior Stock be made without the consent of the holder thereof, and no such reduction in respect of the shares of any particular series of Senior Stock shall be made without the consent of all the holders of shares of such series. D. No share of Senior Stock shall be deemed to be "outstanding" within the meaning of this Section 6 or of Section 7 if, at or prior to the time when the approval herein or therein referred to would otherwise be required, provision shall be made for its redemption, including a deposit complying with the requirements of subsection D of Section 3. Section 7. Merger, Consolidation or Sale of All Assets Except with the affirmative vote or written consent of a majority in interest of Senior Stock then outstanding voting or giving consent together as a class, the Company shall not merge or consolidate with or into any other corporation or sell or otherwise dispose of all or substantially all of its assets (except by mortgage or pledge) unless such merger, consolidation, sale or other disposition, or the issuance or assumption of securities in the effectuation thereof shall have been ordered, approved or permitted under the Public Utility Holding Company Act of 1935. Section 8. No Preemptive Right Except as otherwise expressly provided by law, the holders of Senior Stock shall have no preemptive right to subscribe to any further issue of additional shares of Senior Stock or of any other class of stock now or hereafter authorized, nor for any future issue of bonds, debentures, notes or other evidence of indebtedness or other security convertible into stock. If it is expressly required by law that, notwithstanding the provisions of the preceding sentence, any such further or future issue be offered proportionately to the stockholders, the holders of Preferred Stock only shall be entitled to subscribe for new or additional Preferred Stock, the holders of Class A Preferred Stock only shall be entitled to subscribe for new or additional Class A Preferred Stock and the holders of Common Stock only shall be entitled to subscribe for new or additional Common Stock; and notice of such increase as required by law need be given and the new shares need be offered proportionately only to the stockholders who are so entitled to subscribe. Section 9. Immunity of Directors, Officers and Agents No director, officer or agent of the Company shall be held personally responsible for any action taken in good faith though subsequently adjudged to be in violation of this Article. Section 10. Transfer Agent The Company shall always have at least one transfer agent for Senior Stock, which shall be an incorporated bank or trust company of good standing. ARTICLE XVII PROVISIONS WITH RESPECT TO THE SERIES OF PREFERRED STOCK 1. 7.72% Preferred Stock, Series B There shall be a series of Preferred Stock designated "7.72% Preferred Stock, Series B," and consisting of 200,000 shares with an aggregate par value of $20,000,000 and a par value per share of $100. The dividend rate and redemption prices as to said 7.72% Preferred Stock, Series B, shall be as follows: (a)Dividends on said 7.72% Preferred Stock, Series B, shall be at the rate of 7.72% per share per annum, and no more, and shall be cumulative from October 1, 1971. Said dividends, when declared, shall be payable on the first days of January, April, July and October in each year. (b)Redemption Prices of said 7.72% Preferred Stock, Series B, shall be $109.30 per share if redeemed on or before October 1, 1976, $107.37 per share if redeemed after October 1, 1976 and on or before October 1, 1981, $105.44 per share if redeemed after October 1, 1981 and on or before October 1, 1986, and $103.51 per share if redeemed after October 1, 1986, plus in all cases that portion of the quarterly dividend accrued thereon to the redemption date and all unpaid dividends thereon, if any, provided, however, that none of the 7.72% Preferred Stock, Series B shall be redeemed prior to October 1, 1976, if such redemption is for the purpose of or in anticipation of refunding such 7.72% Preferred Stock, Series B through the use, directly or indirectly, of finds borrowed by the Company or of the proceeds of the issue by the Company of shares of any stock ranking prior to or on a parity with the 7.72% Preferred Stock, Series B as to dividends or assets, if such borrowed funds or such shares have an effective interest cost or effective dividend cost to the Company (computed in accordance with generally accepted financial principles), as the case may be, of less than 7.69% per annum. 2. 7.60% Class A Preferred Stock, 1987 Series There shall be a series of Preferred Stock designated "7.60% Class A Preferred Stock, 1987 Series," and consisting of 1,200,000 shares with an aggregate par value of $30,000,000 and a par value per share of $25. The dividend rate and redemption prices as to said 7.60% Class A Preferred Stock, 1987 Series, shall be as follows: (a) Dividends on said 7.60% Class A Preferred Stock, 1987 Series, shall be at the rate of 7.60% per share per annum, and no more, and shall be cumulative from the date of issuance. Said dividends, when declared, shall be payable on the first days of February, May, August and November in each year, commencing May 1, 1987. (b) For each of the twelve month periods commencing February 1, 1987, the redemption prices of said 7.60% Class A Preferred Stock, 1987 Series, shall be the amount per share set forth below: Twelve Twelve Months Redemption Months Redemption Beginning Price Beginning Price February 1 Per Share February 1 Per Share 1987 $26.90 2000 $25.26 1988 26.90 2001 25.13 1989 26.90 2002 25.00 1990 26.90 2003 25.00 1991 26.90 2004 25.00 1992 26.27 2005 25.00 1993 26.14 2006 25.00 1994 26.02 2007 25.00 1995 25.89 2008 25.00 1996 25.76 2009 25.00 1997 25.64 2010 25.00 1998 25.51 2011 25.00 1999 25.38 plus in all cases that portion of the quarterly dividend accrued thereon to the redemption date and all unpaid dividends thereon, if any; provided, however, that none of the 7.60% Class A Preferred Stock, 1987 Series, shall be redeemed prior to February 1, 1992, if such redemption is for the purpose of or in anticipation of refunding such 7.60% Class A Preferred Stock, 1987 Series, through the use, directly or indirectly, of funds borrowed by the Company or of the proceeds of the issue by the Company of shares of any stock ranking prior to or on a parity with the 7.60% Class A Preferred Stock, 1987 Series, as to dividends or assets, if such borrowed funds or such shares have an effective interest cost or effective dividend cost to the Company (computed in accordance with generally accepted financial principles), as the case may be, of less than 7.69% per annum. (c) As and for a sinking fund for said 7.60% Class A Preferred Stock, 1987 Series, commencing on February 1, 1992, and on each February 1 in each year thereafter so long as any shares of the 7.60% Class A Preferred Stock, 1987 Series, remain outstanding, the Company shall, to the extent of any funds of the Company legally available therefor and except as otherwise restricted by the Company's Statement of Preferred Stock Provisions, redeem 60,000 shares of 7.60% Class A Preferred Stock, 1987 Series (or such lesser number of such shares as remain outstanding) at $25 per share plus accrued dividends to the date of redemption; provided, however, that if in any year the Company does not redeem the full number of shares of 7.60% Class A Preferred Stock, 1987 Series, required to be redeemed pursuant to this sinking fund, the deficiency shall be made good on the next succeeding February 1 on which the Company has funds legally available for, and is otherwise permitted to effect, the redemption of shares of 7.60% Class A Preferred Stock, 1987 Series, pursuant to this sinking fund. At the option of the Company, the number of shares of 7.60% Class A Preferred Stock, 1987 Series, redeemed on any February 1 may be reduced by the number of such shares purchased and canceled by the Company during the preceding twelve-month period or redeemed during such period pursuant to subsection (b) hereof. Any shares so redeemed or purchased and canceled may be given the status of authorized but unissued shares of Senior Stock, but none of such shares shall be reissued as shares of 7.60% Class A Preferred Stock, 1987 Series. The Company shall have the option, which shall be noncumulative, to redeem on February 1, 1992 and on each February 1 thereafter up to an additional 60,000 shares of 7.60% Class A Preferred Stock, 1987 Series, at the sinking fund redemption price. No such optional sinking fund shall operate to reduce the number of shares of the 7.60% Class A Preferred Stock, 1987 Series, required to be redeemed pursuant to the mandatory sinking fund provisions hereinabove set forth. In the event that the Company shall at any time fail to make a full mandatory sinking fund payment on any sinking fund payment date, the Company shall not pay any dividends or make any other distributions in respect of outstanding shares of any junior stock (as that term is defined in Subsection 2D of Section 2 of Article XVI of the by-laws of the Company) of the Company, other than dividends or distributions in shares of junior stock, or purchase or otherwise acquire for value any outstanding shares of junior stock, until all such payments have been made. 3. Dutch Auction Rate Transferable Securities Class A Preferred Stock, 1988 Series There shall be a series of Class A Preferred Stock designated "Dutch Auction Rate Transferable Securities Class A Preferred Stock, 1988 Series" (the "1988 DARTS") consisting of 2,140,000 shares with an aggregate par value of $53,500,000 and a par value per share of $25. The provisions governing the issue and sale of the 1988 DARTS in Units, certification, dividend rights, redemption, reacquisition, auction procedures, and other preferences, qualifications and special or relative rights or privileges with respect to the 1988 DARTS shall be as follows: (1) Units The 1988 DARTS shall be issued and sold by the Company only in units of 4,000 shares per unit ("Units"). No partial Units shall be issued and sold by the Company, and no fractional shares of the 1988 DARTS shall be issued and sold, no transfer of the 1988 DARTS in less than whole Units shall be made, nor shall any transfer in less than whole Units be registered on the transfer books of the Company or be effective for any purpose. (2) Certification Except as otherwise provided by law, all outstanding DARTS shall be represented by a certificate or certificates registered in the name of a nominee of the Securities Depository (as defined in Section (6)(a)(xxi) below), and no person acquiring Units shall be entitled to receive a certificate representing the 1988 DARTS. The nominee of the Securities Depository shall be the sole holder of record of the 1988 DARTS. Each purchaser of Units will receive dividends, distributions and notices according to the procedures of the Securities Depository and, if such purchaser is not a member of the Securities Depository, of such purchaser's Agent Member (as defined in Section (6)(a)(ii) below). (3) Dividend Rights (a) Dividends on the 1988 DARTS shall be paid, when, as and if declared by the Board of Directors of the Company out of funds legally available therefor, at the rate per annum determined as set forth below in subsection (c) of this Section (3) and no more (the "Applicable Rate"), payable on the respective dates set forth below. (b) Dividends on the 1988 DARTS shall accrue from the date of original issuance and shall be payable commencing on May 3, 1988, and on each succeeding seventh Tuesday thereafter, except that if any of such Tuesday, the Monday preceding such Tuesday, or the Wednesday following such Tuesday is not a Business Day (as defined below), then (i) the dividend payment date shall be the first Business Day after such Tuesday that is immediately followed by a Business Day and is preceded by a Business Day that is the preceding Monday or a day after such Monday, or (ii) if the Securities Depository shall make available to its participants and members, in funds immediately available in New York City on dividend payment dates, the amount due as dividends on such dividend payment dates (and the Securities Depository shall have so advised the Trust Company (as defined in Section (6)(a)(xxx) below)), then the dividend payment date shall be the first Business Day on or after such Tuesday that is preceded by a Business Day that is the preceding Monday or a day after such Monday. "Business Day" means a day on which the New York Stock Exchange is open for trading and which is not a day on which banks in New York City are authorized by law to close. Each dividend payment date determined as provided above is referred to herein as the "Dividend Payment Date." Although any particular Dividend Payment Date may not occur on the originally scheduled Tuesday because of the exceptions discussed above, the next succeeding Dividend Payment Date shall be, subject to such exceptions, the seventh Tuesday following the originally designated Tuesday Dividend Payment Date for the prior Dividend Period. As used herein, Dividend Period means the period commencing on a Dividend Payment Date for DARTS and ending on the day next preceding the next Dividend Payment Date. Notwithstanding the foregoing, in the event of a change in law altering the minimum holding period (currently found in Section 246(c) of the Internal Revenue Code of 1986, as amended (the "Code")) required for taxpayers to be entitled to the dividends received deduction on preferred stock held by non-affiliated corporations (currently found in Section 243(a) of the Code), the Company shall adjust the period of time between Dividend Payment Dates so as to adjust uniformly the number of days (such number of days without giving effect to the exceptions referred to above being hereinafter referred to as "Dividend Period Days") in Dividend Periods commencing after the date of such change in law to equal or exceed the then current minimum holding period; provided that the number of Dividend Period Days shall not exceed by more than nine days the length of such then current minimum holding period and shall be evenly divisible by seven, and the maximum number of Dividend Period Days in no event shall exceed 98 days. Upon any such change in the number of Dividend Period Days as a result of a change in law, the Company shall give notice of such change to all Existing Holders of Units. (c) The dividend rate on shares of the 1988 DARTS during the period from and after the date of original issuance to the Initial Dividend Payment Date (the "Initial Dividend Period") shall be 6.375 percent per annum. Commencing on the Initial Dividend Payment Date, the dividend rate on shares of the 1988 DARTS for each subsequent Dividend Period shall be at a rate per annum that results from the implementation of the Auction procedures set forth in Section (6) below. The amount of dividends per Unit for the 1988 DARTS payable for each Dividend Period shall be computed by multiplying the dividend rate for such series for each Dividend Period determined in accordance with subsection (c) above by a fraction the numerator of which shall be the number of days in such Dividend Period (calculated by counting the first day thereof but excluding the last day thereof) such Unit was outstanding and the denominator of which shall be 360, and multiplying the amount so obtained by $100,000 per Unit. (d) Prior to each Dividend Payment Date, the Company shall pay to the Trust Company sufficient funds for the payment of declared dividends. (e) For the purpose of determining whether and when holders of the Senior Stock are entitled to the rights to elect certain directors of the Company, described under Article XVI, Section 5(c) of these By-laws, dividends on the DARTS shall be deemed to be in arrears "in an amount equal to or exceeding four quarterly dividend payments," if, at the time dividends are in arrears for four quarterly dividend payments for Senior Stock having quarterly dividend payments, dividends on the 1988 DARTS are in arrears for each Dividend Period beginning on or after the first day of the first of the four quarterly dividend periods as to which dividends on the Senior Stock having quarterly dividends are in arrears. (4) Redemption Provisions (a) At the option of the Company, the Units may be redeemed out of funds legally available therefor in whole on any Dividend Payment Date at a redemption price of $25 per share of the 1988 DARTS ($100,000 per Unit) plus accrued and unpaid dividends (whether or not earned or declared) to the redemption date. Only whole Units may be redeemed. See Section (5) below for restrictions on the reissue of Units after redemption. (b) In accordance with Article XVI, Section 3 of these By-laws, notice of redemption shall be mailed to each record holder of Units and to the Trust Company not less than 30 days prior to the date fixed for redemption thereof. Each notice of redemption shall include a statement setting forth: (i) the redemption date, (ii) the number of Units to be redeemed, (iii) the redemption price, (iv) the place or places where Units are to be surrendered for payment of the redemption price, and (v) that dividends of the Units to be redeemed will cease to accrue on such redemption date. No defect in the notice of redemption or in the mailing thereof shall affect the validity of the redemption proceedings, except as required by applicable law. (c) If less than all of the outstanding Units are to be redeemed, the number of Units to be redeemed shall be determined by the Company and communicated to the Trust Company. In accordance with Article XVI, Section 3A of these By-laws, the Trust Company shall give notice to the Securities Depository and the Securities Depository will determine by lot under its usual operating procedures the number of Units, if any, to be redeemed from the account of the Agent Member of each Existing Holder. An Agent Member may determine to redeem Units from some Existing Holders without redeeming Units from the accounts of other Existing Holders. (5) Reacquisition Except in an Auction (as defined in Section (6)(a)(iii) below), the Company shall have the right, in accordance with Article XVI, Section 3E of these By-laws, and where permitted by applicable law, to purchase or otherwise acquire Units upon the best terms reasonably obtainable, but not exceeding the then current redemption price of such Units, except that no such purchase shall be made if the Company shall be in arrears in respect to payment of dividends on any shares of Senior Stock outstanding or if there shall exist an event of default as defined in Article XVI, Section 5 of these By-laws. Notwithstanding the provisions of Article XVI, Section 3D of these By-laws, Units that have been redeemed, purchased or otherwise acquired by the Company shall not be reissued as 1988 DARTS and shall either be restored to authorized but unissued shares of the Company's Class A Preferred Stock or canceled at the Company's option. (6) Auction Procedures (a) Certain Definitions. As used in this Section 6 of these Provisions with Respect to the series of Senior Stock, the following terms shall have the following meanings, unless the context otherwise requires: (i) "Affiliate" shall mean any Person known to the Trust Company to be controlled by, in control of, or under common control with the Company. (ii) "Agent Member" shall mean the member of the Securities Depository that will act on behalf of a Bidder and is identified as such in such Bidder's Purchaser's Letter. (iii) "Auction" shall mean the periodic operation of the procedures set forth herein. (iv) "Auction Date" shall mean the Business Day next preceding a Dividend Payment Date. (v) "Available Units" shall have the meaning specified in paragraph (d)(i)(A) below. (vi) "Bid" shall have the meaning specified in paragraph (b)(i) below. (vii) "Bidder" shall have the meaning specified in paragraph (b)(i) below. (viii) "Board of Directors" shall mean the Board of Directors of the Company. (ix) "Broker-Dealer" shall mean any broker-dealer, or other entity permitted by law to perform the functions required of a Broker-Dealer herein, that has been selected by the Company and has entered into a Broker-Dealer Agreement with the Trust Company that remains effective. (x) "Broker-Dealer Agreement" shall mean an agreement between the Trust Company and a Broker-Dealer pursuant to which such Broker-Dealer agrees to follow the procedures specified herein. (xi) "DARTS" or "1988 DARTS" shall mean the 2,140,000 shares of Dutch Auction Rate Transferable Securities Class A Preferred Stock, 1988 Series, $25 Par Value, of the Company. (xii) "Existing Holder," when used with respect to Units, shall mean a Person who has signed a Purchaser's Letter and is listed as the beneficial owner of such Units in the records of the Trust Company. (xiii) "Hold Order" shall have the meaning specified in paragraph (b)(i) below. (xiv) "Maximum Applicable Rate," on any Auction Date, shall mean the percentage of the 60-day "AA" Composite Commercial Paper Rate (as defined below) in effect on such Auction Date, determined as set forth below based on the prevailing rating of the DARTS in effect at the close of business on the day preceding such Auction Date: Prevailing Rating Percentage AA/aa or Above........................... 110% A/a...................................... 120% BBB/baa.................................. 130% BB/ba.................................... 175% Below BB/ba.............................. 200% For purposes of this definition, the "prevailing rating" of the DARTS shall be (i) AA/aa or Above, if the DARTS have a rating of AA- or better by Standard & Poor's Corporation or its successor ("S&P") and aa3 or better by Moody's Investors Service, Inc. or its successor ("Moody's"), or the equivalent of both of such ratings by such agencies or a substitute rating agency or substitute rating agencies selected as provided below, (ii) if not AA/aa or Above, then A/a, if the DARTS have a rating of A- or better by S&P and a3 or better by Moody's or the equivalent of both of such ratings by such agencies or a substitute rating agency or substitute rating agencies selected as provided below, (iii) if not AA/aa or Above or A/a, then BBB/Baa, if the DARTS have a rating of BBB- or better by S&P and baa3 or better by Moody's or the equivalent of both of such ratings by such agencies or a substitute rating agency or substitute rating agencies selected as provided below, and (iv) if not AA/aa or Above, A/a or BBB/baa, then BB/ba, if the DARTS have a rating of BB- or better by S&P and Ba3 or better by Moody's, or the equivalent of both of such ratings by such agencies or a substitute rating agency or substitute rating agencies selected as provided below, and (v) if not AA/aa or Above, A/a, BBB/baa or BB/ba, then Below BB/ba. The Company shall take all reasonable action necessary to enable S&P and Moody's to provide a rating for the DARTS. If either S&P or Moody's shall not make such a rating available, or neither S&P nor Moody's shall make such a rating available, Salomon Brothers Inc and Morgan Stanley & Co. Incorporated, or their successors shall select a nationally recognized securities rating agency or two nationally recognized securities rating agencies to act as substitute rating agency or substitute rating agencies, as the case may be. (xv) "Minimum Applicable Rate," on any Auction Date, shall mean 59% of the 60-day "AA" Composite Commercial Paper Rate in effect on such Auction Date. (xvi) "Order" shall have the meaning specified in paragraph(b)(i) below. (xvii) "Outstanding" shall mean, as of any date, the DARTS theretofore issued by the Company except, without duplication, (A) any DARTS theretofore canceled or delivered to the Trust Company for cancellation, or redeemed by the Company, or as to which a notice of redemption shall have been given by the Company, (B) any DARTS as to which the Company or any Affiliate thereof shall be an Existing Holder and (C) any DARTS represented by any certificate in lieu of which a new certificate has been executed and delivered by the Company. (xviii) "Person" shall mean and include an individual, a partnership, a corporation, a trust, an unincorporated association, a joint venture or other entity or a government or any agency or political subdivision thereof. (xix) "Potential Holder" shall mean any Person, including any Existing Holder, (A) who shall have executed and delivered or caused to be delivered a Purchaser's Letter to the Trust Company and (B) who may be interested in acquiring Units (or, in the case of an Existing Holder, additional Units). (xx) "Purchaser's Letter" shall mean a letter addressed to the Company, the Trust Company, Broker-Dealer and other persons in which a Person agrees, among other things, to offer to purchase, purchase, offer to sell and/or sell Units as set forth herein. (xxi) "Securities Depository" shall mean The Depository Trust Company and its successors and assigns or any other securities depository selected by the Company which agrees to follow the procedures required to be followed by such securities depository in connection with the DARTS. (xxii) "Sell Order" shall have the meaning specified in paragraph (b)(i) below. (xxiii) "60-day 'AA' Composite Commercial Paper Rate," on any date, means (i) the interest equivalent of the 60-day rate on commercial paper placed on behalf of issuers whose corporate bonds are rated "AA" by S&P or the equivalent of such rating by S&P or another rating agency, as such 60-day rate is made available on a discount basis or otherwise by the Federal Reserve Bank of New York for the Business Day immediately preceding such date, or (ii) in the event that the Federal Reserve Bank of New York does not make available such a rate, then the interest equivalent of the 60-day rate on commercial paper placed on behalf of such issuers, as quoted on a discount basis or otherwise by Morgan Stanley & Co. Incorporated or, in lieu thereof, any affiliates or successor thereof (the "Commercial Paper Dealer"), to the Trust Company for the close of business on the Business Day immediately preceding such date. If the Commercial Paper Dealer does not quote a rate required to determine the 60-day "AA" Composite Commercial Rate, the 60-day "AA" Composite Commercial Paper Rate shall be determined on the basis of the quotation or quotations furnished by any Substitute Commercial Paper Dealer or Substitute Commercial Paper Dealers selected by the Company to provide such rate. If the Company, however, shall adjust the number of Dividend Period Days in the event of a change in the dividends received deduction minimum holding period contained in the Internal Revenue Code of 1986, as amended, with the result that (i) the Dividend Period Days shall be fewer than 70 days, such rate shall be the interest equivalent of the 60-day rate on such commercial paper, (ii) the Dividend Period Days shall be 70 or more days but fewer than 85 days, such rate shall be the arithmetic average of the interest equivalent of the 60-day and 90-day rates on such commercial paper, and (iii) the Dividend Period Days shall be 85 or more days but 98 or fewer days, such rate shall be the interest equivalent of the 90-day rate on such commercial paper. For the purposes of such definition, "interest equivalent" means the equivalent yield on a 360-day basis of a discount basis security to an interest-bearing security and "Substitute Commercial Paper Dealer" shall mean any commercial paper dealer that is a leading dealer in the commercial paper market, provided that neither such dealer nor any of its affiliates is a Commercial Paper Dealer. (xxiv) "Submission Deadline" shall mean 12:30 P.M., New York City time, on any Auction Date or such other time on any Auction Date by which Broker-Dealers are required to submit Orders to the Trust Company as specified by the Trust Company from time to time. (xxv) "Submitted Bid" shall have the meaning specified inparagraph (d)(i) below. (xxvi) "Submitted Hold Order" shall have the meaning specified in paragraph (d)(i) below. (xxvii) "Submitted Order" shall have the meaning specified in paragraph (d)(i) below. (xxviii) "Submitted Sell Order" shall have the meaning specified in paragraph (d)(i) below. (xxvix) "Sufficient Clearing Bids" shall have the meaning specified in paragraph (d)(i) below. (xxx) "Trust Company" shall mean Bankers Trust Company and its successor, and assigns or any other bank, trust company or other entity selected by the Company which agrees to follow the Auction Procedures described in this Section (6) for the purposes of determining the Applicable Rate for the DARTS. (xxxi) "Winning Bid Rate" shall have the meaning specified in paragraph (d)(i) below. (b) Orders by Existing Holders and Potential Holders (i) On or prior to each Auction Date: (A) each Existing Holder may submit to a Broker-Dealer information as to: (1) the number of Outstanding Units, if any, held by such Existing Holder which such Existing Holder desires to continue to hold without regard to the Applicable Rate for the next succeeding Dividend Period; (2) the number of Outstanding Units, if any, held by such Existing Holder which such Existing Holder desires to continue to hold, provided that the Applicable Rate for the next succeeding Dividend Period shall not be less than the rate per annum specified by such Existing Holder; and/or (3) the number of Outstanding Units, if any, held by such Existing Holder which such Existing Holder offers to sell without regard to the Applicable Rate for the next succeeding Dividend Period; and (B) Each Broker-Dealer, using a list of Potential Holders that shall be maintained in good faith for the purpose of conducting a competitive Auction shall contact Potential Holders, including Persons that are not Existing Holders, on such list to determine the number of Outstanding Units, if any, which each such Potential Holder offers to purchase, provided that the Applicable Rate for the next succeeding Dividend Period shall not be less than the rate per annum specified by such Potential Holder. For the purposes hereof, the communication to a Broker-Dealer of information referred to in clause (A) or (B) of this paragraph (b)(i) is hereinafter referred to as an "Order" and each Existing Holder and each Potential Holder placing an Order is hereinafter referred to as a "Bidder"; and Order containing the information referred to in clause (A)(1) of this paragraph (b)(i) is hereinafter referred to as a "Hold Order"; an Order containing the information referred to in clause (A)(2) or (B) of this paragraph (b)(i) is hereinafter referred to as a "Bid"; and an Order containing the information referred to in clause (A)(3) of this paragraph (b)(i) is hereinafter referred to as a "Sell Order." (ii) (A) A Bid by an Existing Holder shall constitute an irrevocable offer to sell: (1) the number of Outstanding Units specified in such Bid if the Applicable Rate determined on such Auction Date shall be less than the rate specified therein; or (2) such number or a lesser number of Outstanding Units to be determined as set forth in paragraph (e)(i)(D) if the Applicable Rate determined on such Auction Date shall be equal to the rate specified therein; or (3) a lesser number of Outstanding Units to be determined as set forth in paragraph (e)(ii)(C) if such specified rate shall be higher than Maximum Applicable Rate and Sufficient Clearing Bids do not exist. (B) A Sell Order by an Existing Holder shall constitute an irrevocable offer to sell: (1) the number of Outstanding Units specified in such Sell Order; or (2) such number or a lesser number of Outstanding Units to be determined as set forth in paragraph (e)(ii)(C) if Sufficient Clearing Bids do not exist. (C) A Bid by a Potential Holder shall constitute an irrevocable offer to purchase: (1) the number of Outstanding Units specified in such Bid if the Applicable Rate determined on such Auction Date shall be higher than the rate specified therein; or (2) such number of a lesser number of Outstanding Units to be determined as set forth in paragraph (e)(i)(E) if the Applicable Rate determined on such Auction Date shall be equal to the rate specified therein. (c) Submission of Orders by Broker-Dealers to Trust Company (i) Each Broker-Dealer shall submit in writing to the Trust Company prior to the Submission Deadline on each Auction Date all Orders obtained by such Broker-Dealer and specifying with respect to each Order: (A) the name of the Bidder placing such Order; (B) the aggregate number of Outstanding Units that are subject of such Order; (C) to the extent that such Bidder is an Existing Holder: (1) the number of Outstanding Units, if any, subject to any Hold Order placed by such Existing Holder; (2) the number of Outstanding Units, if any, subject to any Bid placed by such Existing Holder and the rate specified in such Bid; and (3) the number of Outstanding Units, if any, subject to any Sell Order placed by such Existing Holder; and (D) to the extent such Bidder is a Potential Holder, the rate specified in such Potential Holder's Bid. (ii) If any rate specified in any Bid contains more than three figures to the right of the decimal point, the Trust Company shall round such rate up to the next highest one-thousandth (.001) of 1%. (iii) If an Order or Orders covering all of the Outstanding Units held by an Existing Holder is not submitted to the Trust Company prior to the Submission Deadline, the Trust Company shall deem a Hold Order to have been submitted on behalf of such Existing Holder covering the number of Outstanding Units held by such Existing Holder and not subject to Orders submitted to the Trust Company. (iv) If one or more Orders covering in the aggregate more than the number of Outstanding Units held by an Existing Holder are submitted to the Trust Company, such Orders shall be considered valid as follows and in the following order or priority: (A) any Hold Order submitted on behalf of such Existing Holder shall be considered valid up to and including the number of Outstanding Units held by such Existing Holder; provided that if more than one Hold Order is submitted on behalf of such Existing Holder and the number of Units subject to such Hold Orders exceeds the number of Outstanding Units held by such Existing Holder, the number of Units subject to such Hold Orders shall be reduced pro rata so that such Hold Orders shall cover the number of Outstanding Units held by such Existing Holder; (B) (1) any Bid shall be considered valid up to and including the excess of the number of Outstanding Units held by such Existing Holder over the number of Units subject to Hold Orders referred to in paragraph (c)(iv)(A); (2) subject to clause (1) above, if more than one Bid with the same rate is submitted on behalf of such Existing Holder and the number of Outstanding Units subject to such Bids is greater than such excess, the number of Outstanding Units subject to such Bids shall be reduced pro rata so that such Bids shall cover the number of Outstanding Units equal to such excess; and (3) subject to clause (1) above, if more than one Bid with different rates is submitted on behalf of such Existing Holder, such Bids shall be considered valid in the ascending order of their respective rates and in any such event the number, if any, of such Outstanding shares subject to Bids not valid under this clause (B) shall be treated as the subject of a Bid by a Potential Holder; and (C) any Sell Order shall be considered valid up to and including the excess of the number of Outstanding Units held by such Existing Holder over the number of Outstanding Units subject to Hold Orders referred to in paragraph (c)(iv)(A) and Bids referred to in paragraph (c)(iv)(B). (v) If more than one Bid is submitted on behalf of any Potential Holder, each Bid submitted shall be a separate Bid with the rate and Units therein specified. (vi) If any rate specified in any Bid is lower than the Minimum Applicable Rate for the Dividend Period to which such Bid relates, such Bid shall be deemed to be a Bid specifying a rate equal to such Minimum Applicable Rate. (vii) Orders by Existing Holders and Potential Holders must specify numbers of Units in whole Units. Any Order that specifies a number of Units other than in whole shares will be invalid and will not be considered a Submitted Order for purposes of an Auction. (d) Determination of Sufficient Clearing Bids, Winning Bid Rate and Applicable Rate (i) Not earlier than the Submission Deadline on each Auction Date, the Trust Company shall assemble all Orders submitted or deemed submitted to it by the Broker-Dealers (each such Order as submitted or deemed submitted by a Broker-Dealer being hereinafter referred to individually as a "Submitted Hold Order" a "Submitted Bid" or a "Submitted Sell Order," as the case may be, or as a "Submitted Order") and shall determine: (A) the excess of the total number of Outstanding Units over the number of Outstanding Units that are the subject of Submitted Hold Orders (such excess being hereinafter referred to as the "Available Units"); (B) from the Submitted Orders, whether: (1) the number of Outstanding Units that are the subject of Submitted Bids by Potential Holders specifying one or more rates equal to or lower than the Maximum Applicable Rate exceeds or is equal to the sum of: (2) [a] the number of Outstanding Units that are the subject of Submitted Bids by Existing Holders specifying one or more rates higher than the Maximum Applicable Rate, and [b] the number of Outstanding Units that are subject to Submitted Sell Orders (if such excess of such equality exists (other than because the number of Outstanding Units in clauses [a] and [b] above are each zero because all of the Outstanding Units are the subject of Submitted Hold Orders), such Submitted Bids in clause (1) above being hereinafter referred to collectively as "Sufficient Clearing Bids"); and (C) if Sufficient Clearing Bids exist, the lowest rate specified in the Submitted Bids (the "Winning Bid Rate"), which if: (1) each Submitted Bid from Existing Holders specifying the Winning Bid Rate and all other Submitted Bids from Existing Holders specifying lower rates were rejected, thus entitling such Existing Holders to continue to hold the Units that are the subject of such Submitted Bids, and (2) each Submitted Bid from Potential Holders specifying the Winning Bid Rate and all other Submitted Bids from Potential Holders specifying lower rates were accepted, thus entitling the Potential Holders to purchase the Units that are the subject of such Submitted Bids, would result in the number of shares subject to all Submitted Bids specifying the Winning Bid Rate or a lower rate being at least equal to the Available Units. (ii) Promptly after the Trust Company has made the determinations pursuant to paragraph (d)(i), the Trust Company shall advise the Company of the Maximum Applicable Rate and the Minimum Applicable Rate and, based on such determinations, the Applicable Rate for the next succeeding Dividend Period as follows: (A) if Sufficient Clearing Bids exist, that the Applicable Rate for the next succeeding Dividend Period shall be equal to the Winning Bid Rate so determined; (B) if Sufficient Clearing Bids do not exist (other than because all of the Outstanding Units are the subject of Submitted Hold Orders), that the Applicable Rate for the next succeeding Dividend Period shall be equal to the Maximum Applicable Rate; or (C) if all the Outstanding Units are the subject of Submitted Hold Orders, that the Applicable Rate for the next succeeding Dividend Period shall be equal to the Minimum Applicable Rate. (e) Acceptance and Rejection of Submitted Bids and Submitted Sell Orders and Allocation of Shares Based on the determinations made pursuant to paragraph (d)(i), the Submitted Bids and Submitted Sell Orders shall be accepted or rejected and the Trust Company shall take such other action as set forth below: (i) If Sufficient Clearing Bids have been made, subject to the provisions of paragraphs (e)(iii) and (e)(iv), Submitted Bids and Submitted Sell Orders shall be accepted or rejected in the following order or priority and all other Submitted bids shall be rejected: (A) the Submitted Sell Orders of Existing Holders shall be accepted and the Submitted Bid of each of the Existing Holders specifying any rate that is higher than the Winning Bid Rate shall be rejected, thus requiring each such Existing Holder to sell the Outstanding Units that are the subject of such Submitted Bid; (B) the Submitted Bid of each of the Existing Holders specifying any rate that is lower than the Winning Bid Rate shall be accepted, thus entitling each such Existing Holder to continue to hold the Outstanding Units that are the subject of such Submitted Bid; (C) the Submitted Bid of each of the Potential Holders specifying any rate that is lower than the Winning Bid Rate shall be accepted; (D) the Submitted Bid of each of the Existing Holders specifying a rate that is equal to the Winning Bid Rate shall be accepted, thus entitling each such Existing Holder to continue to hold the Outstanding Units that are the subject of such Submitted Bid, unless the number of Outstanding Units subject to all such Submitted Bids shallbe greater than the number of Outstanding Units ("remaining shares") equal to the excess of the Available Units over the number of Outstanding Units subject to Submitted Bids described in paragraphs (e)(i)(B) and (e)(i)(C), in which event the Submitted Bids of each such Existing Holder shall be rejected, and each such Existing Holder shall be required to sell Outstanding Units, but only in an amount equal to the difference between (1) the number of Outstanding Units then held by such Existing Holder subject to such Submitted Bid and (2) the number of Units obtained by multiplying (x) the number of remaining shares by (y) a fraction the numerator of which shall be the number of Outstanding Units held by such Existing Holder subject to such Submitted Bid and the denominator of which shall be the sum of the number of Outstanding Units subject to such Submitted Bids made by all such Existing Holders that specified a rate equal to the Winning Bid Rate; and (E) the Submitted Bid of each of the Potential Holders specifying a rate that is equal to the Winning Bid Rate shall be accepted but only in an amount equal to the number of Outstanding Units obtained by multiplying (x) the difference between the Available Units and the number of Outstanding Units subject to the Submitted Bids described inparagraphs (e)(i)(B), (e)(i)(C) and (e)(i)(D) by (y) a fraction the numerator of which shall be the number of Outstanding shares of Units subject to such Submitted Bid and the denominator of which shall be the sum of the number of Outstanding Units subject to such Submitted Bids made by all such Potential Holders that specified rates equal to the Winning Bid Rate. (ii) If Sufficient Clearing Bids have been made (other than because all of the Outstanding Units are subject to Submitted Hold Orders), subject to the provisions of paragraphs (e)(iii) and (e)(iv), Submitted Orders shall be accepted or rejected as follows in the following order of priority and all other Submitted Bids shall be rejected: (A) the Submitted Bid of each Existing Holder specifying any rate that is equal to or lower than the Maximum Applicable Rate shall be accepted, thus entitling such Existing Holder to continue to hold the Outstanding Units that are the subject of such Submitted Bid; (B) the Submitted Bid of each Potential Holder specifying any rate that is equal to or lower than the Maximum Applicable Rate shall be accepted, thus requiring such Potential Holder to purchase the Outstanding Units that are the subject of such Submitted Bid; and (C) the Submitted Bids of each Existing Holder specifying any rate that is higher than the Maximum Applicable Rate shall be rejected and the Submitted Sell Orders of each Existing Holder shall be accepted, in both cases only in an amount equal to the difference between (1) the number of Outstanding Units then held by such Existing Holder subject to such Submitted Bid or Submitted Sell Order and (2) the number of Units obtained by multiplying (x) the difference between the Available Units and the aggregate number of Outstanding Units subject to Submitted Bids described in paragraphs (e)(ii)(A) and (e)(ii)(B) by (y) a fraction the numerator of which shall be the number of Outstanding Units held by such Existing Holder subject to such Submitted Bid or Submitted Sell Order and the denominator of which shall be the number of Outstanding Units subject to all such Submitted Bids and Submitted Sell Orders. (iii) If, as a result of the procedures described in paragraph (e)(i) or (e)(ii), any Existing Holder would be entitled or required to sell, or any Potential Holder would be entitled or required to purchase, a fraction of a Unit on any Auction Date, the Trust Company shall, in such manner as, in its sole discretion, it shall determine, round up or down the number of Units to be purchased or sold by any Existing Holder or Potential Holder on such Auction Date so that the number of Outstanding shares purchased or sold by each Existing Holder or Potential Holder on such Auction Date shall be whole Units. (iv) If, as a result of the procedures described in paragraph (e)(i), any Potential Holder would be entitled or required to purchase less than a whole Unit on any Auction Date, the Trust Company shall, in such manner as, in its sole discretion, it shall determine, allocate Units for purchase among Potential Holders so that only whole Units are purchased on such Auction Date by any Potential Holder, even if such allocation results in one or more of such Potential Holders not purchasing Units on such Auction Date. (v) Based on the results of each Auction, the Trust Company shall determine the aggregate number of Outstanding Units to be purchased and the aggregate number of Outstanding Units to be sold by Potential Holders and Existing Holders on whose behalf each Broker-Dealer submitted Bids or Sell Orders, and, with respect to each Broker-Dealer, to the extent that such aggregate number of Outstanding shares to be purchased and such aggregate number of Outstanding shares to be sold differ, determine to which other Broker-Dealer or Broker-Dealers acting for one or more purchasers such Broker-Dealer shall deliver, or from which other Broker-Dealer or Broker-Dealers acting for one or more sellers such Broker-Dealer shall receive, as the case may be, Outstanding Units. (f) Miscellaneous The Board of Directors may interpret the provisions of these Auction Procedures to resolve any inconsistency or ambiguity, and may remedy any formal defect or make any other change or modification which does not adversely affect the rights of Existing Holders of Units. An Existing Holder (A) may sell, transfer or otherwise dispose of Units only pursuant to a Bid or Sell Order in accordance with the procedures described in this paragraph or to or through a Broker-Dealer or to a Person that has delivered a signed copy of a Purchaser's Letter to the Trust Company, provided that in the case of all transfers other than pursuant to Auctions such Existing Holder, its Broker-Dealer or its Agent Member advises the Trust Company of such transfer and (B) shall have the ownership of the Units held by it maintained in book entry form by the Securities Depository in the account of its Agent Member, which in turn will maintain records of such Existing Holder's beneficial ownership. Neither the Company nor any Affiliate shall submit an Order, either directly or indirectly, in any Auction. Except as otherwise provided by law, all of the Outstanding Units shall be represented by a certificate registered in the name of the nominee of the Securities Depository and no Person acquiring Units shall be entitled to receive a certificate representing such shares. (g) Headings of Subdivisions The headings of the various subdivisions of these Auction Procedures are for convenience of reference only and shall not affect the interpretation of any of the provisions hereof. ARTICLE XVIII AMENDMENTS Except as otherwise provided in Article XVI hereof, these By-Laws may be altered, amended or repealed at any meeting of the stockholders called for the purpose by vote of a majority of stock present and voting thereon EX-4.2.15 4 SUPPLEMENTAL INDENTURE Dated as of June 1, 1994 TO Indenture of Mortgage and Deed of Trust Dated as of May 1, 1921 THE CONNECTICUT LIGHT AND POWER COMPANY TO BANKERS TRUST COMPANY, Trustee 1994 Series C Bonds, Due June 1, 2024 THE CONNECTICUT LIGHT AND POWER COMPANY Supplemental Indenture, Dated as of June 1, 1994 TABLE OF CONTENTS PAGE Parties 1 Recitals 1 Granting Clauses 2 Habendum 2 Grant in Trust 2 ARTICLE 1. FORM AND PROVISIONS OF BONDS OF SERIES C SECTION 1.01. Designation; Amount 3 SECTION 1.02. Form of Bonds of Series C 3 SECTION 1.03. Provisions of Bonds of Series C; Interest Accrual 3 SECTION 1.04. Transfer and Exchange of Bonds of Series C 4 SECTION 1.05. Sinking and Improvement Fund 4 ARTICLE 2. REDEMPTION OF BONDS OF SERIES C 4 ARTICLE 3. MISCELLANEOUS SECTION 3.01. Benefits of Supplemental Indenture and Bonds of Series C 5 SECTION 3.02. Effect of Table of Contents and Headings 5 SECTION 3.03. Counterparts 5 TESTIMONIUM 5 SIGNATURES 5 ACKNOWLEDGMENTS 6 SCHEDULE A - Form of Bond of Series C, Form of Trustee's Certificate 7 SCHEDULE B - Property Subject to the Lien of the Mortgage 12 SUPPLEMENTAL INDENTURE, dated as of the first day of June, 1994, between THE CONNECTICUT LIGHT AND POWER COMPANY, a corporation organized and existing under the laws of the State of Connecticut (hereinafter called "Company") and BANKERS TRUST COMPANY, a corporation organized and existing under the laws of the State of New York (hereinafter called "Trustee"). WHEREAS, the Company heretofore duly executed, acknowledged and delivered to the Trustee a certain Indenture of Mortgage and Deed of Trust dated as of May 1, 1921, and sixty-one Supplemental Indentures thereto dated respectively as of May 1, 1921, February 1, 1924, July 1, 1926, June 20, 1928, June 1, 1932, July 1, 1932, July 1, 1935, September 1, 1936, October 20, 1936, December 1, 1936, December 1, 1938, August 31, 1944, September 1, 1944, May 1, 1945, October 1, 1945, November 1, 1949, December 1, 1952, December 1, 1955, January 1, 1958, February 1, 1960, April 1, 1961, September 1, 1963, April 1, 1967, May 1, 1967, January 1, 1968, October 1, 1968, December 1, 1969, January 1, 1970, October 1, 1970, December 1, 1971, August 1, 1972, April 1, 1973, March 1, 1974, February 1, 1975, September 1, 1975, May 1, 1977, March 1, 1978, September 1, 1980, October 1, 1981, June 30, 1982, October 1, 1982, July 1, 1983, January 1, 1984, October 1, 1985, September 1, 1986, April 1, 1987, October 1, 1987, November 1, 1987, April 1, 1988, November 1, 1988, June 1, 1989, September 1, 1989, December 1, 1989, April 1, 1992, July 1, 1992, October 1, 1992, July 1, 1993, July 1, 1993, December 1, 1993, February 1, 1994 and February 1, 1994 (said Indenture of Mortgage and Deed of Trust (i) as heretofore amended, being hereinafter generally called the "Mortgage Indenture," and (ii) together with said Supplemental Indentures thereto, being hereinafter generally called the "Mortgage"), all of which have been duly recorded as required by law, for the purpose of securing its First and Refunding Mortgage Bonds (of which $1,330,176,000 aggregate principal amount are outstanding at the date of this Supplemental Indenture) to an unlimited amount, issued and to be issued for the purposes and in the manner therein provided, of which Mortgage this Supplemental Indenture is intended to be made a part, as fully as if therein recited at length; WHEREAS, the Company by appropriate and sufficient corporate action in conformity with the provisions of the Mortgage has duly determined to create a further series of bonds under the Mortgage to be designated "First and Refunding Mortgage 8-1/2% Bonds, 1994 Series C" (hereinafter generally referred to as the "bonds of Series C"), to consist of fully registered bonds containing terms and provisions duly fixed and determined by the Board of Directors of the Company and expressed in this Supplemental Indenture, such fully registered bonds and the Trustee's certificate of its authentication thereof to be substantially in the forms thereof respectively set forth in Schedule A appended hereto and made a part hereof; and WHEREAS, the execution and delivery of this Supplemental Indenture and the issue of not in excess of one hundred and fifteen million dollars ($115,000,000) in aggregate principal amount of bonds of Series C and other necessary actions have been duly authorized by the Board of Directors of the Company; and WHEREAS, the Company proposes to execute and deliver this Supplemental Indenture to provide for the issue of the bonds of Series C and to confirm the lien of the Mortgage on the property referred to below, all as permitted by Section 14.01 of the Mortgage Indenture; and WHEREAS, all acts and things necessary to constitute this Supplemental Indenture a valid, binding and legal instrument and to make the bonds of Series C, when executed by the Company and authenticated by the Trustee valid, binding and legal obligations of the Company have been authorized and performed; NOW, THEREFORE, THIS SUPPLEMENTAL INDENTURE OF MORTGAGE AND DEED OF TRUST WITNESSETH: That in order to secure the payment of the principal of and interest on all bonds issued and to be issued under the Mortgage, according to their tenor and effect, and according to the terms of the Mortgage and this Supplemental Indenture, and to secure the performance of the covenants and obligations in said bonds and in the Mortgage and this Supplemental Indenture respectively contained, and for the better assuring and confirming unto the Trustee, its successor or successors and its or their assigns, upon the trusts and for the purposes expressed in the Mortgage and this Supplemental Indenture, all and singular the hereditament, premises, estates and property of the Company thereby conveyed or assigned or intended so to be, or which the Company may thereafter have become bound to convey or assign to the Trustee, as security for said bonds (except such hereditament, premises, estates and property as shall have been disposed of or released or withdrawn from the lien of the Mortgage and this Supplemental Indenture, in accordance with the provisions thereof and subject to alterations, modifications and changes in said hereditament, premises, estates and property as permitted under the provisions thereof), the Company, for and in consideration of the premises and the sum of One Dollar ($1.00) to it in hand paid by the Trustee, the receipt whereof is hereby acknowledged, and of other valuable considerations, has granted, bargained, sold, assigned, mortgaged, pledged, transferred, set over, aliened, enfeoffed, released, conveyed and confirmed, and by these presents does grant, bargain, sell, assign, mortgage, pledge, transfer, set over, alien, enfeoff, release, convey and confirm unto said Bankers Trust Company, as Trustee, and its successor or successors in the trusts created by the Mortgage and this Supplemental Indenture, and its and their assigns, all of said hereditament, premises, estates and property (except and subject as aforesaid), as fully as though described at length herein, including, without limitation of the foregoing, the property, rights and privileges of the Company described or referred to in Schedule B hereto. Together with all plants, buildings, structures, improvements and machinery located upon said real estate or any portion thereof, and all rights, privileges and easements of every kind and nature appurtenant thereto, and all and singular the tenements, hereditament and appurtenances belonging to the real estate or any part thereof described or referred to in Schedule B or intended so to be, or in any wise appertaining thereto, and the reversions, remainders, rents, issues and profits thereof, and also all the estate, right, title, interest, property, possession, claim and demand whatsoever, as well in law as in equity, of the Company, of, in and to the same and any and every part thereof, with the appurtenances; except and subject as aforesaid. TO HAVE AND TO HOLD all and singular the property, rights and privileges hereby granted or mentioned or intended so to be, together with all and singular the reversions, remainders, rents, revenues, income, issues and profits, privileges and appurtenances, now or hereafter belonging or in any way appertaining thereto, unto the Trustee and its successor or successors in the trust created by the Mortgage and this Supplemental Indenture, and its and their assigns, forever, and with like effect as if the above described property, rights and privileges had been specifically described at length in the Mortgage and this Supplemental Indenture. Subject, however, to permitted liens, as defined in the Mortgage Indenture. IN TRUST, NEVERTHELESS, upon the terms and trusts of the Mortgage and this Supplemental Indenture for those who shall hold the bonds and coupons issued and to be issued thereunder, or any of them, without preference, priority or distinction as to lien of any of said bonds and coupons over any others thereof by reason of priority in the time of the issue or negotiation thereof, or otherwise howsoever, subject, however, to the provisions in reference to extended, transferred or pledged coupons and claims for interest set forth in the Mortgage and this Supplemental Indenture (and subject to any sinking fund that may heretofore have been or hereafter be created for the benefit of any particular series). And it is hereby covenanted that all such bonds of Series C are to be issued, authenticated and delivered, and that the mortgaged premises are to be held by the Trustee, upon and subject to the trusts, covenants, provisions and conditions and for the uses and purposes set forth in the Mortgage and this Supplemental Indenture and upon and subject to the further covenants, provisions and conditions and for the uses and purposes hereinafter set forth, as follows, to wit: ARTICLE 1. FORM AND PROVISIONS OF BONDS OF SERIES C SECTION 1.01. Designation; Amount. The bonds of Series C shall be designated "First and Refunding Mortgage 8-1/2% Bonds, 1994 Series C" and, subject to Section 2.08 of the Mortgage Indenture, shall not exceed one hundred and fifteen million dollars ($115,000,000) in aggregate principal amount at any one time outstanding. The initial issue of the bonds of Series C may be effected upon compliance with the applicable provisions of the Mortgage Indenture. SECTION 1.02. Form of Bonds of Series C. The bonds of Series C shall be issued only in fully registered form without coupons in denominations of one thousand dollars ($1,000) and multiples thereof. The bonds of Series C and the certificate of the Trustee upon said bonds shall be substantially in the forms thereof respectively set forth in Schedule A appended hereto. SECTION 1.03. Provisions of Bonds of Series C; Interest Accrual. The bonds of Series C shall mature on June 1, 2024 and shall bear interest, payable semiannually on the first days of June and December of each year, commencing December 1, 1994, at the rate specified in their title, until the Company's obligation in respect of the principal thereof shall be discharged; and shall be payable both as to principal and interest at the office or agency of the Company in the Borough of Manhattan, New York, New York, in any coin or currency of the United States of America which at the time of payment is legal tender for the payment of public and private debts. The interest on the bonds of Series C, whether in temporary or definitive form, shall be payable without presentation of such bonds; and only to or upon the written order of the registered holders thereof of record at the applicable record date. The bonds of Series C shall be callable for redemption in whole or in part according to the terms and provisions provided herein in Article 2. Each bond of Series C shall be dated as of June 1, 1994 and shall bear interest on the principal amount thereof from the interest payment date next preceding the date of authentication thereof by the Trustee to which interest has been paid on the bonds of Series C, or if the date of authentication thereof is prior to November 16, 1994, then from the date of original issuance, or if the date of authentication thereof be an interest payment date to which interest is being paid or a date between the record date for any such interest payment date and such interest payment date, then from such interest payment date. The person in whose name any bond of Series C is registered at the close of business on any record date (as hereinafter defined) with respect to any interest payment date shall be entitled to receive the interest payable on such interest payment date notwithstanding the cancellation of such bond upon any registration of transfer or exchange thereof subsequent to the record date and prior to such interest payment date, except that if and to the extent the Company shall default in the payment of the interest due on such interest payment date, then such defaulted interest shall be paid to the person in whose name such bond is registered on a subsequent record date for the payment of defaulted interest if one shall have been established as hereinafter provided and otherwise on the date of payment of such defaulted interest. A subsequent record date may be established by the Company by notice mailed to the owners of bonds of Series C not less than ten days preceding such record date, which record date shall not be more than thirty days prior to the subsequent interest payment date. The term "record date" as used in this Section with respect to any regular interest payment (i.e., June 1 or December 1) shall mean the May 15 or November 15, as the case may be, next preceding such interest payment date, or if such May 15 or November 15 shall be a legal holiday or a day on which banking institutions in the Borough of Manhattan, New York, New York are authorized by law to close, the next preceding day which shall not be a legal holiday or a day on which such institutions are so authorized to close. SECTION 1.04. Transfer and Exchange of Bonds of Series C. The bonds of Series C may be surrendered for registration of transfer as provided in Section 2.06 of the Mortgage Indenture at the office or agency of the Company in the Borough of Manhattan, New York, New York, and may be surrendered at said office for exchange for a like aggregate principal amount of bonds of Series C of other authorized denominations. Notwithstanding the provisions of Section 2.06 of the Mortgage Indenture, no charge, except for taxes or other governmental charges, shall be made by the Company for any registration of transfer of bonds of Series C or for the exchange of any bonds of Series C for such bonds of other authorized denominations. SECTION 1.05. Sinking and Improvement Fund. Each holder of a bond of Series C, solely by virtue of its acquisition thereof, shall have and be deemed to have consented, without the need for any further action or consent by such holder, to any and all amendments to the Mortgage Indenture which are intended to eliminate or modify in any manner the requirements of the sinking and improvement fund as provided for in Section 6.14 thereof. ARTICLE 2. REDEMPTION OF BONDS OF SERIES C. The bonds of Series C are not subject to redemption at the option of the Company prior to June 1, 2004. Thereafter, the bonds of Series C shall be redeemable as a whole at any time or in part from time to time in accordance with the provisions of the Mortgage and upon not less than thirty (30) days' prior notice given by mail as provided in the Mortgage (which notice may state that it is subject to the receipt of the redemption moneys by the Trustee on or before the date fixed for redemption and which notice shall be of no effect unless such moneys are so received on or before such date), either at the option of the Company, or for the purpose of any applicable provision of the Mortgage, at the following prices: (a) if redeemed with trust moneys deposited with or received by the Trustee pursuant to Section 3.55 or Section 6.06 or Section 6.09 or Section 6.14 or Article 8.5 of the Mortgage Indenture, then at the applicable special redemption price, stated as a percentage of the principal amount, specified under the column headed Special Redemption Price in the form of bond of Series C set forth in Schedule A appended hereto, together in every case with accrued and unpaid interest thereon to the date fixed for redemption; and (b) otherwise, at the applicable general redemption price, stated as a percentage of the principal amount, specified under the column headed General Redemption Price in the form of bond of Series C set forth in Schedule A appended hereto, together in every case with accrued and unpaid interest thereon to the date fixed for redemption. ARTICLE 3. MISCELLANEOUS. SECTION 3.01. Benefits of Supplemental Indenture and Bonds of Series C. Nothing in this Supplemental Indenture, or in the bonds of Series C, expressed or implied, is intended to or shall be construed to give to any person or corporation other than the Company, the Trustee and the holders of the bonds and interest obligations secured by the Mortgage and this Supplemental Indenture, any legal or equitable right, remedy or claim under or in respect of this Supplemental Indenture or of any covenant, condition or provision herein contained. All the covenants, conditions and provisions hereof are and shall be held to be for the sole and exclusive benefit of the Company, the Trustee and the holders of the bonds and interest obligations secured by the Mortgage and this Supplemental Indenture. SECTION 3.02. Effect of Table of Contents and Headings. The table of contents and the descriptive headings of the several Articles and Sections of this Supplemental Indenture are inserted for convenience of reference only and are not to be taken to be any part of this Supplemental Indenture or to control or affect the meaning, construction or effect of the same. SECTION 3.03. Counterparts. For the purpose of facilitating the recording hereof, this Supplemental Indenture may be executed in any number of counterparts, each of which shall be and shall be taken to be an original and all collectively but one instrument. IN WITNESS WHEREOF, The Connecticut Light and Power Company has caused these presents to be executed by a Vice President and its corporate seal to be hereunto affixed, duly attested by its Secretary or an Assistant Secretary, and Bankers Trust Company has caused these presents to be executed by a Vice President or Assistant Vice President and its corporate seal to be hereunto affixed, duly attested by one of its Assistant Secretaries, as of the day and year first above written. THE CONNECTICUT LIGHT AND POWER COMPANY Attest: /s/ Mark A. Joyse By /s/ John B. Keane Mark A. Joyse John B. Keane Assistant Secretary Vice President (SEAL) Signed, sealed and delivered in the presence of: /s/ Tracy A. DeCredico /s/ Jane P. Seidl BANKERS TRUST COMPANY Attest: /s/ Scott Thiel By /s/ Robert Caporale (SEAL) Signed, sealed and delivered in the presence of: /s/ Denise Mitchell /s/ Michael Alba STATE OF CONNECTICUT ) ) SS.: BERLIN COUNTY OF HARTFORD ) On this 18th day of May 1994, before me, Deborah A. Lacus, the undersigned officer, personally appeared John B. Keane and Mark A. Joyse, who acknowledged themselves to be Vice President and Assistant Secretary, respectively, of THE CONNECTICUT LIGHT AND POWER COMPANY, a corporation, and that they, as such Vice President and such Assistant Secretary, being authorized so to do, executed the foregoing instrument for the purpose therein contained, by signing the name of the corporation by themselves as Vice President and Assistant Secretary, and as their free act and deed. IN WITNESS WHEREOF, I hereunto set my hand and official seal. /s/ Deborah A. Lacus Deborah A. Lacus Notary Public My commission expires December 31, 1995 (SEAL) STATE OF NEW YORK ) ) SS.: NEW YORKCOUNTY OF NEW YORK ) On this 19th day of May, 1994, before me, John Florio, the undersigned officer, personally appeared Robert Caporale and Scott Thiel who acknowledged themselves to be Vice President and Assistant Treasurer, respectively, of BANKERS TRUST COMPANY, a corporation, and that they, as such Vice President and such Assistant Treasurer, being authorized so to do, executed the foregoing instrument for the purposes therein contained, by signing the name of the corporation by themselves as Vice President and Assistant Treasurer, and as their free act and deed. IN WITNESS WHEREOF, I hereunto set my hand and official seal. /s/ John Florio John Florio Notary Public, State of New York No. 01FL5021631 Qualified in New York County My Commission Expires December 20, 1995 (SEAL) SCHEDULE A [FORM OF BONDS OF SERIES C] No. $ THE CONNECTICUT LIGHT AND POWER COMPANY Incorporated under the Laws of the State of Connecticut FIRST AND REFUNDING MORTGAGE 8-1/2% BOND, 1994 SERIES C PRINCIPAL DUE JUNE 1, 2024 FOR VALUE RECEIVED, THE CONNECTICUT LIGHT AND POWER COMPANY, a corporation organized and existing under the laws of the State of Connecticut (hereinafter called the Company), hereby promises to pay to /s/ or registered assigns, the principal sum of dollars, on the first day of ---------------- June, 2024 and to pay interest on said sum, semiannually on the first days of June and December in each year, commencing December 1, 1994, until the Company's obligation with respect to said principal sum shall be discharged, at the rate per annum specified in the title of this bond from the interest payment date next preceding the date of authentication hereof to which interest has been paid on the bonds of this series, or if the date of authentication hereof is prior to November 16, 1994, then from the date of original issuance, or if the date of authentication hereof is an interest payment date to which interest is being paid or a date between the record date for any such interest payment date and such interest payment date, then from such interest payment date. Both principal and interest shall be payable at the office or agency of the Company in the Borough of Manhattan, New York, New York, in such coin or currency of the United States of America as at the time of payment is legal tender for the payment of public and private debts. Each installment of interest hereon (other than overdue interest) shall be payable to the person who shall be the registered owner of this bond at the close of business on the record date, which shall be the May 15 or November 15, as the case may be, next preceding the interest payment date, or, if such May 15 or November 15 shall be a legal holiday or a day on which banking institutions in the Borough of Manhattan, New York, New York, are authorized by law to close, the next preceding day which shall not be a legal holiday or a day on which such institutions are so authorized to close. Reference is hereby made to the further provisions of this bond set forth on the reverse hereof, including without limitation provisions in regard to the call and redemption and the registration of transfer and exchangeability of this bond, and such further provisions shall for all purposes have the same effect as though fully set forth in this place. This bond shall not become or be valid or obligatory until the certificate of authentication hereon shall have been signed by Bankers Trust Company (hereinafter with its successors as defined in the Mortgage hereinafter referred to, generally called the Trustee), or by such a successor. IN WITNESS WHEREOF, The Connecticut Light and Power Company has caused this bond to be executed in its corporate name and on its behalf by its President by his signature or a facsimile thereof, and its corporate seal to be affixed or imprinted hereon and attested by the manual or facsimile signature of its Secretary. Dated as of June 1, 1994. THE CONNECTICUT LIGHT AND POWER COMPANY By ------------------------------------- President Attest: Secretary [FORM OF TRUSTEE'S CERTIFICATE] Bankers Trust Company hereby certifies that this bond is one of the bonds described in the within mentioned Mortgage. BANKERS TRUST COMPANY, TRUSTEE By ------------------------------------------- Authorized Officer Dated: [FORM OF BOND] [REVERSE] THE CONNECTICUT LIGHT AND POWER COMPANY FIRST AND REFUNDING MORTGAGE 8-1/2% BOND, 1994 SERIES C This bond is one of an issue of bonds of the Company, of an unlimited authorized amount of coupon bonds or registered bonds without coupons, or both, known as its First and Refunding Mortgage Bonds, all issued or to be issued in one or more series, and is one of a series of said bonds limited in principal amount to one hundred and fifteen million dollars ($115,000,000), consisting only of registered bonds without coupons and designated "First and Refunding Mortgage 8-1/2% Bonds, 1994 Series C," all of which bonds are issued or are to be issued under, and equally and ratably secured by, a certain Indenture of Mortgage and Deed and Trust dated as of May 1, 1921, and by sixty-two Supplemental Indentures dated respectively as of May 1, 1921, February 1, 1924, July 1, 1926, June 20, 1928, June 1, 1932, July 1, 1932, July 1, 1935, September 1, 1936, October 20, 1936, December 1, 1936, December 1, 1938, August 31, 1944, September 1, 1944, May 1, 1945, October 1, 1945, November 1, 1949, December 1, 1952, December 1, 1955, January 1, 1958, February 1, 1960, April 1, 1961, September 1, 1963, April 1, 1967, May 1, 1967, January 1, 1968, October 1, 1968, December 1, 1969, January 1, 1970, October 1, 1970, December 1, 1971, August 1, 1972, April 1, 1973, March 1, 1974, February 1, 1975, September 1, 1975, May 1, 1977, March 1, 1978, September 1, 1980, October 1, 1981, June 30, 1982, October 1, 1982, July 1, 1983, January 1, 1984, October 1, 1985, September 1, 1986, April 1, 1987, October 1, 1987, November 1, 1987, April 1, 1988, November 1, 1988, June 1, 1989, September 1, 1989, December 1, 1989, April 1, 1992, July 1, 1992, October 1, 1992, July 1, 1993, July 1, 1993, December 1, 1993, February 1, 1994, February 1, 1994 and June 1, 1994 (said Indenture of Mortgage and Deed of Trust and Supplemental Indentures being collectively referred to herein as the "Mortgage"), all executed by the Company to Bankers Trust Company, as Trustee, all as provided in the Mortgage to which reference is made for a statement of the property mortgaged and pledged, the nature and extent of the security, the rights of the holders of the bonds in respect thereof and the terms and conditions upon which the bonds may be issued and are secured; but neither the foregoing reference to the Mortgage nor any provision of this bond or of the Mortgage shall affect or impair the obligation of the Company, which is absolute, unconditional and unalterable, to pay at the maturities herein provided the principal of and interest on this bond as herein provided. The principal of this bond may be declared or may become due on the conditions, in the manner and at the time set forth in the Mortgage, upon the happening of an event of default as in the Mortgage provided. This bond is transferable by the registered holder hereof in person or by attorney upon surrender hereof at the office or agency of the Company in the Borough of Manhattan, New York, New York, together with a written instrument of transfer in approved form, signed by the holder, and a new bond or bonds of this series for a like principal amount in authorized denominations will be issued in exchange, all as provided in the Mortgage. Prior to due presentment for registration of transfer of this bond the Company and the Trustee may deem and treat the registered owner hereof as the absolute owner hereof, whether or not this bond be overdue, for the purpose of receiving payment and for all other purposes, and neither the Company nor the Trustee shall be affected by any notice to the contrary. This bond is exchangeable at the option of the registered holder hereof upon surrender hereof, at the office or agency of the Company in the Borough of Manhattan, New York, New York, for an equal principal amount of bonds of this series of other authorized denominations, in the manner and on the terms provided in the Mortgage. Bonds of this series are to be issued initially under a book-entry only system and, except as hereinafter provided, registered in the name of The Depository Trust Company, New York, New York ("DTC") or its nominee, which shall be considered to be the holder of all bonds of this series for all purposes of the Mortgage, including, without limitation, payment by the Company of principal of and interest on such bonds of this series and receipt of notices and exercise of rights of holders of such bonds of this series. There shall be a single bond of this series which shall be immobilized in the custody of DTC with the owners of book-entry interests in bonds of this series ("Book-Entry Interests") having no right to receive bonds of this series in the form of physical securities or certificates. Ownership of Book-Entry Interests shall be shown by book-entry on the system maintained and operated by DTC, its participants (the "Participants") and certain persons acting through the Participants. Transfers of ownership of Book-Entry Interests are to be made only by DTC and the Participants by that book-entry system, the Company and the Trustee having no responsibility therefor so long as bonds of this series are registered in the name of DTC or its nominee. DTC is to maintain records of positions of Participants in bonds of this series, and the Participants and persons acting through Participants are to maintain records of the purchasers and owners of Book-Entry Interests. If DTC or its nominee determines not to continue to act as a depository for the bonds of this series in connection with a book-entry only system, another depository, if available, may act instead and the single bond of this series will be transferred into the name of such other depository or its nominee, in which case the above provisions will continue to apply to the new depository. If the book- entry only system for bonds of this series is discontinued for any reason, upon surrender and cancellation of the single bond of this series registered in the name of the then depository or its nominee, new registered bonds of this series will be issued in authorized denominations to the holders of Book-Entry Interests in principal amounts coinciding with the amounts of Book-Entry Interests shown on the book-entry system immediately prior to the discontinuance thereof. Neither the Trustee nor the Company shall be responsible for the accuracy of the interests shown on that system. The bonds of this series are not subject to redemption at the option of the Company prior to June 1, 2004. Thereafter, the bonds of this series are subject to redemption prior to maturity as a whole at any time or in part from time to time in accordance with the provisions of the Mortgage, upon not less than thirty (30) days' prior notice (which notice may be made subject to the deposit of redemption moneys with the Trustee before the date fixed for redemption) given by mail as provided in the Mortgage, either at the option of the Company, or for the purposes of any applicable provision of the Mortgage, at the following prices, together in every case with accrued and unpaid interest thereon to the date fixed for redemption: (a) if redeemed with trust moneys deposited with or received by the Trustee pursuant to specified provisions of the Mortgage, then at the applicable special redemption price, stated as a percentage of the principal amount, set forth below; and (b) otherwise, at the applicable general redemption price, stated as a percentage of the principal amount, set forth below: If date fixed for General Special redemption falls Redemption Redemption within twelve months' Price (% Price (% period ending the of principal of principal last day of May amount called) amount called) --------------- -------------- -------------- 2005 103.87 100.00 2006 103.48 100.00 2007 103.09 100.00 2008 102.71 100.00 2009 102.32 100.00 2010 101.94 100.00 2011 101.55 100.00 2012 101.16 100.00 2013 100.78 100.00 2014 100.39 100.00 2015 100.00 100.00 2016 100.00 100.00 2017 100.00 100.00 2018 100.00 100.00 2019 100.00 100.00 2020 100.00 100.00 2021 100.00 100.00 2022 100.00 100.00 2023 100.00 100.00 2024 100.00 100.00 The Mortgage provides that the Company and the Trustee, with consent of the holders of not less than 66-2/3% in aggregate principal amount of the bonds at the time outstanding which would be affected by the action proposed to be taken, may by supplemental indenture add any provisions to or change or eliminate any of the provisions of the Mortgage or modify the rights of the holders of the bonds and coupons issued thereunder; provided, however, that without the consent of the holder hereof no such supplemental indenture shall affect the terms of payment of the principal of or interest or premium on this bond, or reduce the aforesaid percentage of the bonds the holders of which are required to consent to such a supplemental indenture, or permit the creation by the Company of any mortgage or pledge or lien in the nature thereof ranking prior to or equal with the lien of the Mortgage or deprive the holder hereof of the lien of the Mortgage on any of the property which is subject to the lien thereof. As set forth in the Supplemental Indenture establishing the terms and series of the bonds of this series, each holder of this bond, solely by virtue of its acquisition thereof, shall have and be deemed to have consented, without the need for any further action or consent by such holder, to any and all amendments to the Mortgage which are intended to eliminate or modify in any manner the requirements of the sinking and improvement fund as set forth in Section 6.14 of the Mortgage. No recourse shall be had for the payment of the principal of or the interest on this bond, or any part thereof, or for any claim based thereon or otherwise in respect thereof, to any incorporator, or any past, present or future stockholder, officer or director of the Company, either directly or indirectly, by virtue of any statute or by enforcement of any assessment or otherwise, and any and all liability of the said incorporators, stockholders, officers or directors of the Company in respect to this bond is hereby expressly waived and released by every holder hereof. SCHEDULE B PROPERTY SUBJECT TO THE LIEN OF THE MORTGAGE IN CONNECTICUT TOWN OF ASHFORD All of the following described rights, privileges and easements situated in the Town of Ashford, County of Windham and State of Connecticut, more particularly described in the following deeds, viz: Recorded Grantor Date of Instrument Volume Page (1) Rex Harkness et al January 18, 1994 103 547 (2) C. Nelson Construction,Inc. January 17, 1994 103 641 (3) Town of Ashford March 11, 1994 104 002 TOWN OF AVON All of the following described rights, privileges and easements situated in the Town of Avon, County of Hartford and State of Connecticut, more particularly described in the following deeds, viz: Recorded Grantor Date of Instrument Volume Page (4) Edward M. Ferrigno Construction December 13, 1993 288 808 Company, Inc. (5) Solo Development January 13, 1994 291 325 TOWN OF BERLIN All of the following described rights, privileges and easements situated in the Town of Berlin, County of Hartford and State of Connecticut, more particularly described in the following deeds, viz: Recorded Grantor Date of Instrument Volume Page (6) Kensington Woods, Incorporated December 16, 1993 356 40 TOWN OF BRISTOL All of the following described rights, privileges and easements situated in the Town of Bristol, County of Hartford and State of Connecticut, more particularly described in the following deeds, viz: Recorded Grantor Date of Instrument Volume Page (7) Bruce Development Corporation, December 10, 1993 1115 650 Inc. et al TOWN OF BURLINGTON All of the following described rights, privileges and easements situated in the Town of Burlington, County of Hartford and State of Connecticut, more particularly described in the following deeds, viz: Recorded Grantor Date of Instrument Volume Page (8) Woodland Notch Development May 27, 1993 140 756 Corporation TOWN OF CANTON All of the following described rights, privileges and easements situated in the Town of Canton, County of Hartford and State of Connecticut, more particularly described in the following deeds, viz: Recorded Grantor Date of Instrument Volume Page (9) Michael A. Hollender et al October 2, 1993 196 384 TOWN OF CHESHIRE All of the following described rights, privileges and easements situated in the Town of Cheshire, County of New Haven and State of Connecticut, more particularly described in the following deeds, viz: Recorded Grantor Date of Instrument Volume Page (10) Thomas J. Norback et al December 7, 1993 1024 224 (11) Neda DeMayo et al February 1, 1994 1036 223* * Inter Alia: Hamden TOWN OF CLINTON All of the following described rights, privileges and easements situated in the Town of Clinton, County of Middlesex and State of Connecticut, more particularly described in the following deeds, viz: Recorded Grantor Date of Instrument Volume Page (12) Lione Enterprises August 30, 1993 225 67 TOWN OF DANBURY All of the following described rights, privileges and easements situated in the Town of Danbury, County of Fairfield and State of Connecticut, more particularly described in the following deeds, viz: Recorded Grantor Date of Instrument Volume Page (13) Warren Ramey February 1, 1994 1077 823 (14) Mario Aldo Ljubicic et al January 12, 1994 1077 903 TOWN OF DURHAM All of the following described rights, privileges and easements situated in the Town of Durham, County of Middlesex and State of Connecticut, more particularly described in the following deeds, viz: Recorded Grantor Date of Instrument Volume Page (15) William J. O'Neal December 2, 1993 140 107 TOWN OF EAST WINDSOR All of the following described rights, privileges and easements situated in the Town of East Windsor, County of Hartford and State of Connecticut, more particularly described in the following deeds, viz: Recorded Grantor Date of Instrument Volume Page (16) Connecticut Development Group, December 3, 1993 176 1061 Inc. of Glastonbury TOWN OF ELLINGTON All of the following described rights, privileges and easements situated in the Town of Ellington, County of Tolland and State of Connecticut, more particularly described in the following deeds, viz: Recorded Grantor Date of Instrument Volume Page (17) The SBD Partnership December 21, 1993 207 136 (18) MMS Country Home Properties, January 26, 1994 207 138 Inc. TOWN OF ENFIELD All of the following described rights, privileges and easements situated in the Town of Enfield, County of Hartford and State of Connecticut, more particularly described in the following deeds, viz: Recorded Grantor Date of Instrument Volume Page (19) Hazard Avenue Associates May 25, 1988 575 225 (20) Lan Associates XII, Limited May 29, 1986 519 1118 Partnership (21) Leaska Construction Co. October 22, 1990 622 15 (22) Carriage House I-Enfield, Inc.October 8, 1987 561 611 (23) Daro Development Corporation October 22, 1986 530 724 (24) ADS Realty Co., Inc. April 24, 1989 594 1189 TOWN OF GREENWICH All of the following described rights, privileges and easements situated in the Town of Greenwich, County of Fairfield and State of Connecticut, more particularly described in the following deeds, viz: Recorded Grantor Date of Instrument Volume Page (25) Mario E. Autera et al December 7, 1992 2450 75 TOWN OF HAMDEN All of the following described rights, privileges and easements situated in the Town of Hamden, County of New Haven and State of Connecticut, more particularly described in the following deeds, viz: Recorded Grantor Date of Instrument Volume Page (26) Neda DeMayo et al February 1, 1994 1399 294* TOWN OF LEBANON All of the following described rights, privileges and easements situated in the Town of Lebanon, County of New London and State of Connecticut, more particularly described in the following deeds, viz: Recorded Grantor Date of Instrument Volume Page (27) G. Bradford Foster et al November 1, 1993 155 515 (28) Farmers & Mechanics Bank December 10, 1993 156 87 (29) Donald A. Demar January 17, 1994 156 589 TOWN OF LITCHFIELD All of the following described rights, privileges and easements situated in the Town of Litchfield, County of Litchfield and State of Connecticut, more particularly described in the following deeds, viz: Recorded Grantor Date of Instrument Volume Page (30) Nancy D. Goldring et al October 25, 1993 219 1162 & November 15, 1993 * Inter Alia: Cheshire TOWN OF MANCHESTER All of the following described rights, privileges and easements situated in the Town of Manchester, County of Hartford and State of Connecticut, more particularly described in the following deeds, viz: Recorded Grantor Date of Instrument Volume Page (31) TAVCO Associates December 8, 1992 1671 343 TOWN OF MIDDLEBURY All of the following described rights, privileges and easements situated in the Town of Middlebury, County of New Haven and State of Connecticut, more particularly described in the following deeds, viz: Recorded Grantor Date of Instrument Volume Page (32) Christine N. Lavigne et al August 11, 1992 127 912 TOWN OF MONROE All of the following described rights, privileges and easements situated in the Town of Monroe, County of Fairfield and State of Connecticut, more particularly described in the following deeds, viz: Recorded Grantor Date of Instrument Volume Page (33) Carol B. Steiner October 13, 1988 425 154 TOWN OF MONTVILLE All of the following described rights, privileges and easements situated in the Town of Montville, County of New London and State of Connecticut, more particularly described in the following deeds, viz: Recorded Grantor Date of Instrument Volume Page (34) Bernard Barnett et al June 17, 1993 255 777 (35) Jean K. Milefski et al December 15, 1993 264 250 TOWN OF NAUGATUCK All of the following described rights, privileges and easements situated in the Town of Naugatuck, County of New Haven and State of Connecticut, more particularly described in the following deeds, viz: Recorded Grantor Date of Instrument Volume Page (36) Realrock Associates December 20, 1993 389 919 TOWN OF NEW MILFORD All of the following described rights, privileges and easements situated in the Town of New Milford, County of Litchfield and State of Connecticut, more particularly described in the following deeds, viz: Recorded Grantor Date of Instrument Volume Page (37) Joseph S. Tarzia May 21, 1993 476 791 (38) John W. Dinneen, Jr. et al November 10, 1993 484 812 TOWN OF NEWTOWN All of the following described rights, privileges and easements situated in the Town of Newtown, County of Fairfield and State of Connecticut, more particularly described in the following deeds, viz: Recorded Grantor Date of Instrument Volume Page (39) Joseph Scherpf December 21, 1993 486 88 (40) Early Settlers Limited February 9, 1994 488 630 Partnership TOWN OF NORTH STONINGTON All of the following described rights, privileges and easements situated in the Town of North Stonington, County of New London and State of Connecticut, more particularly described in the following deeds, viz: Recorded Grantor Date of Instrument Volume Page (41) B & D Associates January 3, 1994 99 581 TOWN OF OLD LYME All of the following described rights, privileges and easements situated in the Town of Old Lyme, County of New London and State of Connecticut, more particularly described in the following deeds, viz: Recorded Grantor Date of Instrument Volume Page (42) Gary D. Smith June 17, 1993 211 551 TOWN OF PLAINFIELD All of the following described rights, privileges and easements situated in the Town of Plainfield, County of Windham and State of Connecticut, more particularly described in the following deeds, viz: Recorded Grantor Date of Instrument Volume Page (43) Kenneth E. Tetreault March 30, 1994 222 12 TOWN OF RIDGEFIELD All of the following described rights, privileges and easements situated in the Town of Ridgefield, County of Fairfield and State of Connecticut, more particularly described in the following deeds, viz: Recorded Grantor Date of Instrument Volume Page (44) Sturges Brothers, Inc. August 28, 1993 476 98 (45) William A. Jones January 14, 1994 485 911 TOWN OF SIMSBURY All of the following described rights, privileges and easements situated in the Town of Simsbury, County of Hartford and State of Connecticut, more particularly described in the following deeds, viz: Recorded Grantor Date of Instrument Volume Page (46) Estate of George L. Engel April 8, 1994 429 68 TOWN OF SOUTHBURY All of the following described rights, privileges and easements situated in the Town of Southbury, County of New Haven and State of Connecticut, more particularly described in the following deeds, viz: Recorded Grantor Date of Instrument Volume Page (47) Naugatuck Savings Bank et al May 7, 1993 271 549 (48) T D I, Ltd. April 8, 1993 271 613 TOWN OF SOUTHINGTON All of the following described rights, privileges and easements situated in the Town of Southington, County of Hartford and State of Connecticut, more particularly described in the following deeds, viz: Recorded Grantor Date of Instrument Volume Page (49) David W. Florian September 25, 1992 548 826 (50) Katherine Florian September 25, 1992 548 828 (51) Carl J. Sokolowski, Trustee September 30, 1992 548 830 (52) LePage Homes, Inc. March 8, 1993 560 840 (53) William G. Gioia February 14, 1994 594 795 TOWN OF SOUTH WINDSOR All of the following described rights, privileges and easements situated in the Town of South Windsor, County of Hartford and State of Connecticut, more particularly described in the following deeds, viz: Recorded Grantor Date of Instrument Volume Page (54) Dart Hill Realty, Inc. March 22, 1994 784 30 TOWN OF STAFFORD All of the following described rights, privileges and easements situated in the Town of Stafford, County of Tolland and State of Connecticut, more particularly described in the following deeds, viz: Recorded Grantor Date of Instrument Volume Page (55) Maiolo Real Estate Investment November 18, 1993 313 3 Company, Inc. TOWN OF STERLING All of the following described rights, privileges and easements situated in the Town of Sterling, County of Windham and State of Connecticut, more particularly described in the following deeds, viz: Recorded Grantor Date of Instrument Volume Page (56) Christopher Adam Sliwinski August 18, 1993 69 707 (57) Peter F. Maerkel July 16, 1993 69 1052 (58) Patten Liquidation Sales January 11, 1994 70 40 Corporation TOWN OF SUFFIELD All of the following described rights, privileges and easements situated in the Town of Suffield, County of Hartford and State of Connecticut, more particularly described in the following deeds, viz: Recorded Grantor Date of Instrument Volume Page (59) Briarwood Homes, Inc. February 8, 1994 252 455 TOWN OF THOMASTON All of the following described rights, privileges and easements situated in the Town of Thomaston, County of Litchfield and State of Connecticut, more particularly described in the following deeds, viz: Recorded Grantor Date of Instrument Volume Page (60) Robert D. Scanlon et al February 18, 1993 144 31 TOWN OF TOLLAND All of the following described rights, privileges and easements situated in the Town of Tolland, County of Tolland and State of Connecticut, more particularly described in the following deeds, viz: Recorded Grantor Date of Instrument Volume Page (61) Alan D. Williams et al November 22, 1993 474 73 TOWN OF TORRINGTON All of the following described rights, privileges and easements situated in the Town of Torrington, County of Litchfield and State of Connecticut, more particularly described in the following deeds, viz: Recorded Grantor Date of Instrument Volume Page (62) David Vaill November 18, 1992 574 1031 (63) The Charlotte Hungerford June 4, 1993 575 697 Hospital et al (64) The Charlotte Hungerford December 8, 1993 587 965 Hospital et al TOWN OF VOLUNTOWN All of the following described rights, privileges and easements situated in the Town of Voluntown, County of New London and State of Connecticut, more particularly described in the following deeds, viz: Recorded Grantor Date of Instrument Volume Page (65) Town of Voluntown March 8, 1994 61 994 TOWN OF WATERBURY All of the following described rights, privileges and easements situated in the Town of Waterbury, County of New Haven and State of Connecticut, more particularly described in the following deeds, viz: Recorded Grantor Date of Instrument Volume Page (66) Daniel W. Ferraro May 26, 1993 2972 12 TOWN OF WATERTOWN All of the following described rights, privileges and easements situated in the Town of Watertown, County of Litchfield and State of Connecticut, more particularly described in the following deeds, viz: Recorded Grantor Date of Instrument Volume Page (67) The Torrington Company May 12, 1993 700 237 TOWN OF WESTON All of the following described rights, privileges and easements situated in the Town of Weston, County of Fairfield and State of Connecticut, more particularly described in the following deeds, viz: Recorded Grantor Date of Instrument Volume Page (68) KHM Family Trust January 26, 1994 217 625 TOWN OF WILTON All of the following described rights, privileges and easements situated in the Town of Wilton, County of Fairfield and State of Connecticut, more particularly described in the following deeds, viz: Recorded Grantor Date of Instrument Volume Page (69) Thomas T. Adams, Trustee April 20, 1992 785 51 (70) Thomas T. Adams, Trustee January 3, 1994 887 112 TOWN OF WOODBURY All of the following described rights, privileges and easements situated in the Town of Woodbury, County of Litchfield and State of Connecticut, more particularly described in the following deeds, viz: Recorded Grantor Date of Instrument Volume Page (71) Garwin D. Hardisty June 10, 1993 195 939 TOWN OF WOODSTOCK All of the following described rights, privileges and easements situated in the Town of Woodstock, County of Windham and State of Connecticut, more particularly described in the following deeds, viz: Recorded Grantor Date of Instrument Volume Page EX-4.2.16 5 SUPPLEMENTAL INDENTURE Dated as of October 1, 1994 TO Indenture of Mortgage and Deed of Trust Dated as of May 1, 1921 THE CONNECTICUT LIGHT AND POWER COMPANY TO BANKERS TRUST COMPANY, Trustee 1994 Series D Bonds, Due October 1, 2024 THE CONNECTICUT LIGHT AND POWER COMPANY Supplemental Indenture, Dated as of October 1, 1994 TABLE OF CONTENTS PAGE Parties 1 Recitals 1 Granting Clauses 2 Habendum 2 Grant in Trust 2 ARTICLE 1. FORM AND PROVISIONS OF BONDS OF SERIES D SECTION 1.01. Designation; Amount 3 SECTION 1.02. Form of Bonds of Series D 3 SECTION 1.03. Provisions of Bonds of Series D; Interest Accrual 3 SECTION 1.04. Transfer and Exchange of Bonds of Series D 4 SECTION 1.05. Sinking and Improvement Fund 4 ARTICLE 2. REDEMPTION OF BONDS OF SERIES D 4 ARTICLE 3. REPAYMENT OF BONDS OF SERIES D AT OPTION OF HOLDER 4 ARTICLE 4. MISCELLANEOUS SECTION 4.01. Benefits of Supplemental Indenture and Bonds of Series D 4 SECTION 4.02. Effect of Table of Contents and Headings 5 SECTION 4.03. Counterparts 5 TESTIMONIUM 5 SIGNATURES 5 ACKNOWLEDGMENTS 6 SCHEDULE A - Form of Bond of Series D, Form of Trustee's Certificate 7 SCHEDULE B - Property Subject to the Lien of the Mortgage 13 SUPPLEMENTAL INDENTURE, dated as of the first day of October, 1994, between THE CONNECTICUT LIGHT AND POWER COMPANY, a corporation organized and existing under the laws of the State of Connecticut (hereinafter called "Company") and BANKERS TRUST COMPANY, a corporation organized and existing under the laws of the State of New York (hereinafter called "Trustee"). WHEREAS, the Company heretofore duly executed, acknowledged and delivered to the Trustee a certain Indenture of Mortgage and Deed of Trust dated as of May 1, 1921, and sixty-two Supplemental Indentures thereto dated respectively as of May 1, 1921, February 1, 1924, July 1, 1926, June 20, 1928, June 1, 1932, July 1, 1932, July 1, 1935, September 1, 1936, October 20, 1936, December 1, 1936, December 1, 1938, August 31, 1944, September 1, 1944, May 1, 1945, October 1, 1945, November 1, 1949, December 1, 1952, December 1, 1955, January 1, 1958, February 1, 1960, April 1, 1961, September 1, 1963, April 1, 1967, May 1, 1967, January 1, 1968, October 1, 1968, December 1, 1969, January 1, 1970, October 1, 1970, December 1, 1971, August 1, 1972, April 1, 1973, March 1, 1974, February 1, 1975, September 1, 1975, May 1, 1977, March 1, 1978, September 1, 1980, October 1, 1981, June 30, 1982, October 1, 1982, July 1, 1983, January 1, 1984, October 1, 1985, September 1, 1986, April 1, 1987, October 1, 1987, November 1, 1987, April 1, 1988, November 1, 1988, June 1, 1989, September 1, 1989, December 1, 1989, April 1, 1992, July 1, 1992, October 1, 1992, July 1, 1993, July 1, 1993, December 1, 1993, February 1, 1994, February 1, 1994 and June 1, 1994 (said Indenture of Mortgage and Deed of Trust (i) as heretofore amended, being hereinafter generally called the "Mortgage Indenture," and (ii) together with said Supplemental Indentures thereto, being hereinafter generally called the "Mortgage"), all of which have been duly recorded as required by law, for the purpose of securing its First and Refunding Mortgage Bonds (of which $1,330,000,000 aggregate principal amount are outstanding at the date of this Supplemental Indenture) to an unlimited amount, issued and to be issued for the purposes and in the manner therein provided, of which Mortgage this Supplemental Indenture is intended to be made a part, as fully as if therein recited at length; WHEREAS, the Company by appropriate and sufficient corporate action in conformity with the provisions of the Mortgage has duly determined to create a further series of bonds under the Mortgage to be designated "First and Refunding Mortgage 7-7/8% Bonds, 1994 Series D" (hereinafter generally referred to as the "bonds of Series D"), to consist of fully registered bonds containing terms and provisions duly fixed and determined by the Board of Directors of the Company and expressed in this Supplemental Indenture, such fully registered bonds and the Trustee's certificate of its authentication thereof to be substantially in the forms thereof respectively set forth in Schedule A appended hereto and made a part hereof; and WHEREAS, the execution and delivery of this Supplemental Indenture and the issue of not in excess of one hundred and forty million dollars ($140,000,000) in aggregate principal amount of bonds of Series D and other necessary actions have been duly authorized by the Board of Directors of the Company; and WHEREAS, the Company proposes to execute and deliver this Supplemental Indenture to provide for the issue of the bonds of Series D and to confirm the lien of the Mortgage on the property referred to below, all as permitted by Section 14.01 of the Mortgage Indenture; and WHEREAS, all acts and things necessary to constitute this Supplemental Indenture a valid, binding and legal instrument and to make the bonds of Series D, when executed by the Company and authenticated by the Trustee valid, binding and legal obligations of the Company have been authorized and performed; NOW, THEREFORE, THIS SUPPLEMENTAL INDENTURE OF MORTGAGE AND DEED OF TRUST WITNESSETH: That in order to secure the payment of the principal of and interest on all bonds issued and to be issued under the Mortgage, according to their tenor and effect, and according to the terms of the Mortgage and this Supplemental Indenture, and to secure the performance of the covenants and obligations in said bonds and in the Mortgage and this Supplemental Indenture respectively contained, and for the better assuring and confirming unto the Trustee, its successor or successors and its or their assigns, upon the trusts and for the purposes expressed in the Mortgage and this Supplemental Indenture, all and singular the hereditament, premises, estates and property of the Company thereby conveyed or assigned or intended so to be, or which the Company may thereafter have become bound to convey or assign to the Trustee, as security for said bonds (except such hereditament, premises, estates and property as shall have been disposed of or released or withdrawn from the lien of the Mortgage and this Supplemental Indenture, in accordance with the provisions thereof and subject to alterations, modifications and changes in said hereditament, premises, estates and property as permitted under the provisions thereof), the Company, for and in consideration of the premises and the sum of One Dollar ($1.00) to it in hand paid by the Trustee, the receipt whereof is hereby acknowledged, and of other valuable considerations, has granted, bargained, sold, assigned, mortgaged, pledged, transferred, set over, aliened, enfeoffed, released, conveyed and confirmed, and by these presents does grant, bargain, sell, assign, mortgage, pledge, transfer, set over, alien, enfeoff, release, convey and confirm unto said Bankers Trust Company, as Trustee, and its successor or successors in the trusts created by the Mortgage and this Supplemental Indenture, and its and their assigns, all of said hereditament, premises, estates and property (except and subject as aforesaid), as fully as though described at length herein, including, without limitation of the foregoing, the property, rights and privileges of the Company described or referred to in Schedule B hereto. Together with all plants, buildings, structures, improvements and machinery located upon said real estate or any portion thereof, and all rights, privileges and easements of every kind and nature appurtenant thereto, and all and singular the tenements, hereditament and appurtenances belonging to the real estate or any part thereof described or referred to in Schedule B or intended so to be, or in any wise appertaining thereto, and the reversions, remainders, rents, issues and profits thereof, and also all the estate, right, title, interest, property, possession, claim and demand whatsoever, as well in law as in equity, of the Company, of, in and to the same and any and every part thereof, with the appurtenances; except and subject as aforesaid. TO HAVE AND TO HOLD all and singular the property, rights and privileges hereby granted or mentioned or intended so to be, together with all and singular the reversions, remainders, rents, revenues, income, issues and profits, privileges and appurtenances, now or hereafter belonging or in any way appertaining thereto, unto the Trustee and its successor or successors in the trust created by the Mortgage and this Supplemental Indenture, and its and their assigns, forever, and with like effect as if the above described property, rights and privileges had been specifically described at length in the Mortgage and this Supplemental Indenture. Subject, however, to permitted liens, as defined in the Mortgage Indenture. IN TRUST, NEVERTHELESS, upon the terms and trusts of the Mortgage and this Supplemental Indenture for those who shall hold the bonds and coupons issued and to be issued thereunder, or any of them, without preference, priority or distinction as to lien of any of said bonds and coupons over any others thereof by reason of priority in the time of the issue or negotiation thereof, or otherwise howsoever, subject, however, to the provisions in reference to extended, transferred or pledged coupons and claims for interest set forth in the Mortgage and this Supplemental Indenture (and subject to any sinking fund that may heretofore have been or hereafter be created for the benefit of any particular series). And it is hereby covenanted that all such bonds of Series D are to be issued, authenticated and delivered, and that the mortgaged premises are to be held by the Trustee, upon and subject to the trusts, covenants, provisions and conditions and for the uses and purposes set forth in the Mortgage and this Supplemental Indenture and upon and subject to the further covenants, provisions and conditions and for the uses and purposes hereinafter set forth, as follows, to wit: ARTICLE 1. FORM AND PROVISIONS OF BONDS OF SERIES D SECTION 1.01. Designation; Amount. The bonds of Series D shall be designated "First and Refunding Mortgage 7-7/8% Bonds, 1994 Series D" and, subject to Section 2.08 of the Mortgage Indenture, shall not exceed one hundred and forty million dollars ($140,000,000) in aggregate principal amount at any one time outstanding. The initial issue of the bonds of Series D may be effected upon compliance with the applicable provisions of the Mortgage Indenture. SECTION 1.02. Form of Bonds of Series D. The bonds of Series D shall be issued only in fully registered form without coupons in denominations of one thousand dollars ($1,000) and multiples thereof. The bonds of Series D and the certificate of the Trustee upon said bonds shall be substantially in the forms thereof respectively set forth in Schedule A appended hereto. SECTION 1.03. Provisions of Bonds of Series D; Interest Accrual. The bonds of Series D shall mature on October 1, 2024 and shall bear interest, payable semiannually on the first days of April and October of each year, commencing April 1, 1995, at the rate specified in their title, until the Company's obligation in respect of the principal thereof shall be discharged; and shall be payable both as to principal and interest at the office or agency of the Company in the Borough of Manhattan, New York, New York, in any coin or currency of the United States of America which at the time of payment is legal tender for the payment of public and private debts. The interest on the bonds of Series D, whether in temporary or definitive form, shall be payable without presentation of such bonds; and only to or upon the written order of the registered holders thereof of record at the applicable record date. The bonds of Series D shall be callable for redemption in whole or in part according to the terms and provisions provided herein in Article 2. Each bond of Series D shall be dated as of October 1, 1994 and shall bear interest on the principal amount thereof from the interest payment date next preceding the date of authentication thereof by the Trustee to which interest has been paid on the bonds of Series D, or if the date of authentication thereof is prior to March 16, 1995, then from the date of original issuance, or if the date of authentication thereof be an interest payment date to which interest is being paid or a date between the record date for any such interest payment date and such interest payment date, then from such interest payment date. The person in whose name any bond of Series D is registered at the close of business on any record date (as hereinafter defined) with respect to any interest payment date shall be entitled to receive the interest payable on such interest payment date notwithstanding the cancellation of such bond upon any registration of transfer or exchange thereof subsequent to the record date and prior to such interest payment date, except that if and to the extent the Company shall default in the payment of the interest due on such interest payment date, then such defaulted interest shall be paid to the person in whose name such bond is registered on a subsequent record date for the payment of defaulted interest if one shall have been established as hereinafter provided and otherwise on the date of payment of such defaulted interest. A subsequent record date may be established by the Company by notice mailed to the owners of bonds of Series D not less than ten days preceding such record date, which record date shall not be more than thirty days prior to the subsequent interest payment date. The term "record date" as used in this Section with respect to any regular interest payment (i.e., April 1 or October 1) shall mean the March 15 or September 15, as the case may be, next preceding such interest payment date, or if such March 15 or September 15 shall be a legal holiday or a day on which banking institutions in the Borough of Manhattan, New York, New York are authorized by law to close, the next preceding day which shall not be a legal holiday or a day on which such institutions are so authorized to close. SECTION 1.04. Transfer and Exchange of Bonds of Series D. The bonds of Series D may be surrendered for registration of transfer as provided in Section 2.06 of the Mortgage Indenture at the office or agency of the Company in the Borough of Manhattan, New York, New York, and may be surrendered at said office for exchange for a like aggregate principal amount of bonds of Series D of other authorized denominations. Notwithstanding the provisions of Section 2.06 of the Mortgage Indenture, no charge, except for taxes or other governmental charges, shall be made by the Company for any registration of transfer of bonds of Series D or for the exchange of any bonds of Series D for such bonds of other authorized denominations. SECTION 1.05. Sinking and Improvement Fund. Each holder of a bond of Series D, solely by virtue of its acquisition thereof, shall have and be deemed to have consented, without the need for any further action or consent by such holder, to any and all amendments to the Mortgage Indenture which are intended to eliminate or modify in any manner the requirements of the sinking and improvement fund as provided for in Section 6.14 thereof. ARTICLE 2. REDEMPTION OF BONDS OF SERIES D. The bonds of Series D shall not be redeemable as a whole or in part at any time. ARTICLE 3 REPAYMENT OF BONDS OF SERIES D AT OPTION OF HOLDER Any of the bonds of Series D are subject to repayment on October 1, 2001 at the option of the holder of the bond of Series D as set forth in the form of bond of Series D appended hereto. ARTICLE 4 MISCELLANEOUS. SECTION 4.01. Benefits of Supplemental Indenture and Bonds of Series D. Nothing in this Supplemental Indenture, or in the bonds of Series D, expressed or implied, is intended to or shall be construed to give to any person or corporation other than the Company, the Trustee and the holders of the bonds and interest obligations secured by the Mortgage and this Supplemental Indenture, any legal or equitable right, remedy or claim under or in respect of this Supplemental Indenture or of any covenant, condition or provision herein contained. All the covenants, conditions and provisions hereof are and shall be held to be for the sole and exclusive benefit of the Company, the Trustee and the holders of the bonds and interest obligations secured by the Mortgage and this Supplemental Indenture. SECTION 4.02. Effect of Table of Contents and Headings. The table of contents and the descriptive headings of the several Articles and Sections of this Supplemental Indenture are inserted for convenience of reference only and are not to be taken to be any part of this Supplemental Indenture or to control or affect the meaning, construction or effect of the same. SECTION 4.03. Counterparts. For the purpose of facilitating the recording hereof, this Supplemental Indenture may be executed in any number of counterparts, each of which shall be and shall be taken to be an original and all collectively but one instrument. IN WITNESS WHEREOF, The Connecticut Light and Power Company has caused these presents to be executed by a Vice President and its corporate seal to be hereunto affixed, duly attested by its Secretary or an Assistant Secretary, and Bankers Trust Company has caused these presents to be executed by a Vice President or Assistant Vice President and its corporate seal to be hereunto affixed, duly attested by one of its Assistant Secretaries, as of the day and year first above written. THE CONNECTICUT LIGHT AND POWER COMPANY Attest: /s/ Mark A. Joyse By /s/ John B. Keane Mark A. Joyse John B. Keane Assistant Secretary Vice President (SEAL) Signed, sealed and delivered in the presence of: /s/ Tracy A. DeCredico /s/ Jeffrey C. Miller BANKERS TRUST COMPANY Attest: /s/ Scott Thiel By /s/ Robert Caporale Scott Thiel Robert Caporale Assistant Treasurer Vice President (SEAL) Signed, sealed and delivered in the presence of: /s/ Kerri O'Brien /s/ Denise Mitchell (STATE OF CONNECTICUT ) ) SS.: BERLIN COUNTY OF HARTFORD ) On this 28th day of September, 1994, before me, Deborah A. Tawrel, the undersigned officer, personally appeared John B. Keane and Mark A. Joyse who acknowledged themselves to be Vice President and Assistant Secretary, respectively, of THE CONNECTICUT LIGHT AND POWER COMPANY, a corporation, and that they, as such Vice President and such Assistant Secretary, being authorized so to do, executed the foregoing instrument for the purpose therein contained, by signing the name of the corporation by themselves as Vice President and Assistant Secretary, and as their free act and deed. IN WITNESS WHEREOF, I hereunto set my hand and official seal. /s/ Deborah A. Tawrel Deborah A. Tawrel Notary Public My commission expires December 31, 1995 (SEAL) STATE OF NEW YORK ) ) SS.: NEW YORK COUNTY OF NEW YORK ) On this day of September, 1994, before me, Sharon V. Alston, the ---- undersigned officer, personally appeared Robert Caporale and Scott Thiel who acknowledged themselves to be Vice President and Assistant Treasurer, respectively, of BANKERS TRUST COMPANY, a corporation, and that they, as such Vice President and such Assistant Treasurer, being authorized so to do, executed the foregoing instrument for the purposes therein contained, by signing the name of the corporation by themselves as Vice President and Assistant Treasurer, and as their free act and deed. IN WITNESS WHEREOF, I hereunto set my hand and official seal. /s/ Sharon V. Alston Sharon V. Alston Notary Public, State of New York No. 31-4966275 Qualified in New York County My Commission expires -------------- (SEAL) (SEAL) SCHEDULE A [FORM OF BONDS OF SERIES D] No. $ THE CONNECTICUT LIGHT AND POWER COMPANY Incorporated under the Laws of the State of Connecticut FIRST AND REFUNDING MORTGAGE 7-7/8% BOND, 1994 SERIES D PRINCIPAL DUE October 1, 2024 FOR VALUE RECEIVED, THE CONNECTICUT LIGHT AND POWER COMPANY, a corporation organized and existing under the laws of the State of Connecticut (hereinafter called the Company), hereby promises to pay to , or registered --------------- assigns, the principal sum of dollars, on the first day ------------------------ of October, 2024 and to pay interest on said sum, semiannually on the first days of April and October in each year, commencing April 1, 1995, until the Company's obligation with respect to said principal sum shall be discharged, at the rate per annum specified in the title of this bond from the interest payment date next preceding the date of authentication hereof to which interest has been paid on the bonds of this series, or if the date of authentication hereof is prior to March 16, 1995, then from the date of original issuance, or if the date of authentication hereof is an interest payment date to which interest is being paid or a date between the record date for any such interest payment date and such interest payment date, then from such interest payment date. Both principal and interest shall be payable at the office or agency of the Company in the Borough of Manhattan, New York, New York, in such coin or currency of the United States of America as at the time of payment is legal tender for the payment of public and private debts. Each installment of interest hereon (other than overdue interest) shall be payable to the person who shall be the registered owner of this bond at the close of business on the record date, which shall be the March 15 or September 15, as the case may be, next preceding the interest payment date, or, if such March 15 or September 15 shall be a legal holiday or a day on which banking institutions in the Borough of Manhattan, New York, New York, are authorized by law to close, the next preceding day which shall not be a legal holiday or a day on which such institutions are so authorized to close. This bond is subject to repayment on October 1, 2001 at the option of the registered holder hereof exercisable during the period from and including August 1, 2001 to and including September 1, 2001 at a repayment price equal to the principal amount hereof to be repaid, together with interest payable hereon to the repayment date, as described on the reverse hereof. Reference is hereby made to the further provisions of this bond set forth on the reverse hereof, including without limitation provisions in regard to the call and redemption, repayment at option of holder and the registration of transfer and exchangeability of this bond, and such further provisions shall for all purposes have the same effect as though fully set forth in this place. This bond shall not become or be valid or obligatory until the certificate of authentication hereon shall have been signed by Bankers Trust Company (hereinafter with its successors as defined in the Mortgage hereinafter referred to, generally called the Trustee), or by such a successor. IN WITNESS WHEREOF, The Connecticut Light and Power Company has caused this bond to be executed in its corporate name and on its behalf by its President by his signature or a facsimile thereof, and its corporate seal to be affixed or imprinted hereon and attested by the manual or facsimile signature of its Secretary. Dated as of October 1, 1994. THE CONNECTICUT LIGHT AND POWER COMPANY By -------------------------------------- President Attest: Secretary [FORM OF TRUSTEE'S CERTIFICATE] Bankers Trust Company hereby certifies that this bond is one of the bonds described in the within mentioned Mortgage. BANKERS TRUST COMPANY, TRUSTEE By ------------------------------------- Authorized Officer Dated: [FORM OF BOND] [REVERSE] THE CONNECTICUT LIGHT AND POWER COMPANY FIRST AND REFUNDING MORTGAGE 7-7/8% BOND, 1994 SERIES D This bond is one of an issue of bonds of the Company, of an unlimited authorized amount of coupon bonds or registered bonds without coupons, or both, known as its First and Refunding Mortgage Bonds, all issued or to be issued in one or more series, and is one of a series of said bonds limited in principal amount to one hundred and forty million dollars ($140,000,000), consisting only of registered bonds without coupons and designated "First and Refunding Mortgage 7-7/8% Bonds, 1994 Series D," all of which bonds are issued or are to be issued under, and equally and ratably secured by, a certain Indenture of Mortgage and Deed and Trust dated as of May 1, 1921, and by sixty-three Supplemental Indentures dated respectively as of May 1, 1921, February 1, 1924, July 1, 1926, June 20, 1928, June 1, 1932, July 1, 1932, July 1, 1935, September 1, 1936, October 20, 1936, December 1, 1936, December 1, 1938, August 31, 1944, September 1, 1944, May 1, 1945, October 1, 1945, November 1, 1949, December 1, 1952, December 1, 1955, January 1, 1958, February 1, 1960, April 1, 1961, September 1, 1963, April 1, 1967, May 1, 1967, January 1, 1968, October 1, 1968, December 1, 1969, January 1, 1970, October 1, 1970, December 1, 1971, August 1, 1972, April 1, 1973, March 1, 1974, February 1, 1975, September 1, 1975, May 1, 1977, March 1, 1978, September 1, 1980, October 1, 1981, June 30, 1982, October 1, 1982, July 1, 1983, January 1, 1984, October 1, 1985, September 1, 1986, April 1, 1987, October 1, 1987, November 1, 1987, April 1, 1988, November 1, 1988, June 1, 1989, September 1, 1989, December 1, 1989, April 1, 1992, July 1, 1992, October 1, 1992, July 1, 1993, July 1, 1993, December 1, 1993, February 1, 1994, February 1, 1994, June 1, 1994 and October 1, 1994 (said Indenture of Mortgage and Deed of Trust and Supplemental Indentures being collectively referred to herein as the "Mortgage"), all executed by the Company to Bankers Trust Company, as Trustee, all as provided in the Mortgage to which reference is made for a statement of the property mortgaged and pledged, the nature and extent of the security, the rights of the holders of the bonds in respect thereof and the terms and conditions upon which the bonds may be issued and are secured; but neither the foregoing reference to the Mortgage nor any provision of this bond or of the Mortgage shall affect or impair the obligation of the Company, which is absolute, unconditional and unalterable, to pay at the maturities herein provided the principal of and interest on this bond as herein provided. The principal of this bond may be declared or may become due on the conditions, in the manner and at the time set forth in the Mortgage, upon the happening of an event of default as in the Mortgage provided. This bond is transferable by the registered holder hereof in person or by attorney upon surrender hereof at the office or agency of the Company in the Borough of Manhattan, New York, New York, together with a written instrument of transfer in approved form, signed by the holder, and a new bond or bonds of this series for a like principal amount in authorized denominations will be issued in exchange, all as provided in the Mortgage. Prior to due presentment for registration of transfer of this bond the Company and the Trustee may deem and treat the registered owner hereof as the absolute owner hereof, whether or not this bond be overdue, for the purpose of receiving payment and for all other purposes, and neither the Company nor the Trustee shall be affected by any notice to the contrary. This bond is exchangeable at the option of the registered holder hereof upon surrender hereof, at the office or agency of the Company in the Borough of Manhattan, New York, New York, for an equal principal amount of bonds of this series of other authorized denominations, in the manner and on the terms provided in the Mortgage. Bonds of this series are to be issued initially under a book-entry only system and, except as hereinafter provided, registered in the name of The Depository Trust Company, New York, New York ("DTC") or its nominee, which shall be considered to be the holder of all bonds of this series for all purposes of the Mortgage, including, without limitation, payment by the Company of principal of and interest on such bonds of this series and receipt of notices and exercise of rights of holders of such bonds of this series. There shall be a single bond of this series which shall be immobilized in the custody of DTC with the owners of book-entry interests in bonds of this series ("Book-Entry Interests") having no right to receive bonds of this series in the form of physical securities or certificates. Ownership of Book-Entry Interests shall be shown by book-entry on the system maintained and operated by DTC, its participants (the "Participants") and certain persons acting through the Participants. Transfers of ownership of Book-Entry Interests are to be made only by DTC and the Participants by that book-entry system, the Company and the Trustee having no responsibility therefor so long as bonds of this series are registered in the name of DTC or its nominee. DTC is to maintain records of positions of Participants in bonds of this series, and the Participants and persons acting through Participants are to maintain records of the purchasers and owners of Book-Entry Interests. If DTC or its nominee determines not to continue to act as a depository for the bonds of this series in connection with a book-entry only system, another depository, if available, may act instead and the single bond of this series will be transferred into the name of such other depository or its nominee, in which case the above provisions will continue to apply to the new depository. If the book- entry only system for bonds of this series is discontinued for any reason, upon surrender and cancellation of the single bond of this series registered in the name of the then depository or its nominee, new registered bonds of this series will be issued in authorized denominations to the holders of Book-Entry Interests in principal amounts coinciding with the amounts of Book-Entry Interests shown on the book-entry system immediately prior to the discontinuance thereof. Neither the Trustee nor the Company shall be responsible for the accuracy of the interests shown on that system. The bonds of this series are not subject to redemption as a whole or in part prior to maturity. This bond will be repayable on October 1, 2001, at the option of the registered holder or holders hereof, at 100% of its principal amount together with interest payable to the date of repayment. The repayment option may be exercised by a registered holder or holders of this bond for less than the entire principal amount of the bond, provided the principal amount which is to be repaid to such holder is equal to $1,000 or an integral multiple of $1,000. Such election by a registered holder to tender this bond for repayment will be irrevocable. So long as this bond is held under the book-entry only system referred to above, DTC or its nominee, as registered holder of the bond, will be entitled to tender the bond on October 1, 2001 for repayment and such tender will be effected by means of DTC's Repayment Option Procedures. During the period from and including August 1, 2001 to and including September 1, 2001 or, if September 1, 2001 shall be a legal holiday or a day on which banking institutions in the Borough of Manhattan, New York, New York, are authorized by law to close, the next succeeding day which shall not be a legal holiday or a day on which such institutions are so authorized to close, DTC will receive instructions from its Participant or Participants (acting on behalf of the owner or owners of beneficial interests in this bond) to tender this bond for purchase under DTC's Repayment Option Procedures. Such tender for purchase will be made by DTC by means of a book-entry credit of the bond to the account of the Trustee, provided that DTC receives instructions from the tendering Participant or Participants by Noon on September 1, 2001. Promptly after the recording of such book-entry credit, DTC will provide the Trustee an Agent Put Daily Activity Report in accordance with its Repayment Option Procedures, identifying this bond and the aggregate principal amount hereof as to which such tender for purchase has been made. OWNERS OF BENEFICIAL INTERESTS IN THIS BOND WHO WISH TO EFFECTUATE THE TENDER AND REPAYMENT OF THIS BOND MUST INSTRUCT THEIR RESPECTIVE DTC PARTICIPANT OR PARTICIPANTS A REASONABLE PERIOD OF TIME IN ADVANCE OF SEPTEMBER 1, 2001. If at any time the use of a book-entry only system through DTC (or any successor securities depository) is discontinued with respect to this bond, tender for repayment of the bond on October 1, 2001 shall be made according to the following procedures. The Company must receive at the principal office or agency of the Trustee, in the Borough of Manhattan, New York, New York, during the period from and including August 1, 2001 to and including September 1, 2001 or, if September 1, 2001 shall be a legal holiday or a day on which banking institutions in the Borough of Manhattan, New York, New York, are authorized by law to close, the next succeeding day which shall not be a legal holiday or a day on which such institutions are so authorized to close: (i) this bond with the form entitled "Option to Elect Repayment" below duly completed or (ii) a telegram, telex, facsimile transmission or letter from a member of a national securities exchange or the National Association of Securities Dealers Inc., or a commercial bank or trust company in the United States of America, setting forth the name of the holder of the bond, the principal amount of the bond, the amount of the bond to be repaid, a statement that the option to elect repayment is being exercised thereby and a guarantee that the bond to be repaid with the form entitled "Option to Elect Repayment" on the reverse thereof duly completed will be received by the Company not later than five days (which are not legal holidays or days on which banking institutions in the Borough of Manhattan, New York, New York are authorized by law to close) after the date of such telegram, telex, facsimile transmission or letter, and such bond and duly completed form are received by the Company by such fifth day. Either form of notice duly received during the period from and including August 1, 2001 to and including September 1, 2001 shall be irrevocable. All questions as to the validity, eligibility (including time of receipt) and acceptance of any bond for repayment will be determined by the Company, whose determination shall be final and binding. The Mortgage provides that the Company and the Trustee, with consent of the holders of not less than 66-2/3% in aggregate principal amount of the bonds at the time outstanding which would be affected by the action proposed to be taken, may by supplemental indenture add any provisions to or change or eliminate any of the provisions of the Mortgage or modify the rights of the holders of the bonds and coupons issued thereunder; provided, however, that without the consent of the holder hereof no such supplemental indenture shall affect the terms of payment of the principal of or interest or premium on this bond, or reduce the aforesaid percentage of the bonds the holders of which are required to consent to such a supplemental indenture, or permit the creation by the Company of any mortgage or pledge or lien in the nature thereof ranking prior to or equal with the lien of the Mortgage or deprive the holder hereof of the lien of the Mortgage on any of the property which is subject to the lien thereof. As set forth in the Supplemental Indenture establishing the terms and series of the bonds of this series, each holder of this bond, solely by virtue of its acquisition thereof, shall have and be deemed to have consented, without the need for any further action or consent by such holder, to any and all amendments to the Mortgage which are intended to eliminate or modify in any manner the requirements of the sinking and improvement fund as set forth in Section 6.14 of the Mortgage. No recourse shall be had for the payment of the principal of or the interest on this bond, or any part thereof, or for any claim based thereon or otherwise in respect thereof, to any incorporator, or any past, present or future stockholder, officer or director of the Company, either directly or indirectly, by virtue of any statute or by enforcement of any assessment or otherwise, and any and all liability of the said incorporators, stockholders, officers or directors of the Company in respect to this bond is hereby expressly waived and released by every holder hereof. [FORM OF OPTION TO ELECT REPAYMENT] OPTION TO ELECT REPAYMENT The undersigned hereby irrevocably requests and instructs the Company to repay the within bond (or portion thereof specified below) pursuant to its terms at a price equal to the principal amount thereof, together with interest to the repayment date, to the undersigned, at (Please Print or Typewrite Name, Address and ----------------------------------------------------------------------------- Tax Identification Number of the Undersigned) For this bond to be repaid the Company must receive at the office or agency of the Trustee in the Borough of Manhattan, New York, New York, during the period from and including August 1, 2001 to and including September 1, 2001 or, if September 1, 2001 shall be a legal holiday or a day on which banking institutions in the Borough of Manhattan, New York, New York are authorized by law to close, the next succeeding day which shall not be a legal holiday or a day on which such institutions are so authorized to close: (i) this bond with this "Option to Elect Repayment" form duly completed or (ii) a telegram, telex, facsimile transmission or letter from a member of a national securities exchange or the National Association of Securities Dealers, Inc., or a commercial bank or trust company in the United States of America, setting forth the name of the holder of the bond, the principal amount of the bond, the amount of the bond to be repaid, a statement that the option to elect repayment is being exercised thereby and a guarantee that the bond to be repaid with the form entitled "Option to Elect Repayment" on the reverse of the bond duly completed, will be received by the Company not later than five days (which are not legal holidays or days on which banking institutions in the Borough of Manhattan, New York, New York are authorized by law to close) after the date of such telegram, telex, facsimile transmission or letter, and such bond and form duly completed are received by the Company by such fifth day. If less than the entire principal amount of the within bond is to be repaid, specify the portion thereof (which shall be $1,000 or an integral multiple of $1,000) which the holder elects to have repaid: $ . Specify the -------- denomination or denominations (which shall be $1,000 or an integral multiple of $1,000 in excess of $1,000) of the bond or bonds to be issued to the holder for the amount of the portion of the within bond not being repaid (in the absence of any such specification, one such bond will be issued for the portion not being repaid): $ . -------- Signature NOTICE: The signature on this Option to Elect Repayment must correspond with the name as written upon the face of this bond in every particular without alteration or enlargement or any other change whatsoever. SCHEDULE B PROPERTY SUBJECT TO THE LIEN OF THE MORTGAGE IN CONNECTICUT TOWN OF ANDOVER ALL of the following described rights, privileges and easements situated in the Town of Andover, County of Tolland and State of Connecticut, more particularly described in the following deeds, viz: RECORDED GRANTOR DATE OF INSTRUMENT VOLUME PAGE (1) Jodi M. Conway June 6, 1994 61 410 (2) James Arthur Gorman et al June 9, 1994 61 412 TOWN OF AVON ALL of the following described rights, privileges and easements situated in the Town of Avon, County of Hartford and State of Connecticut, more particularly described in the following deeds, viz: RECORDED GRANTOR DATE OF INSTRUMENT VOLUME PAGE (3) The Secret Lake Association October 15, 1992 267 475 TOWN OF BERLIN ALL of the following described rights, privileges and easements situated in the Town of Berlin, County of Hartford and State of Connecticut, more particularly described in the following deeds, viz: RECORDED GRANTOR DATE OF INSTRUMENT VOLUME PAGE (4) CT Galaxy Properties, Inc. December 8, 1993 354 734 (5) Robert W. Jud et al December 16, 1993 360 649 (6) John P. Lee March 4, 1994 360 652 (7) Stanley Nalewajek et al December 29, 1993 361 890 TOWN OF BRISTOL ALL of the following described rights, privileges and easements situated in the Town of Bristol, County of Hartford and State of Connecticut, more particularly described in the following deeds, viz: RECORDED GRANTOR DATE OF INSTRUMENT VOLUME PAGE (8) ARMC Real Estate Divestiture February 28, 1994 1123 449 Corporation TOWN OF CANTON ALL of the following described rights, privileges and easements situated in the Town of Canton, County of Hartford and State of Connecticut, more particularly described in the following deeds, viz: RECORDED GRANTOR DATE OF INSTRUMENT VOLUME PAGE ------- (9) Shepherd M. Holcombe July 18, 1994 201 890 TOWN OF COLCHESTER ALL of the following described rights, privileges and easements situated in the Town of Colchester, County of New London and State of Connecticut, more particularly described in the following deeds, viz: RECORDED GRANTOR DATE OF INSTRUMENT VOLUME PAGE (10) Donald a. Demar July 25, 1994 364 184 TOWN OF COVENTRY ALL of the following described rights, privileges and easements situated in the Town of Coventry, County of Tolland and State of Connecticut, more particularly described in the following deeds, viz: RECORDED GRANTOR DATE OF INSTRUMENT VOLUME PAGE (11) Pine Knoll Associates March 15, 1994 513 149 (12) S. R. Blanchard, Inc. March 7, 1994 513 153 TOWN OF ELLINGTON ALL of the following described rights, privileges and easements situated in the Town of Ellington, County of Tolland and State of Connecticut, more particularly described in the following deeds, viz: RECORDED GRANTOR DATE OF INSTRUMENT VOLUME PAGE (13) Jacob's Hill Associates, Inc. June 16, 1994 210 238 TOWN OF FARMINGTON ALL of the following described rights, privileges and easements situated in the Town of Farmington, County of Hartford and State of Connecticut, more particularly described in the following deeds, viz: RECORDED GRANTOR DATE OF INSTRUMENT VOLUME PAGE (14) Inwood Associates, Inc. June 8, 1994 483 485 (15) Daigle & Son, Inc. July 15, 1994 486 54 (16) Town of Farmington July 21, 1994 486 56 TOWN OF HARWINTON ALL of the following described rights, privileges and easements situated in the Town of Harwinton, County of Litchfield and State of Connecticut, more particularly described in the following deeds, viz: RECORDED GRANTOR DATE OF INSTRUMENT VOLUME PAGE (17) David J. Nadeau March 15, 1994 134 746 TOWN OF MANCHESTER ALL of the following described rights, privileges and easements situated in the Town of Manchester, County of Hartford and State of Connecticut, more particularly described in the following deeds, viz: RECORDED GRANTOR DATE OF INSTRUMENT VOLUME PAGE (18) Ansaldi Associates May 9, 1994 1693 41 (19) Housing Authority of the June 17, 1994 1698 284 Town of Manchester (20) Warren E. Howland et al December 8, 1983 893 13 (21) Michael A. DeCaprio et al May 15, 1984 899 38 TOWN OF NAUGATUCK ALL of the following described rights, privileges and easements situated in the Town of Naugatuck, County of New Haven and State of Connecticut, more particularly described in the following deeds, viz: RECORDED GRANTOR DATE OF INSTRUMENT VOLUME PAGE (22) A. & J. Property Management, August 26, 1993 380 852 Ltd. TOWN OF NEWINGTON ALL of the following described rights, privileges and easements situated in the Town of Newington, County of Hartford and State of Connecticut, more particularly described in the following deeds, viz: RECORDED GRANTOR DATE OF INSTRUMENT VOLUME PAGE (23) Estate of Domenico Pane May 4, 1994 978 220 (24) Ramblewood, Incorporated` May 23, 1994 985 115 (25) Ramblewood, Incorporated July 13, 1994 992 70 TOWN OF OLD SAYBROOK ALL of the following described rights, privileges and easements situated in the Town of Old Saybrook, County of Middlesex and State of Connecticut, more particularly described in the following deeds, viz: RECORDED GRANTOR DATE OF INSTRUMENT VOLUME PAGE (26) Glenn Michael Rice et al February 5, 1994 315 1079 TOWN OF PLAINFIELD ALL of the following described rights, privileges and easements situated in the Town of Plainfield, County of Windham and State of Connecticut, more particularly described in the following deeds, viz: RECORDED GRANTOR DATE OF INSTRUMENT VOLUME PAGE (27) George Palmisano et al July 12, 1994 223 716 TOWN OF PLAINVILLE ALL of the following described rights, privileges and easements situated in the Town of Plainville, County of Hartford and State of Connecticut, more particularly described in the following deeds, viz: RECORDED GRANTOR DATE OF INSTRUMENT VOLUME PAGE (28) Joseph C. Ciccio et al May 23, 1994 312 179 TOWN OF PUTNAM ALL of the following described rights, privileges and easements situated in the Town of Putnam, County of Windham and State of Connecticut, more particularly described in the following deeds, viz: RECORDED GRANTOR DATE OF INSTRUMENT VOLUME PAGE (29) Mark A. Bard, Inc. March 4, 1994 259 315 TOWN OF ROCKY HILL ALL of the following described rights, privileges and easements situated in the Town of Rocky Hill, County of Hartford and State of Connecticut, more particularly described in the following deeds, viz: RECORDED GRANTOR DATE OF INSTRUMENT VOLUME PAGE (30) F&S Associates June 9, 1994 280 571 (31) Seby Romano Construction June 9, 1994 280 573 Company, Inc. (32) 200 Capital Boulevard January 31, 1990 226 868 Limited Partnership et al TOWN OF SIMSBURY ALL of the following described rights, privileges and easements situated in the Town of Simsbury, County of Hartford and State of Connecticut, more particularly described in the following deeds, viz: RECORDED GRANTOR DATE OF INSTRUMENT VOLUME PAGE (33) Town of Simsbury April 25, 1994 429 1034 TOWN OF SOMERS ALL of the following described rights, privileges and easements situated in the Town of Somers, County of Tolland and State of Connecticut, more particularly described in the following deeds, viz: RECORDED GRANTOR DATE OF INSTRUMENT VOLUME PAGE (34) Frank Lomangino et al March 21, 1994 159 658 TOWN OF SOUTHINGTON ALL of the following described rights, privileges and easements situated in the Town of Southington, County of Hartford and State of Connecticut, more particularly described in the following deeds, viz: RECORDED GRANTOR DATE OF INSTRUMENT VOLUME PAGE (35) Milo & Denorfia Construction, May 23, 1994 598 280 Inc. TOWN OF WATERBURY ALL of the following described rights, privileges and easements situated in the Town of Waterbury, County of New Haven and State of Connecticut, more particularly described in the following deeds, viz: RECORDED GRANTOR DATE OF INSTRUMENT VOLUME PAGE (36) The Bank of Stamford Service July 21, 1993 2989 292 Corporation TOWN OF WESTBROOK ALL of the following described rights, privileges and easements situated in the Town of Westbrook, County of Middlesex and State of Connecticut, more particularly described in the following deeds, viz: RECORDED GRANTOR DATE OF INSTRUMENT VOLUME PAGE (37) Frank Esposito et al July 21, 1994 165 437 TOWN OF WILLINGTON ALL of the following described rights, privileges and easements situated in the Town of Willington, County of Tolland and State of Connecticut, more particularly described in the following deeds, viz: RECORDED GRANTOR DATE OF INSTRUMENT VOLUME PAGE EX-10.1 6 STOCKHOLDER AGREEMENT, dated as of July 1, 1964 among the stockholders of CONNECTICUT YANKEE ATOMIC POWER COMPANY ("Connecticut Yankee"), a Connecticut corporation, namely: State of Stockholder Incorporation ----------- ------------- The Connecticut Light and Power Company Connecticut New England Power Company Massachusetts Boston Edison Company Massachusetts The Hartford Electric Light Company Connecticut The United Illuminating Company Connecticut Western Massachusetts Electric Company Massachusetts Central Maine Power Company Maine Public Service Company of New Hampshire New Hampshire Montaup Electric Company Massachusetts New Bedford Gas and Edison Light Company Massachusetts Cambridge Electric Light Company Massachusetts Central Vermont Public Service Corporation Vermont (collectively the "Stockholders" and individually the "Stockholder"). It is agreed as follows: 1. Relationship Among the Parties ------------------------------ Connecticut Yankee has been organized to provide for the supply of power to the Stockholders. It has commenced the construction of a nuclear electric generating unit of the pressurized water type, which is being designed to have an initial gross capability of approximately 490 megawatts electric, at a site adjacent to the Connecticut River at Haddam Neck, Connecticut (the unit being herein, together with the site and all related facilities, referred to as the "Unit"). Construction of the Unit is being carried out under contract with Westinghouse Electric Corporation and Stone & Webster Engineering Corporation. By separate power contracts (the "Power Contracts") and capital funds agreements (the "Capital Funds Agreements") Connecticut Yankee is agreeing to sell the entire output of the Unit to the Stockholders and the Stockholders are agreeing to purchase the output and to provide Connecticut Yankee with necessary capital funds. The respective percentages of the capacity and output of the Unit to be purchased by the Stockholders will be the same as their respective percentages of stock ownership. The Stockholders' respective stock and entitlement percentages as of the date of this Agreement are as follows: Stock Stockholder Percentage ---------- The Connecticut Light and Power Company 25.0% New England Power Company 15.0% Boston Edison Company 9.5% The Hartford Electric Light Company 9.5% The United Illuminating Company 9.5% Western Massachusetts Electric Company 9.5% Central Maine Power Company 6.0% Public Service Company of New Hampshire 5.0% Montaup Electric Company 4.5% New Bedford Gas and Edison Light Company 2.5% Cambridge Electric Light Company 2.0% Central Vermont Public Service Corporation 2.0% New Bedford Gas and Edison Light Company proposes to transfer the Connecticut Yankee stock owned by it to Cambridge Electric Light Company. If this transfer is consummated, the Power Contract and Capital Funds Agreement between Connecticut Yankee and New Bedford Gas and Edison Light Company will be cancelled, and the Power Contract and Capital Funds Agreement between Connecticut Yankee and Cambridge Electric Light Company will be amended to increase Cambridge Electric Light Company's entitlement and stock percentages from 2.0% to 4.5%. Upon such cancellation of its Power Contract and Capital Funds Agreement New Bedford Gas and Edison Light Company shall cease to have any rights or obligations under this Agreement. 2. Unanimous Consent to Certain Matters ------------------------------------ The Stockholders will not cause or permit Connecticut Yankee to take any of the following actions unless the holders at the time of all of Connecticut Yankee's outstanding common stock consent thereto, by vote or otherwise: (a) the amendment in any material respect of any of the Power Contracts or Capital Funds Agreements; (b) the construction by Connecticut Yankee of an additional generating unit at the Haddam Neck site or elsewhere; and (c) participation by Connecticut Yankee, to a material extent, in any business other than the generation and sale of electric power. However, the amendment of particular Power Contracts and Capital Funds Agreements to effect changes in entitlement and stock percentages shall not constitute such a material amendment, if, after the amendment, the sum of the entitlement percentages of all Stockholders under all Power Contracts then in force, and the sum of the stock percentages of all Stockholders under all Capital Funds Agreements then in force, continues to be 100%. 3. Consent to Construction of Additional Units by Others ----------------------------------------------------- The Stockholders will not cause or permit Connecticut Yankee to make any arrangement with respect to the construction and/or operation by one or more persons other than Connecticut Yankee of additional generating unit(s) at the Haddam Neck site unless the holders at the time of at least 66 2/3% of Connecticut Yankee's outstanding common stock consent thereto by vote. However, if the holders at the time of at least 66 2/3% of Connecticut Yankee's outstanding common stock vote to consent to such a proposed arrangement at a meeting of Stockholders duly held on at least 30 days' notice which shall specify in reasonable detail the proposed arrangement to be voted on, Connecticut Yankee may give effect to such arrangement by selling, leasing or otherwise transferring a portion of the site and of the facilities included in the Unit to one or more other persons proposing to construct additional generating unit(s) at the site, and by contracting with such person or persons with respect to operating and other matters. Any Stockholder who votes against such a proposed arrangement (a "dissenting Stockholder") shall have the right to require the Stockholders who do not vote against the arrangement (the "assenting Stockholders") to purchase the dissenting Stockholder's shares of Connecticut Yankee stock, if the dissenting Stockholder elects to require such purchase by written notice given to the other Stockholders before the meeting at which the vote in question is taken. The dissenting Stockholder shall designate in such notice the date on which such purchase will be effected, which date shall be not less than 90 days nor more than three years after the date on which the vote is taken. In the case of any such purchase of a dissenting Stockholder's shares, the assenting Stockholders shall be obligated to purchase the dissenting Stockholder's shares pro rata, according to their respective holdings of Connecticut Yankee's outstanding stock. However, the assenting Stockholders shall have the right to direct the dissenting Stockholder to transfer its shares and power entitlement to such of them and in such proportions as they may designate. The purchase price to be paid to a dissenting Stockholder for its shares pursuant to this Section shall be the book value thereof as of the date on which the vote in question is taken, as determined in accordance with the formula specified in Section 2 of Article VIII of Connecticut Yankee's By-Laws, as in effect on the date of this Agreement, plus interest thereon at the rate of ---- 6% per annum, from such date to the date of purchase, minus the amount of any ----- dividends or other distributions paid or payable with respect to such shares to stockholders of record on any date subsequent to the date of the vote and prior to the purchase date. The rights and obligations of the dissenting Stockholder and the assenting Stockholders with respect to a purchase of stock under this Section 3 shall be subject to the condition that all necessary regulatory approvals shall have been obtained with respect to the action to be taken by the seller and the action to be taken by the purchaser(s). The parties will use their best efforts to obtain, or to assist in obtaining, the foregoing regulatory approvals. If such regulatory approvals cannot be obtained prior to the specified purchase date, the dissenting Stockholder may postpone the closing by not more than 90 days by written notice to the assenting Stockholders. On the purchase date the dissenting Stockholder shall deliver the certificates representing its share of Connecticut Yankee stock to the designated purchaser(s) against payment of the purchase price by certified or official bank check in New York, Hartford or Boston Clearing House funds. Such certificates shall be duly assigned or accompanied by appropriate instruments of transfer, and the shares transferred shall be free and clear of all liens and encumbrances. All transfer and other similar taxes with respect to the transaction shall be paid by the seller. At the time of the closing the dissenting Stockholder shall assign to the purchaser(s), in such proportions as they may direct, all of the dissenting Stockholder's rights under its Power Contract and Capital Funds Agreement, free and clear of all liens and encumbrances, and the purchaser(s) shall assume, in the same proportions, all of the dissenting Stockholder's obligations under such agreements. Thereafter the dissenting Stockholder will be released, except as hereinafter provided, from all further obligations, and shall have no further rights, under such agreements and this Agreement. If at the time of the closing Connecticut Yankee has in effect a pledge and assignment for security purposes of its Power Contract and Capital Funds Agreement with the dissenting Stockholder, and the pledgee's consent is required for a complete release of the dissenting Stockholder from further obligations under any of such agreements, the parties will use their best efforts to obtain such consent. If such consent cannot be obtained prior to the purchase date, the dissenting Stockholder may elect not to go forward with the sale of its stock. 4. Power Entitlement Upon Failure to Provide Additional Capital ------------------------------------------------------------ If, as the result of any Stockholder's failure to provide capital to Connecticut Yankee as requested by Connecticut Yankee pursuant to Sections 4, 5, or 6 of such Stockholder's Capital Funds Agreement, such Stockholder's entitlement percentage under its Power Contract is in excess of its "capital percentage" (as hereinafter defined), then, in such event and so long as such condition continues, such Stockholder shall, if requested to do so by Stockholders whose respective entitlement percentages are less than their respective capital percentages, enter into appropriate arrangements to sell to such Stockholders at its cost some or all, as such Stockholders may from time to time determine, of its "excess power" (as hereinafter defined). For the purposes of this Section, (i) a Stockholder's "capital percentage" as of any time shall be the percentage which that portion of Connecticut Yankee's then outstanding capital theretofore provided by such Stockholder bears to the aggregate amount of Connecticut Yankee's then outstanding capital theretofore provided by all of the Stockholders, and (ii) a Stockholder's "excess power" as of any time shall be that amount of Connecticut Yankee's capacity and net electric output determined by subtracting such Stockholder's then capital percentage of such capacity and output from such Stockholder's entitlement percentage of such capacity and output. 5. Cancellation of Power Contracts ------------------------------- If at any time: (a) Stockholders owning more than 50% of Connecticut Yankee's outstanding common stock have cancelled their Power Contracts, pursuant to Section 9 thereof, because either (i) the Unit is damaged to the extent of being completely or substantially completely destroyed, or (ii) the Unit is taken by exercise of the right of eminent domain or a similar right or power, and --- (b) Connecticut Yankee has paid in full, or made adequate provision for the payment in full of, all its outstanding bonds and notes and other indebtedness and liabilities, other than its indebtedness to Stockholders for loans and advances made pursuant to Section 6 of the Capital Funds Agreements, then, and in such case, upon the request of any Stockholder who has theretofore so cancelled its Power Contract, the Stockholders whose Power Contracts are still in effect will forthwith cancel their respective Power Contracts pursuant to Section 9 thereof. 6. Arbitration ----------- In case any dispute shall arise as to the interpretation or performance of this Agreement which cannot be settled by mutual agreement, such dispute shall be submitted to arbitration. The parties shall if possible agree upon a single arbitrator. In case of failure to agree upon an arbitrator within 15 days after the delivery by any party to the others of a written notice requesting arbitration, any party may request the American Arbitration Association to appoint the arbitrator. The arbitrator, after opportunity for each of the parties to be heard, shall consider and decide the dispute and notify the parties in writing of his decision. Such decision shall be binding upon the parties, and the expenses of the arbitration shall be borne equally by them. 7. Interpretation -------------- The interpretation and performance of this Agreement shall be in accordance with and controlled by the law of the State of Connecticut. 8. Addresses --------- Except as the parties may otherwise agree, any notice, request or other communication from a party to any other party, relating to this Agreement, or the rights, obligations or performance of the parties hereunder, shall be in writing and shall be effective upon delivery to the other party. Any such communication shall be considered as duly delivered when mailed to the respective post office address of the other party shown following the signature of such other party hereto, or such other post office address as may be designated by written notice given as provided in this Section 8. 9. Successors and Assigns ---------------------- This Agreement shall be binding upon and shall inure to the benefit of and may be performed by the corporate successors of the parties. No assignment of this Agreement, other than to a corporate successor to all or substantially all the electric business and property of a party, shall operate to relieve the assignor of its obligations under this Agreement without the written consent of the remaining parties hereto. 10. Execution in Counterparts ------------------------- This Agreement may be executed in any number of counterparts, each of which shall be an original but all of which together shall constitute one and the same instrument. This Agreement shall become effective at such time as counterparts thereof have been executed by each of the parties and it shall not be a condition to its effectiveness that each of the parties have executed the same counterpart. IN WITNESS WHEREOF, the undersigned parties have executed this Stockholder Agreement dated as of July 1, 1964 by their respective officers thereunto duly authorized. (Stockholder Agreement) ----------------------- THE CONNECTICUT LIGHT AND POWER COMPANY P.O. BOX 2010 Hartford, Connecticut 06101 By /s/ S. R. Knapp -------------------- Chairman (Stockholder Agreement) ----------------------- NEW ENGLAND POWER COMPANY 441 Stuart Street Boston, Massachusetts 02116 By /s/ Robert F. Kramer ------------------------ President (Stockholder Agreement) ----------------------- BOSTON EDISON COMPANY 182 Tremont Street Boston, Massachusetts 02112 By /s/ Charles F. Avila ----------------------- President (Stockholder Agreement) ----------------------- THE HARTFORD ELECTRIC LIGHT COMPANY P.O. BOX 2370 Hartford, Connecticut 06101 By /s/ R. A. Gibson ------------------ Chairman (Stockholder Agreement) ----------------------- THE UNITED ILLUMINATING COMPANY 80 Temple Street New Haven, Connecticut 06506 By /s/ William J. Cooper --------------------------- President (Stockholder Agreement) ----------------------- WESTERN MASSACHUSETTS ELECTRIC COMPANY 174 Brush Hill Avenue West Springfield, Massachusetts 01089 By /s/ Howard J. Cadwell ------------------------ Chairman of the Board (Stockholder Agreement) ----------------------- CENTRAL MAINE POWER COMPANY 9 Green Street Augusta, Maine 04332 By /s/ W. H. Dunham ---------------------- President (Stockholder Agreement) ----------------------- PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE 1087 Elm Street Manchester, New Hampshire 03105 By /s/ D. Miller ------------------------------- President (Stockholder Agreement) ----------------------- MONTAUP ELECTRIC COMPANY 49 Federal Street Boston, Massachusetts 02107 By /s/ Bill M. Perry ----------------------- President (Stockholder Agreement) ----------------------- NEW BEDFORD GAS AND EDISON LIGHT COMPANY 130 Austin Street Cambridge, Massachusetts 02139 By /s/ John F. Rich --------------------------- President CAMBRIDGE ELECTRIC LIGHT COMPANY 130 Austin Street Cambridge, Massachusetts 02139 By /s/ John F. Rich --------------------------- President (Stockholder Agreement) ----------------------- CENTRAL VERMONT PUBLIC SERVICE CORPORATION 77 Grove Street Rutland, Vermont 05701 EX-10.2 7 [COMPOSITE CONFORMED COPY] POWER CONTRACT, dated as of July 1, 1964, between CONNECTICUT YANKEE ATOMIC POWER COMPANY ("Connecticut Yankee"), a Connecticut corporation, and (The names of the Purchasers appear in the attached Appendix) (the "Purchaser"). It is agreed as follows: 1. Basic Understandings Connecticut Yankee has been organized to provide for the supply of power to the twelve utility companies (including the Purchaser) which are its stockholders. It has commenced the construction of a nuclear electric generating unit of the pressurized water type, which is being designed to have an initial gross capability of approximately 490 megawatts electric, at a site adjacent to the Connecticut River at Haddam Neck, Connecticut (the unit being herein, together with the site and all related facilities, referred to as the "Unit"). Construction of the Unit is being carried out under contracts with Westinghouse Electric Corporation and Stone & Webster Engineering Corporation. The Unit is to be operated to supply power to Connecticut Yankee's stockholders, each of which is undertaking to purchase a fixed percentage of the capacity and output of the Unit. The respective percentages of the capacity and output of the Unit to be purchased by the Purchaser and the other Connecticut Yankee stockholders are the same as the respective percentages of Connecticut Yankee's stock now owned by them. The names of the stockholders and their respective percentages ("entitlement percentages") of the capacity and output of the Unit are as follows: Stockholder Entitlement Percentage The Connecticut Light and Power Company 25.0% New England Power Company 15.0% Boston Edison Company 9.5% The Hartford Electric Light Company 9.5% The United Illuminating Company 9.5% Western Massachusetts Electric Company 9.5% Central Maine Power Company 6.0% Public Service Company of New Hampshire 5.0% Montaup Electric Company 4.5% New Bedford Gas and Edison Light Company* 2.5% Cambridge Electric Light Company* 2.0% Central Vermont Public Service Corporation 2.0% Connecticut Yankee and its other stockholders are entering into power contracts which are identical to this contract except for necessary changes in the names of the parties. New Bedford Gas and Edison Light Company has informed Connecticut Yankee that it proposes to transfer the Connecticut Yankee stock owned by it to Cambridge Electric Light Company. If this transfer is consummated, the Power Contract between Connecticut Yankee and New Bedford Gas and Edison Light Company will be cancelled and the contract between Connecticut Yankee and Cambridge Electric Light Company will be amended to increase Cambridge Electric Light Company's entitlement percentage from 2.0% to 4.5%.* * As contemplated by Section 1 of the contract, New Bedford Gas and Edison Light Company has transferred the Connecticut Yankee stock owned by it to Cambridge Electric Light Company, the Power Contract between Connecticut Yankee and New Bedford Gas and Edison Light Company has been cancelled, and the contract between Connecticut Yankee and Cambridge Electric Light Company has been amended to increase Cambridge Electric Light Company's entitlement percentage from 2.0% to 4.5%. As a result of the transfer by New Bedford Gas and Edison Light Company of the Connecticut Yankee stock owned by it to Cambridge Electric Light Company, the number of Connecticut Yankee's stockholders has been reduced from twelve to eleven. 2. Effective Date and Term This contract shall become effective upon receipt by the Purchaser of notice that Connecticut Yankee has entered into power contracts, as contemplated by Section 1 above, with each of its other stockholders. The term of this contract shall expire 30 years after the plant completion date. The "plant completion date" shall be the earlier of (i) October 1, 1968, and (ii) the date on which the Unit is placed in commercial operation, as determined by Connecticut Yankee (the "commercial operation date"). 3. Construction of the Unit Connecticut Yankee will proceed with due diligence with construction of the Unit, and will exercise its best efforts to complete and place it in commercial operation by October 1, 1967, on the presently estimated schedule therefor and within present cost estimates, and will keep the Purchaser currently informed as to the progress of construction and expected plant completion date. 4. Operation and Maintenance of the Unit Connecticut Yankee will operate and maintain the Unit in accordance with good utility practice under the circumstances and all applicable law, including the applicable provisions of the Atomic Energy Act of 1954 and of any license issued thereunder to Connecticut Yankee. Within the limits imposed by good utility practice under the circumstances and applicable law, the Unit will be operated at its maximum capability and on a long hour use basis. Outages for inspection, maintenance, refueling and repairs and replacements will be scheduled in accordance with good utility practice and insofar as practicable shall be mutually agreed upon by Connecticut Yankee and the Purchaser. In the event of an outage, Connecticut Yankee will use its best efforts to restore the Unit to service as promptly as possible. 5. Purchaser's Entitlement The Purchaser will, throughout the term of this contract, be entitled and obligated to take its entitlement percentage of the capacity and net electrical output of the Unit, at all levels at which the Unit is operated or operable, whether more or less than 490 megawatts electric. 6. Deliveries and Metering The Purchaser's entitlement percentage of the output of the Unit will be delivered to and accepted by it at the step-up substation at the site. All deliveries will be made in the form of 3-phase, 60 cycle, alternating current at a nominal voltage of 345,000 volts. The Purchaser will make its own arrangements for the transmission of the power. Connecticut Yankee will supply and maintain all necessary metering equipment for determining the quantity and conditions of supply of deliveries under this contract, will make appropriate tests of such equipment in accordance with good utility practice and as reasonably requested by the Purchaser, and will maintain the accuracy of such equipment within reasonable limits. Connecticut Yankee will furnish the Purchaser with such summaries of meter readings as the Purchaser may reasonably request. 7. Payment With respect to each month commencing prior to the plant completion date, the Purchaser will pay Connecticut Yankee at the rate of 5 mills per kilowatt hour, for the Purchaser's entitlement percentage of the net electrical output (if any) of the Unit during the particular month. With respect to each month commencing on or after the plant completion date, the Purchaser will pay Connecticut Yankee an amount equal to the Purchaser's entitlement percentage of the sum of (a) Connecticut Yankee's total operating expenses for the month with respect to the Unit, plus (b) an amount equal to one-twelfth of 6% per annum of the net Unit investment as most recently determined in accordance with this Section 7. Connecticut Yankee's "operating expenses" shall include all amounts properly chargeable to operating expense accounts, less any applicable credits thereto, in accordance with the Uniform System of Accounts (the "Uniform System") prescribed by the Federal Power Commission for Class A and Class B Public Utilities and Licensees as in effect on the date of this contract; provided, that, for purposes of this contract, the accrual of depreciation as an operating expense shall commence on the plant completion date at the rate of 4% per annum, whether or not the Unit is then in operation, and during each of the first twenty-five years after the plant completion date the amount included in operating expenses on account of depreciation accruals (and amortization, if any, of property losses) shall in no event be less than 4% of the excess of: (a) the amount properly chargeable at the plant completion date in accordance with the Uniform System to electric plant accounts (including construction work in progress) with respect to the depreciable portion of the Unit (or, if the plant completion date is prior to the commercial operation date and the amount so chargeable with respect to the depreciable portion of the Unit on the commercial operation date is greater than it was on the plant completion date, then such greater amount), over (b) the amount of net available cash. The "net Unit investment" shall consist, in each case with respect to the Unit, of (i) the aggregate amount properly chargeable at the time in accordance with the Uniform System to Connecticut Yankee's electric plant accounts (including construction work in progress), less the balance, if any, at the time of the accumulated provision for depreciation, as determined in accordance with the Uniform System; plus (ii) the aggregate amount properly chargeable at the time in accordance with the Uniform System to accounts representing materials and supplies; plus (iii) such reasonable allowances for prepaid items and cash working capital as may from time to time be determined by Connecticut Yankee. However, for purposes of this contract, the net amount included at any date after the plant completion date in net Unit investment under clause (i) of the immediately preceding sentence shall in no event be less than the excess of: (a) the amount properly chargeable at the plant completion date in accordance with the Uniform System to electric plant accounts (including construction work in progress) with respect to the Unit (or, if the plant completion date is prior to the commercial operation date and the amount so chargeable with respect to the Unit on the commercial operation date is greater than it was on the plant completion date, then such greater amount), over (b) the sum of (1) the aggregate minimum amount required by the proviso to the third paragraph of this Section 7 to be included in operating expenses from the plant completion date to the date in question on account of depreciation accruals (and amortization, if any, of property losses), plus (2) the amount of net available cash. The net Unit investment shall be determined as of the plant completion date and thereafter as of the commencement of each calendar year, or, if Connecticut Yankee elects, at more frequent intervals. "Net available cash" means, at any date as of which the amount thereof is to be determined, the excess of (a) the aggregate amount received by Connecticut Yankee after the plant completion date and prior to two years before the determination date as insurance proceeds on account of loss or damage to the Unit or as the proceeds of a sale or condemnation of a portion of the Unit, over (b) the aggregate amount expended after the plant completion date and prior to the determination date on account of rebuilding, repairs, replacements and additions to the Unit, provided that insurance proceeds received with respect to a particular loss shall be taken into account for purposes of the foregoing computation only if the amount received with respect to the loss exceeds $150,000. Connecticut Yankee will bill the Purchaser, as soon as practicable after the end of each month, for all amounts payable by the Purchaser with respect to the particular month. Such bills will be rendered in such detail as the Purchaser may reasonably request and may be rendered on an estimated basis subject to corrective adjustments in subsequent billing periods. All bills shall be paid in full within 10 days after receipt thereof by the Purchaser. 8. Make-up Term and Option Term (a) The Purchaser may elect to extend the contract term by written notice to Connecticut Yankee upon the following conditions and for the following period or periods: (i) in the event that the Unit is not in commercial operation on the plant completion date, the contract term may be extended for a period equal to the number of consecutive days by which commercial operation is delayed beyond the plant completion date; and (ii) if at any time after the commencement of commercial operation no deliveries are made under this contract for a period of at least 120 consecutive days, the contract may be extended for a period equal to the aggregate of such periods during which no deliveries were made. If the term of the contract is extended pursuant to the provisions of this subsection (a), all of the contract provisions shall remain in effect for the extended term. (b) Upon expiration of the initial term of this contract or upon expiration of the term as extended in accordance with subsection (a) of this Section 8, the Purchaser shall continue to be entitled, at its option, to its entitlement percentage of the capacity and output of the Unit upon terms at least as favorable as those obtained by any other person. 9. Cancellation of Contract If deliveries cannot be made to the Purchaser because either (i) the Unit is damaged to the extent of being completely or substantially completely destroyed, or (ii) the Unit is taken by exercise of the right of eminent domain or a similar right or power, or (iii) (a) the Unit cannot be used because of contamination, or because a necessary license or other necessary public authorization cannot be obtained or is revoked, or because the utilization of such a license or authorization is made subject to specified conditions which are not met, and (b) the situation cannot be rectified to an extent which will permit Connecticut Yankee to make deliveries to the Purchaser from the Unit; then and in any such case, the Purchaser may cancel this contract. Such cancellation shall be effected by written notice given by the Purchaser to Connecticut Yankee. In the event of such cancellation, all continuing obligations of the parties, including the Purchaser's obligations to continue payments, shall cease forthwith. Any dispute as to the Purchaser's right to cancel this contract pursuant to the foregoing provisions shall be referred to arbitration in accordance with the provisions of Section 13. Notwithstanding anything in this contract elsewhere contained, the Purchaser may cancel this contract or be relieved of its obligations to make payments hereunder only as provided in the next preceding paragraph of this Section 9. Further, if for reasons beyond Connecticut Yankee's reasonable control, deliveries are not made as contemplated by this contract, Connecticut Yankee shall have no liability to the Purchaser on account of such non-delivery. 10. Insurance Prior to the first shipment of fuel to the plant site, Connecticut Yankee will obtain, and thereafter will at all times maintain, insurance to cover its "public liability" for personal injury and property damage resulting from a "nuclear incident" (as those terms are defined in the Atomic Energy Act of 1954, as amended), with limits not less than Connecticut Yankee may be required to maintain to qualify for governmental indemnity under said Act and shall execute and maintain an indemnification agreement with the Atomic Energy Commission as provided by said Act. Connecticut Yankee will also at all times maintain such other types of liability insurance, including workmen's compensation insurance, in such amounts, as is customary in the case of other similar electric utility companies, or as may be required by law. Connecticut Yankee will at all times keep insured such portions of the Unit as are of a character usually insured by electric utility companies, similarly situated and operating like properties, against the risk of a "nuclear incident", and such other risks as electric utility companies, similarly situated and operating like properties, usually insure against. Such insurance shall to the extent available be carried in an amount at least equal to the original cost of the insured facilities, less accrued depreciation thereon. 11. Additional Units Connecticut Yankee or its nominee may install one or more additional generating units at the Haddam Neck site. The installation of such unit or units shall not affect the terms of this contract, but in such case, if and to the extent appropriate, if any portion of the Unit (whether such portion constitutes land, structures or equipment) is also used with the additional unit(s), an appropriate allocation of the cost of the Unit shall be made and the net Unit investment shall be reduced accordingly, subject, however, to the limitation that the aggregate amount of the reduction in net Unit investment resulting from all such allocations shall not exceed $2,000,000. 12. Audit Connecticut Yankee's books and records (including metering records) shall be open to reasonable inspection and audit by the Purchaser. 13. Arbitration In case any dispute shall arise as to the interpretation or performance of this contract which cannot be settled by mutual agreement, such dispute shall be submitted to arbitration. The parties shall if possible agree upon a single arbitrator. In case of failure to agree upon an arbitrator within 15 days after the delivery by either party to the other of a written notice requesting arbitration, either party may request the American Arbitration Association to appoint the arbitrator. The arbitrator, after opportunity for each of the parties to be heard, shall consider and decide the dispute and notify the parties in writing of his decision. Such decision shall be binding upon the parties, and the expenses of the arbitration shall be borne equally by them. 14. Regulation This contract, and all rights, obligations and performance of the parties hereunder, are subject to all applicable state and federal law and to all duly promulgated orders and other duly authorized action of governmental authority having jurisdiction in the premises. 15. Assignment This contract shall be binding upon and shall inure to the benefit of, and may be performed by, the successors and assigns of the parties, except that no assignment, pledge or other transfer of this contract by either party shall operate to release the assignor, pledgor or transferor of any of its obligations under this contract unless consent to the release is given in writing by the other party, or, if the other party has theretofore assigned, pledged or otherwise transferred its interest in this contract, by the other party's assignee, pledgee or transferee. 16. Right of Setoff The Purchaser shall not be entitled to set off against the payments required to be made by it under this contract (i) any amounts owed to it by Connecticut Yankee or (ii) the amount of any claim by it against Connecticut Yankee. However, the foregoing shall not affect in any other way the Purchaser's rights and remedies with respect to any such amounts owed to it by Connecticut Yankee or any such claim by it against Connecticut Yankee. 17. Interpretation The interpretation and performance of this contract shall be in accordance with and controlled by the law of the State of Connecticut. 18. Addresses Except as the parties may otherwise agree, any notice, request, bill or other communication from one party to the other, relating to this contract, or the rights, obligations or performance of the parties hereunder, shall be in writing and shall be effective upon delivery to the other party. Any such com- munication shall be considered as duly delivered when mailed to the respective post office address of the other party shown following the signatures of such other party hereto, or such other post office address as may be designated by written notice given as provided in this Section 18. 19. Corporate Obligations This contract is the corporate act and obligation of the parties hereto, and any claim hereunder against any stockholder, director or officer of either party, as such, is expressly waived. 20. All Prior Agreements Superseded This contract represents the entire agreement between us relating to the subject matter hereof, and all previous agreements, discussions, communications and correspondence with respect to the subject matter are hereby superseded and are of no further force and effect. IN WITNESS WHEREOF, the parties have executed this contract by their respective officers thereunto duly authorized as of the date first above written. CONNECTICUT YANKEE ATOMIC POWER COMPANY Attest: By --------------------------------- Its --------------------------- ----------------------------- P.O. Box 2010 Hartford, Connecticut 06101 (Purchaser) Attest: By ---------------------------------- (Officer) --------------------------- Its ----------------------------- (Title) (Address) (Forms of signatures appear in the attached Appendix) APPENDIX Separate Power Contracts were entered into, identical in form with the foregoing except as to the execution thereof and except that on page 1 the names of the respective Purchasers were inserted. The Power Contracts were executed by the respective parties thereto, under their Corporate seals, as follows: Attest: CONNECTICUT YANKEE ATOMIC POWER COMPANY R. F. PROBST By S. R. KNAPP Secretary Its President P.O. Box 2010 (CORPORATE SEAL) Hartford, Connecticut 06101 Attest: THE CONNECTICUT LIGHT AND POWER COMPANY C. J. RAMAGE By PAUL V. HAYDEN Assistant Secretary Its President P.O. Box 2010 (CORPORATE SEAL) Hartford, Connecticut 06101 Attest: NEW ENGLAND POWER COMPANY JOSEPH X. CORBETT By ROBERT F. KRAUSE Clerk Its President 441 Stuart Street (CORPORATE SEAL) Boston, Massachusetts 02116 Attest: BOSTON EDISON COMPANY EDWIN J. LEE By CHARLES F. AVILA Clerk Its President 182 Tremont Street (CORPORATE SEAL) Boston, Massachusetts 02112 Attest: THE HARTFORD ELECTRIC LIGHT COMPANY J. B. MADIGAN By R. A. GIBSON Secretary Its Chairman P.O. Box 2370 (CORPORATE SEAL) Hartford, Connecticut 06101 Attest: THE UNITED ILLUMINATING COMPANY A. ROYAL WOOD By WILLIAM J. COOPER Secretary Its President 80 Temple Street (CORPORATE SEAL) New Haven, Connecticut 06506 Attest: WESTERN MASSACHUSETTS ELECTRIC COMPANY N. F. PLANTE By HOWARD J. CADWELL Clerk Its Chairman of the Board 174 Brush Hill Avenue (CORPORATE SEAL) W. Springfield, Massachusetts 01089 Attest: CENTRAL MAINE POWER COMPANY C. W. TOTMAN By W. H. DUNHAM Assistant Secretary Its President 9 Green Street (CORPORATE SEAL) Augusta, Maine 04332 Attest: PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE ANNABELLE LANDERS By A. R. SCHILLER Secretary Its President 1087 Elm Street (CORPORATE SEAL) Manchester, New Hampshire 03105 Attest: MONTAUP ELECTRIC COMPANY R. M. KEITH By GUIDO R. PERERA Clerk Its President 49 Federal Street (CORPORATE SEAL) Boston, Massachusetts 02107 Attest: NEW BEDFORD GAS AND EDISON LIGHT COMPANY* R. E. ROLLS By JOHN F. RICH Clerk Its President 130 Austin Street (CORPORATE SEAL) Cambridge, Massachusetts 02139 * The contract between Connecticut Yankee and New Bedford Gas and Edison Light Company has been cancelled. Attest: CAMBRIDGE ELECTRIC LIGHT COMPANY R. E. ROLLS By JOHN F. RICH Clerk Its President 130 Austin Street (CORPORATE SEAL) Cambridge, Massachusetts 02139 Attest: CENTRAL VERMONT PUBLIC SERVICE CORPORATION PORTER E. NOBLE By ALBERT A. CREE Clerk Its Chairman EX-10.2.1 8 ADDITIONAL POWER CONTRACT ADDITIONAL POWER CONTRACT, dated as of April 30, 1984, between CONNECTICUT YANKEE ATOMIC POWER COMPANY ("Connecticut Yankee"), a Connecticut corporation, and The Connecticut Light and Power Company, (the "Purchaser"). In consideration of the following understandings and the respective undertakings of the parties, it is agreed as follows: 1. Basic Understandings. Connecticut Yankee was organized in 1962 to provide for the supply of power to its sponsoring utility companies (including the Purchaser). Connecticut Yankee constructed a nuclear electric generating unit of the pressurized water type, having a maximum net capability of approximately 582 megawatts electric, at a site adjacent to the Connecticut River at Haddam, Connecticut (said unit, together with the site and all related facilities owned or to be owned by Connecticut Yankee, being referred to herein as the "Unit"). On June 30, 1967, Connecticut Yankee was issued a full-term, operating license for the Unit from the Atomic Energy Commission (now the Nuclear Regulatory Commission which, together with any successor agency or agencies, is hereafter called the "NRC"), which license expires on May 26, 2004, and the Unit commenced commercial operation on January 1, 1968. The Unit is operated to supply power to the purchasers from Connecticut Yankee (collectively the "Purchasers"), each of which by a Power Contract dated as of July 1, 1964, as supplemented by Supplementary Power Contracts dated as of March 1, 1978, such Supplementary Power Contracts amended on August 22, 1980 and October 15, 1982 (collectively the "Power Contracts"), has undertaken to purchase a fixed percentage of the capacity and output of the Unit for a term extending through December 31, 1997. The names of the Purchasers and their respective percentages ("entitlement percentages") of the capacity and output of the Unit are as follows: Entitlement Percentage The Connecticut Light and Power Company 34.5% New England Power Company 15.0 Western Massachusetts Electric Company 9.5 The United Illuminating Company 9.5 Boston Edison Company 9.5 Central Maine Power Company 6.0 Public Service Company of New Hampshire 5.0 Montaup Electric Company 4.5 Cambridge Electric Light Company 4.5 Central Vermont Public Service Corporation 2.0 The Power Contracts have been supplemented most recently by Second Supplementary Power Contracts, dated as of 1984, between Connecticut Yankee and each of the Purchasers (the "Second Supplementary Power Contracts"). The Second Supplementary Power Contracts provide for the collection of funds to defray the ultimate cost of decommissioning the Unit and to provide an allowance for potential taxes payable by Connecticut Yankee with respect to the decommissioning fund. Connecticut Yankee and the Purchasers desire to provide for the orderly continuation of the sale and purchase of the capacity and output of the Unit during the useful life of the Unit to the extent that such useful life continues beyond the termination date of the Power Contracts and the Second Supplementary Power Contracts and to provide appropriate provisions for the collection of funds for, and the payment of, decommissioning costs and any other costs, including potential taxes, with respect to the Unit during and after the useful life of the Unit. Connecticut Yankee and the other Purchasers are entering into Additional Power Contracts which are identical to this contract except for necessary changes in the names of the parties. 2. Effective Date, Term and Waiver. This contract shall become effective upon receipt by the Purchaser of notice that Connecticut Yankee has entered into Additional Power Contracts, as contemplated by Section 1 above, with each of the other Purchasers. The operative term of this contract shall commence on January 1, 1998 notwithstanding the fact that the useful service life of the Unit may have been terminated prior to that date, and shall terminate upon the later to occur of (i) 30 days after the date on which the last of the financial obligations of Connecticut Yankee which constitute elements of the payment calculated pursuant to Section 7 of this contract has been extinguished by Connecticut Yankee, or (ii) 30 days after the date on which Connecticut Yankee is finally relieved of any obligations under the last of any licenses (operating and/or possessory) which it now holds from, or which may hereafter be issued to it by, the NRC with respect to the Unit under applicable provisions of the Atomic Energy Act of 1954, as amended from time to time (the "Act"). Connecticut Yankee and the Purchaser acknowledge that, if the useful service life of the Unit is terminated prior to January 1, 1998, then only the provisions of this contract applicable to decommissioning of the Unit will apply during the operative term of this contract. The Purchaser hereby irrevocably waives its right to extend the contract term of its Power Contract pursuant to subsections (a) or (b) of Section 8 thereof. 3. Operation and Maintenance of the Unit. Connecticut Yankee will operate and maintain the Unit in accordance with good utility practice under the circumstances and all applicable law, including the applicable provisions of the Act and of any licenses issued thereunder to Connecticut Yankee. Within the limits imposed by good utility practice under the circumstances and applicable law, the Unit will be operated at its maximum capability and on a long hour use basis. Outages for inspection, maintenance, refueling and repairs and replacements will be scheduled in accordance with good utility practice and insofar as practicable shall be mutually agreed upon by Connecticut Yankee and the Purchaser. In the event of an outage, Connecticut Yankee will use its best efforts to restore the Unit to service as promptly as practicable. 4. Decommissioning. After commercial operation of the Unit permanently ceases, Connecticut Yankee will decommission the Unit in a manner authorized by Connecticut Yankee's board of directors and approved by the NRC in accordance with the Act and the rules and regulations thereunder then in effect and by any agency having jurisdiction over decommissioning of the Unit. It is understood that, pursuant to the Second Supplementary Power Contracts, the Purchasers are currently being billed for Total Decommissioning Costs which, as of the date of this contract, are being accumulated in a separate fund which was established for the purpose of reimbursing Connecticut Yankee for Decommissioning Expenses incurred in the process of decommissioning the Unit and that such billings are subject to change in accordance with the provisions of the Second Supplementary Power Contracts subject to the jurisdiction of the Federal Energy Regulatory Commission or any successor agency thereto (the "FERC"). It is contemplated that sufficient funds will be accumulated pursuant to those contracts and paragraph 7 hereof to make payment to reimburse Connecticut Yankee for the full cost of decommissioning the Unit. The Purchaser will, throughout the term of this contract, be entitled and obligated to take its entitlement percentage of the capacity and net electrical output of the Unit, at whatever level the Unit is operated or operable, whether more or less than 582 megawatts electric. 6. Deliveries and Metering. The Purchaser's entitlement percentage of the output of the Unit will be delivered to and accepted by the Purchaser at the step-up substation at the site. All deliveries will be made in the form of 3-phase, 60 cycle, alternating current at a nominal voltage of 345,000 volts. The Purchaser will make its own arrangements for the transmission of its entitlement percentage of the output of the Unit. Connecticut Yankee will supply and maintain all necessary metering equipment for determining the quantity and conditions of supply of deliveries under this contract, will make appropriate tests of such equipment in accordance with good utility practice and as reasonably requested by the Purchaser, and will maintain the accuracy of such equipment within reasonable limits. Connecticut Yankee will furnish the Purchaser with such summaries of meter readings as the Purchaser may reasonably request. 7. Payment. With respect to each month commencing on or after January 1, 1998, the Purchaser will pay Connecticut Yankee an amount equal to the Purchaser's entitlement percentage of the sum of (a) the Total Decommissioning Costs for the month with respect to the Unit, plus (b) Connecticut Yankee's total operating expenses for the month with respect to the Unit, plus (c) an amount equal to one-twelfth of the composite percentage for such month of the net Unit investment as most recently determined in accordance with this Section 7. "Composite percentage" shall be computed as of the last day of each month during the term hereof (the "computation date") and for any month the composite percentage shall be that computed as of the last day of the previous month. "Composite percentage" as of a computation date shall be the sum of (i) the equity percentage as of such date multiplied by the ratio which the equity investment with respect to the Unit, as of such date, is to the total capital as of such date; plus (ii) the "effective interest rate" per annum of each principal amount of long-term debt outstanding on such date for money borrowed with respect to the Unit, multiplied by the ratio which such principal amount is to total capital as of such date; plus (iii) the "effective dividend rate" per annum of each series of preferred stock outstanding as of such date with respect to the Unit multiplied by the ratio which the amount at which such preferred stock would be reflected on a balance sheet of Connecticut Yankee is to total capital as of such date. The "effective interest rate" of each principal amount of long-term debt referred to in clause (ii) will reflect the annual interest requirements and to the extent applicable, amortization of issue expenses, discounts and premiums, sinking fund call premiums, expenses and discounts, refunding and retirement expenses, discounts and premiums, and all other expenses applicable to the issue of such indebtedness. The "effective dividend rate" of each series of preferred stock referred to in clause (iii) will reflect the annual dividend requirements applicable to each such series of preferred stock. "Equity percentage" as of any date after commencement of the operative term hereof shall be that percentage which was the "equity percentage" applicable under the Power Contracts on the last day of the term of the Power Contracts or such other percentage as may from time to time thereafter be approved by the FERC or any successor regulatory authority. "Equity investment" as of any date shall consist of the sum of (i) all amounts theretofore paid to Connecticut Yankee for all common capital stock theretofore issued, plus all amounts paid to Connecticut Yankee by any of its common stockholders as capital contributions or advances less the sum of any amounts paid by Connecticut Yankee to its common stockholders in the form of stock retirements, repurchases or redemptions, return of capital or repayments of such contributions or advances; plus (ii) any credit balance in the capital surplus account not included under (i) and in the retained earnings account on the books of Connecticut Yankee as of such date. "Total capital" as of any date shall be the equity investment with respect to the Unit, plus the total of the amount which would be reflected on a balance sheet of Connecticut Yankee for all other securities (excluding short-term debt), including long-term debt and preferred stock then outstanding with respect to the Unit. "Uniform System" shall mean the Uniform System of Accounts prescribed by the FERC for Class A and Class B Public Utilities and Licensees, as from-time to time in effect. Connecticut Yankee's "operating expenses" shall include all amounts properly chargeable to operating expense accounts, less any applicable credits thereto, in accordance with the Uniform System; however, excluding for purposes of this contract Total Decommissioning Costs. "net Unit investment" shall consist, in each case with respect to the Unit, of (i) the aggregate amount properly chargeable at the time in accordance with the Uniform System to Connecticut Yankee's plant accounts (including - construction work in progress to the extent allowed by the FERC) less the balance, if any, at the time of the accumulated provision for depreciation, as determined in accordance with the Uniform System (excluding any amounts specifically allowed by the FERC to be so excluded); plus (ii) the aggregate amount properly chargeable at the time in accordance with the Uniform System to accounts representing materials and supplies; plus (iii) such reasonable allowances for prepaid items and cash working capital as may from time to time be determined by Connecticut Yankee and, for purposes hereof, net Unit investment shall include, in addition to all other amounts which may be includable therein under this section, but without duplication, the aggregate amount properly chargeable at the time in accordance with the Uniform System to Connecticut Yankee's nuclear fuel accounts (other than nuclear fuel in process of fabrication), less the balance at the time of the accumulated provision for amortization of the cost of nuclear fuel (excluding any amounts specifically permitted by the FERC), all as determined in accordance with the Uniform System. The net Unit investment shall be determined as of the commencement of each calendar year, or, if Connecticut Yankee elects, at more frequent intervals. "Total Decommissioning Costs" for any month shall mean the sum of (x) an amount equal to all accruals in such month to any reserve, as from time to time established by Connecticut Yankee and approved by its board of directors to provide for the ultimate payment of the Decommissioning Expenses of the Unit plus (y) Decommissioning Tax Liability for such month. It is understood (i) that such funds may be held by Connecticut Yankee or by an independent trust or other separate fund, as determined by said board of directors, (ii) that, upon compliance with Section 17 hereof, the amount, custody and/or timing of such accruals may from time to time during the term hereof be modified by said board of d rectors in its discretion or to comply with applicable statutory or regulatory requirements or to reflect changes in the amount, custody or timing of anticipated Decommissioning Expenses, and (iii) that the use of the term "to decommission" herein encompasses compliance with all requirements (other than those relating to spent nuclear fuel) of the NRC for permanent cessation of operation of a nuclear facility and any other activities reasonably related thereto. "Decommissioning Expenses" shall include: (1) All costs and expenses of removing the Unit from service, including without limitation, dismantling, mothballing, removing radioactive material (excluding spent nuclear fuel) to temporary and/or permanent storage sites, decontaminating, restoring and supervising the site, and any costs and expenses incurred in connection with proceedings before governmental authorities relating to any authorization to decommission the Unit or remove the Unit from service; (2) All costs of labor and services, whether directly or indirectly incurred, including without limitation, services of foremen, inspectors, supervisors surveyors, engineers, security personnel, counsel and accountants, performed or rendered in connection with the decommissioning of the Unit and the removal of the Unit from service, and all costs of materials, supplies, machinery, construction equipment and apparatus acquired or used (including rental charges for machinery equipment or apparatus hired) for or in connection with the decommissioning of the Unit and the removal of the Unit from service, and all administrative costs, including services of counsel and financial advisers, of any applicable independent trust or other separate fund; it being understood that any amount, exclusive of proceeds of insurance, realized by Connecticut Yankee as salvage on any machinery, construction equipment and apparatus, the cost of which was charged to Decommissioning Expense, shall be treated as a reduction of the amounts otherwise chargeable on account of the costs of decommissioning of the Unit; and (3) All overhead costs applicable to the Unit during its decommissioning period, including, without limiting the generality of the foregoing, taxes (other than taxes on or in respect of income), charges, licenses, excises and assessments, casualties, surety bond premiums and insurance premiums. "Decommissioning Tax Liability" for any month shall be an amount established by Connecticut Yankee and approved by its board of directors to meet possible income tax obligations, which amount shall not exceed: the amount to be included in the clause (x) portion of Total Decommissioning Costs for such month multiplied by a fraction whose numerator is equal to the combined highest applicable statutory Federal and state marginal income tax rate and whose denominator is equal to one minus the combined highest statutory Federal and state marginal income tax rate. Without limiting the generality of the foregoing, any other amounts expended or to be paid with respect to decommissioning of the Unit or removal of the Unit from service shall constitute part of the Decommissioning Expenses if they are, or when paid will be, either (i) properly chargeable to any account related to decommissioning of a nuclear generating unit in accordance with the Uniform System or generally accepted accounting principles as then in effect, or (ii) properly chargeable to decommissioning of a nuclear generating unit in accordance with then applicable regulations of the NRC or the FERC or any other regulatory agency having jurisdiction. 8. Billing. Connecticut Yankee will bill the Purchaser, as soon as practicable after the end of each month, for all amounts payable by the Purchaser with respect to-the-particular month pursuant to Section 7 hereof. Such bills will be rendered in such detail as the Purchaser may reasonably request and may be rendered on an estimated basis subject to corrective adjustments in subsequent billing periods. All bills shall be due and payable when rendered and any amount remaining unpaid 15 days following the date of receipt of bills shall bear interest at an annual rate equal to 2% in excess of the current prime rate then in effect at The Connecticut Bank and Trust Company, National Association, from the due date to the date payment is received by Connecticut Yankee. 9. Decommissioning Fund. Connecticut Yankee agrees to cause an appropriate decommissioning reserve to be maintained in accordance with applicable regulatory requirements. Connecticut Yankee has established an independent trust or other separate fund (the "Connecticut Yankee Trust") which has the necessary powers to hold and invest all funds collected for the decommissioning of the Unit and to disburse the same to reimburse Connecticut Yankee for such costs when actually incurred for decommissioning of the Unit or removal of the Unit from service. If during the term of the Connecticut Yankee Trust applicable legislation or regulations are promulgated which so permit or require, or an alternative entity is created for funding decommissioning of the Unit, the Connecticut Yankee Trust has the authority, with the concurrence of Connecticut Yankee, to transfer its trust estate to such newly authorized entity for the purpose of providing for the decommissioning of the Unit or removal of the Unit from service. Connecticut Yankee agrees to pay to, or cause to be paid to, the Connecticut Yankee Trust or any successor trust approved by the board of directors of Connecticut Yankee all funds collected hereunder for the express purpose of decommissioning the Unit or removing the Unit from service and further agrees that, after the tax consequences of decommissioning collections have been resolved, any funds collected hereunder to meet Decommissioning Tax Liability which are not used for that purpose will be refunded to the Purchaser. 10. Cancellation of Contract. If deliveries cannot be made to the Purchaser because either (i) the Unit is damaged to the extent of being completely or substantially completely destroyed, or (ii) the Unit is taken by exercise of the right of eminent domain or a similar right or power, or (iii) (a) the Unit cannot be used because of contamination, or because a necessary license or other necessary public authorization cannot be obtained or is revoked or because the utilization of such a license or authorization is made subject to specified conditions which are not met, and (b) the situation cannot be rectified to an extent which will permit Connecticut Yankee to make deliveries to the Purchaser from the Unit; then and in any such case, the Purchaser may cancel the provisions of this contract, except that in all cases other than those described in clause (ii) above, the provisions relating to the payment of Total Decommissioning Costs shall, whether or not the Unit is operated or operable and notwithstanding any earlier termination of the service life of the Unit, remain in full force and effect until the expiration of the term hereof, it being recognized that such costs represent deferred payments in connection with power theretofore delivered by Connecticut Yankee hereunder. Such cancellation shall be effected by written notice given by the Purchaser to Connecticut Yankee. In the event of such cancellation, all continuing obligations of the parties hereunder as to subsequently incurred costs of Connecticut Yankee other than the obligations relating to the payment and application of Total Decommissioning Costs excluded from such cancellation by the second preceding sentence, but including the Purchaser's obligations to continue payments pursuant to clauses (b) and (c) of the first paragraph of Section 7 hereof, shall cease forthwith. Notwithstanding the foregoing, the applicable provisions of this contract shall continue in effect after the cancellation hereof to the extent necessary to permit final billings and adjustments hereunder with respect to obligations incurred through the date of cancellation and the collection thereof. Any dispute as to the Purchaser's right to cancel this contract pursuant to the foregoing provisions shall be referred to arbitration in accordance with the provisions of Section 13. Notwithstanding anything in this contract elsewhere contained, the Purchaser may cancel this contract or be relieved of its obligations to make payments hereunder only as provided in the next preceding paragraph of this Section 10. Further, if for reasons beyond Connecticut Yankee's reasonable control, deliveries are not made as contemplated by this contract, Connecticut Yankee shall have no liability to the Purchaser on account of such non-delivery. 11. Insurance. Connecticut Yankee presently has in effect, and hereafter will at all times maintain until the expiration of the term hereof, insurance to cover its "public liability" for personal injury and property damage resulting from a "nuclear incident" (as those terms are defined in the Act), with limits not less than Connecticut Yankee may be required to maintain to qualify for governmental indemnity under the Act and shall maintain an indemnification agreement with the NRC as provided by the Act. Connecticut Yankee will also at all time maintain such other types of liability insurance, including workmen's compensation insurance, in such amounts, as is customary in the case of other similar electric utility companies, or as may be required by law. Connecticut Yankee will at all times keep insured such portions of the Unit as are of a character usually insured by electric utility companies similarly situated and operating like properties, against the risk of a "nuclear incident" and such other risks as electric utility companies, similarly situated and operating like properties, usually insure against; and such insurance shall to the extent available be carried in amounts sufficient to prevent Connecticut Yankee from becoming a co-insurer. Such insurance shall to the extent available be carried in an amount at least equal to the original cost of the insured facilities, less accrued depreciation thereon. 12. Audit. Connecticut Yankee's books and records (including metering records) shall be open to reasonable inspection and audit by the Purchaser. 13. Arbitration. In case any dispute shall arise as to the interpretation or performance of this contract which cannot be settled by mutual agreement, such dispute shall be submitted to arbitration. The parties shall if possible agree upon a single arbitrator. In case of failure to agree upon an arbitrator within 15 days after the delivery by either party to the other of a written notice requesting arbitration, either party may request the American Arbitration Association to appoint the arbitrator. The arbitrator, after opportunity for each of the parties to be heard, shall consider and decide the dispute and notify the parties in writing of his decision. Such decision shall be binding upon the parties, and the expenses of the arbitration shall be borne equally by them. 14. Regulation. This contract, and all rights, obligations and performance of the parties hereunder, are subject to all applicable state and Federal law and to all duly promulgated orders and other duly authorized action of governmental authorities having jurisdiction. 15. Assignment. This contract shall be binding upon and shall inure to the benefit of, and may be performed by, the successors and assigns of the parties, except that no assignment, pledge or other transfer of this contract by either party shall operate to the assignor, pledgor or transferor from any of its obligations under this contract unless consent to the given in writing by the other party, or, if the other party has theretofore assigned, pledged or otherwise transferred its interest in this contract by the other party's assignee, pledgee or transferee, or unless such transfer is incident to a merger or consolidation with, or transfer of all or substantially all of the assets of the transferor to, another Purchaser which shall, as a part of such succession, assume all the obligations of the transferor under this contract. 16. Right of Setoff. The Purchaser shall not be entitled to set off against the payments required to be made by it under this contract (i) any amounts owed to it by Connecticut Yankee or (ii) the amount of any claim by it against Connecticut Yankee. However, the foregoing shall not affect in any other way the Purchaser's right and remedies with respect to any such amounts owed to it by Connecticut Yankee or any such claim by it against Connecticut Yankee. 17. Amendments. Upon authorization by Connecticut Yankee's board of directors of uniform amendments to all the Additional Power Contracts, Connecticut Yankee shall have the right to amend the provisions of Section 7 hereof by serving an appropriate statement of such amendment upon the Purchaser and filing the same with the FERC (or such other regulatory agency as may have jurisdiction in the premises) in accordance with the provisions of applicable laws and any rules and regulations thereunder, and the amendment shall thereupon become effective on the date specified therein, subject to any suspension order issued by such agency. All other amendments to this contract shall be by mutual agreement, evidenced by a written amendment signed by the parties hereto. 18. Interpretation. The interpretation and performance of this contract shall be in accordance with and controlled by the law of the State of Connecticut. 19. Addresses. Except as the parties may otherwise agree, any notice, request, bill or other communication from one party to the other, relating to this contract, or the rights, obligations or performance of the parties hereunder, shall be in writing and shall be effective upon delivery to the other party. Any such communication shall be considered as duly delivered when delivered in person or mailed by registered or certified mail, postage prepaid, to the respective post office address of the other party shown following the signatures of such other party hereto, or such other address as may be designated by written notice given as provided in this Section 19. 20. Corporate Obligations. This contract is the corporate act and obligation of the parties hereto, and any claim hereunder against any stockholder, director or officer of either party, as such, is expressly waived. 21. All Prior Agreements Superseded. This contract represents the entire agreement between the parties relating to the subject matter hereof during the operative term hereof (i.e., post- December 31, 1997), and all previous agreements, discussions, communications and correspondence with respect to the subject matter are hereby superseded and are of no further force and effect. 22. Counterparts. This contract may be executed in any number of counterparts and each executed counterpart shall have the same force and effect as an original instrument and as if all the parties to all of the counterparts had signed the same instrument. Any signature page of this contract may be detached from any counterpart without impairing the legal effect of any signatures thereon, and may be attached to another counterpart of this contract identical in form hereto but having attached to it one or more signature pages. IN WITNESS WHEREOF, the parties have executed this contract by their respective officers thereunto duly authorized as of the date first above written. CONNECTICUT YANKEE ATOMIC POWER COMPANY By /s/ Bernard M. Fox Its Senior Vice President P.O. Box 270 Hartford, Connecticut 06141 THE CONNECTICUT LIGHT AND POWER COMPANY By /s/ E. James Ferland (Officer and Title) E. JAMES FERLAND, PRESIDENT & CHIEF OPERATING OFFICER (Address) EX-10.3 9 CAPITAL FUNDS AGREEMENT, dated as of September 1, 1964, between CONNECTICUT YANKEE ATOMIC POWER COMPANY ("Connecticut Yankee"), a Connecticut corporation, and THE CONNECTICUT LIGHT AND POWER COMPANY (the "Stockholder"), a Connecticut corporation. It is agreed as follows: 1. Basic Understandings Connecticut Yankee has been organized to provide for the supply of power to the eleven utility companies (including the Stockholder) which are its stockholders. It has commenced the construction of a nuclear electric generating unit of the pressurized water type, which is being designed to have an initial gross capability of approximately 490 megawatts electric, at a site adjacent to the Connecticut River at Haddam Neck, Connecticut (the unit being herein, together with the site and all related facilities, referred to as the "Unit"). Construction of the Unit is being carried out under contracts with Westinghouse Electric Corporation and Stone & Webster Engineering Corporation. The respective percentages of the capacity and output of the Unit to be purchased by the Stockholder and the other Connecticut Yankee stockholders are the same as the respective percentages of Connecticut Yankee's stock now owned by them. The names of the stockholders and their respective stock percentages ("stock percentages") are as follows: Stockholder Stock Percentage The Connecticut Light and Power Company 25.0% New England Power Company 15.0% Boston Edison Company 9.5% The Hartford Electric Light Company 9.5% The United Illuminating Company 9.5% Western Massachusetts Electric Company 9.5% Central Maine Power Company 6.0% Public Service Company of New Hampshire 5.0% Cambridge Electric Light Company 4.5% Montaup Electric Company 4.5% Central Vermont Public Service Corporation 2.0% Connecticut Yankee and each of its other stockholders are entering into capital funds agreements which are identical to this agreement except for necessary changes in the names of the parties. Connecticut Yankee's capitalization as of the date of this agreement is $7,500,000 consisting of 75,000 shares of common stock, $100 par value, which have been purchased at the par value thereof by its stockholders. Connecticut Yankee's stockholders have entered into subscription agreements with it covering their purchase of their respective stock percentages of an additional 75,000 shares of its common stock, $100 par value, at the par value thereof. Connecticut Yankee's estimated capital requirements with respect to the Unit aggregate $98,500,000 and Connecticut Yankee proposes to finance the balance of these requirements through the issuance and sale of first mortgage bonds or other securities, and through the issuance and sale of common stock to its stockholders. 2. Effective Date This agreement shall become effective upon receipt by the Stockholder of notice that Connecticut Yankee has entered into capital funds agreements, as contemplated by Section 1 above, with each of its other stockholders, and the execution of capital funds agreements by the other stockholders shall constitute consideration for the obligations of the Stockholder hereunder. 3. Construction of the Unit Connecticut Yankee will proceed with due diligence with construction of the Unit, and will exercise its best efforts to complete and place it in commercial operation by October 1, 1967, on the presently estimated schedule therefor and within present cost estimates, and will keep the Stockholder currently informed as to the progress of construction and expected plant completion date. 4. Stock Purchases to Provide the Capital Requirements of the Unit From time to time when Connecticut Yankee requires capital to meet the capital requirements of the Unit, it may offer shares of its common stock to its stockholders for subscription to raise such capital. Subject to the conditions in Section 7, when Connecticut Yankee offers any such shares for such purpose, the Stockholder will subscribe for and purchase for cash at the par value thereof its stock percentage of the shares so offered. However, the aggregate amount required to be paid by the Stockholder pursuant to this Section (including for this purpose the amount paid by the Stockholder on account of its purchase of the shares of Connecticut Yankee common stock which are outstanding on the date of this agreement, as referred to in Section 1, and any additional amount paid by it after said date on account of the purchase of additional shares of said stock pursuant to its outstanding subscription agreement referred to in Section 1 or any further subscription agreements entered into by the Stockholder with Connecticut Yankee prior to the time at which the conditions specified in the second paragraph of Section 7 are satisfied) shall not exceed the sum of (a) its stock percentage of $70,000,000, and (b) amounts paid to it by Connecticut Yankee as return of capital. 5. Capital Requirements of the Unit Defined Connecticut Yankee shall be deemed to have capital requirements of the Unit within the meaning of Section 4 if it requires additional capital for any of the following purposes: (i) to complete construction of the Unit and place it in commercial operation at a gross capability of at least 490 megawatts electric; (ii) to make additions and replacements (other than those chargeable to maintenance) to the Unit which are required to insure the continued regular operation of the Unit at a gross capability of at least 490 megawatts electric or to restore it to regular operation at such gross capability; (iii) to make any changes in or additions to the Unit which must be effected in order to obtain or maintain, or to meet the conditions of, any license or other public authorization which is required for the regular operation of the Unit at a gross capability of at least 490 megawatts electric; (iv) to provide materials and supplies, or funds for prepaid items or cash working capital, required for the regular operation of the Unit at a gross capability of at least 490 megawatts electric, or to finance the costs of acquiring and maintaining an inventory of nuclear cores owned by Connecticut Yankee. If the Company shall at any time or times determine that it would be more feasible, economic or otherwise desirable for regular operation for the generation of power and energy for delivery under its Power Contracts with its Stockholders for the Unit to operate at a lower gross capability than 490 megawatts or with heat supplied in whole or part other than by a nuclear reactor, and if it holds or can obtain all licenses and other public authorizations required for the regular operation of the Unit at such lower level or with such other heating system, then the "capital requirements of the Unit" shall include any additional capital required for any of the foregoing purposes for operation of the Unit at any such lower level of capability or with such other heating system as from time to time determined. 6. Loans and Advances In lieu of offering additional shares of its common stock for subscription and purchase under Section 4, Connecticut Yankee may, at its option, request its stockholders to provide required capital by means of loans or advances. In any case where Connecticut Yankee requests such loans or advances, in lieu of stock purchases, the Stockholder, subject to the conditions in Section 7, will provide its stock percentage thereof. However, Connecticut Yankee shall not be entitled to request such loans or advances except in circumstances where it would be entitled to require the Stockholder to make a stock subscription pursuant to Section 4. Further, the aggregate amount of capital which the Stockholder is required to provide under Sections 4 and 6 of this agreement shall be the same whether the capital is provided in whole through stock subscriptions and purchases or loans or advances, or is provided instead through a combination of them. However, in determining whether the aggregate of (x) the amounts paid or to be paid by the Stockholder for shares of common stock purchased or to be purchased under Section 4 and (y) the amounts of any loans or advances provided or to be provided in lieu of such stock purchases, equals or exceeds the limit specified in Section 4, the aggregate principal amount of all such loans or advances previously made shall be excluded to the extent repaid. The terms of any loans and advances requested by Connecticut Yankee under this Section 6, as to interest, maturity date, rights and terms of prepayment, and otherwise shall be the same for all stockholders. Such terms shall be as determined by Connecticut Yankee in its discretion, except that the terms of each such loan or advance shall provide for quarterly payments of interest at an annual rate not less than 1-1/2% in excess of the prime rate for commercial loans at the time in effect at The Connecticut Bank and Trust Company and for a maturity date not later than October 1, 1994. 7. Conditions to the Stockholders's Obligations The obligation of the Stockholder to subscribe for and purchase its stock percentage of any stock issue under Section 4, or to provide its stock percentage of any loan or advance under Section 6, shall be subject to the condition that all necessary regulatory approvals shall have been obtained with respect to both the action to be taken by Connecticut Yankee and the action to be taken by the Stockholder. The parties will use their best efforts to obtain, or to assist in obtaining, the foregoing regulatory approvals. The obligation of the Stockholder to subscribe for and purchase its stock percentage of any stock issue under Section 4, or to provide its stock percentage of any loan or advance under Section 6, shall be subject to the further condition that Connecticut Yankee shall first (i) have sold at least $40,000,000 aggregate principal amount of its first mortgage bonds at a price not lower than the aggregate principal amount thereof, and (ii) have entered into an agreement with one or more banks providing for the loan from such bank(s) to Connecticut Yankee of up to $25,000,000 on terms and conditions approved by Connecticut Yankee's Board of Directors. Except as expressly provided in this Section 7, notwithstanding anything in this agreement elsewhere contained, no action of, nor failure to act by, Connecticut Yankee or any of the several stockholders referred to in Section 1 hereof shall permit cancellation of, or relieve the Stockholder from any of its obligations under, this agreement. However, the failure of any of Connecticut Yankee's other stockholders to purchase its stock percentage of any Connecticut Yankee stock issue, or to make its stock percentage of any loan or advance requested by Connecticut Yankee, shall under no circumstances require an increase in the amount of stock to be purchased, or the amount of loans and advances to be made, by the Stockholder. 8. Financing by Other Means Nothing in this agreement shall be construed as precluding Connecticut Yankee from offering shares of its common stock to, or requesting loans and advances from, its stockholders to finance capital requirements other than those contemplated by Section 5, or from financing, in its discretion, its capital requirements (including the capital requirements contemplated by Section 5) by means other than the sale of its common stock to its stockholders, or loans or advances from them. 9. Cooperation By Stockholder The Stockholder agrees that it will cooperate with Connecticut Yankee in taking all such action as may be necessary or appropriate to effectuate the purposes of this agreement. 10. Restrictions on Transfer The Stockholder acknowledges notice of the restrictions on stock transfers contained in Article VIII, Section 2 of Connecticut Yankee's by-laws, and agrees to be bound by said provisions with respect to all shares of Connecticut Yankee's capital stock which it now owns or may hereafter acquire. 11. Interpretation The interpretation and performance of this agreement shall be in accordance with and controlled by the law of the State of Connecticut. 12. Addresses Except as the parties may otherwise agree, any notice, request or other communication from one party to the other, relating to this agreement or the rights, obligations or performance of the parties hereunder, shall be in writing and shall be effective upon delivery to the other party. Any such communication shall be considered as duly delivered when mailed to the respective post office address of the other party shown following the signatures of such other party hereto, or such other post office address as may be designated by written notice given as provided in this Section 12. 13. Assignment This agreement shall be binding upon and shall inure to the benefit of, and may be performed by, the successors and assigns of the parties, except that no assignment, pledge or other transfer of this agreement by either party shall operate to release the assignor, pledgor or transferor of any of its obligations under this agreement unless consent to the release is given in writing by the other party, or, if the other party has theretofore assigned, pledged or otherwise transferred its interest in this agreement, by the other party's assignee, pledgee or transferee. 14. Corporate Obligations This agreement is the corporate act and obligation of the parties hereto, and any claim hereunder against any stockholder, director or officer of either party, as such, is expressly waived. 15. All Prior Agreements Superseded This agreement represents the entire agreement between us relating to the subject matter hereof, and all previous agreements (including our prior Capital Funds Agreement dated as of July 1, 1964), discussions, communications and correspondence with respect to the subject matter are hereby superseded and are of no further force and effect, except that the outstanding subscription agreement, as referred to in Section 1, between the Stockholder and Connecticut Yankee with respect to the Stockholder's subscription for its stock percentage of an additional 75,000 shares of Connecticut Yankee's common stock, $100 par value, is not superseded and shall remain in full force and effect. IN WITNESS WHEREOF, the parties have executed this agreement by their respective officers thereunto duly authorized as of the date first above written. Attest: CONNECTICUT YANKEE ATOMIC POWER COMPANY /s/ R. F. Probst By /s/ S. R. Knapp Secretary Its President P.O. Box 2010 Hartford, Connecticut 06101 Attest: THE CONNECTICUT LIGHT AND POWER COMPANY /s/ C. J. Ramage By /s/ P. V. Hayden Asst. Secretary Its President EX-10.7.3 10 MAINE YANKEE ATOMIC POWER COMPANY Amendment No. 3 to Power Contract AMENDMENT, dated as of this first day of October, 1984, between MAINE YANKEE ATOMIC POWER COMPANY ("Maine Yankee"), a Maine Corporation, and THE CONNECTICUT LIGHT AND POWER COMPANY a corporation (the "Purchaser"), to the Power Contract dated as of May 20, 1968 between Maine Yankee and the Purchaser (the "Power Contract"). W I T N E S S E T H WHEREAS, pursuant to the Power Contract, Maine Yankee supplies to the Purchaser and, pursuant to separate Power Contracts, to the other Sponsors of Maine Yankee, each of whom is contemporaneously entering into Amendments which are identical to the Amendment except for the necessary changes in the names of the parties, all of the capacity and the electric energy available from the nuclear generating unit owned by Maine Yankee at a site on the tidewater in the Town of Wiscasset, Maine, (such unit being herein together with the site and all related facilities owned by Maine Yankee, referred to as the "Unit"). WHEREAS, the Federal Energy Regulatory Commission ("FERC") in a final Order (the "Order") issued August 14, 1984 in Docket No. ER84-344 has directed Maine Yankee to amend the Power Contract to conform with the FERC's regulations regarding the treatment of construction work in progress ("CWIP") and nuclear fuel in process ("NFIP") in rate base. WHEREAS, in the Order the FERC also directed Maine Yankee to amend the Power Contract to conform with the FERC's regulations regarding the treatment of accumulated deferred income taxes in rate base. NOW, THEREFORE, in consideration of the premises and to other good and valuable consideration, receipt of which is hereby acknowledged, the parties hereto agree that the Power Contract is hereby amended as follows: 1. Terms used herein and not defined shall have meanings set forth in the Power Contract. 2. Section 7 of the Power Contract is amended by adding the following paragraph to the end thereof: Notwithstanding any other provision of this contract, the treatment of (1) construction work in progress ("CWIP"), (2) nuclear fuel in process ("NFIP"), and (3) accumulated deferred income taxes ("ADIT") for purposes of any calculations relevant to the computation of monthly payments under this Section 7 shall conform to the Federal Energy Regulatory Commission's regulations respecting such items, as such regulations may be modified from time to time. This Agreement shall become effective on October 1, 1984, or upon such later date as it shall be permitted to become effective by the Federal Energy Regulatory Commission or other governmental regulatory authority having jurisdiction. This Agreement may be executed in any number of counterparts and each executed counterpart shall have the same force and effect as an original instrument and as if all the parties to all of the counterparts had signed the same instrument. Any signature page of this Agreement may be detached from any counterpart without impairing the legal effect of any signatures thereon, and may be detached from any counterpart without impairing the legal effect of any signatures thereon, and may be attached to another counterpart of this contract identical in form hereto by having attached to it one or more signature pages. IN WITNESS WHEREOF, the parties have executed this Agreement by their respective officers hereto duly authorized, as of the date first above written. MAINE YANKEE ATOMIC POWER COMPANY By -------------------------- Its President -------------------------- Title Address: Edison Drive Agusta, Maine 04336 THE CONNECTICUT LIGHT & POWER COMPANY ------------------------------------- (PURCHASER) By /s/E. JAMES FERLAND ----------------------- E. JAMES FERLAND Its PRESIDENT & CHIEF OPERATING --------------------------- OFFICER ------- Title EX-10.8.1 11 This Amendment No. 1, dated as of August 1, 1985, between MAINE YANKEE ATOMIC POWER COMPANY ("Maine Yankee"), a Maine corporation, and THE CONNECTICUT LIGHT AND POWER COMPANY (the "Sponsor"), amending the Capital Funds Agreement, dated as of May 20, 1968, between said parties. WHEREAS, Maine Yankee and the Sponsor are parties to the Capital Funds Agreement which was executed concurrently with a Power Contract between the same parties providing for the sale of power by Maine Yankee to the Sponsor for a term of 30 years which ends on January 1, 2003 and Maine Yankee has comparable agreements with its other sponsors; and WHEREAS, Maine Yankee and the Sponsor have entered into an Additional Power Contract, dated as of February 1, 1984, which continues the provisions of said Power Contract until the expiration of Maine Yankee's operating license and completion of decommissioning of Maine Yankee's plant and Maine Yankee has comparable agreements with its other sponsors; and WHEREAS, Maine Yankee is concurrently entering into an amendment similar to this with each of its other sponsors. NOW, THEREFORE, it is agreed that 1. Section 2 of the Capital Funds Agreement is hereby amended by deleting the date "December 31, 2003" and inserting in lieu thereof the date "October 21, 2008". 2. Section 5 of the Capital Funds Agreement is hereby amended by changing the period at the end of the first sentence thereof to a semicolon and inserting the following clause: "(vi) to provide moneys for funding the Maine Yankee Spent Fuel Disposal Trust established pursuant to Chapter 508 of the Public Laws of 1985 of Maine." 3. This Amendment No. 1 shall become effective upon receipt by the Sponsor of notice that Maine Yankee has entered into a substantially identical agreement with each of the other sponsors with respect to their respective Capital Funds Agreements. IN WITNESS WHEREOF, the parties have executed this amendment by their respective officers thereunto duly authorized as of the date first above written. MAINE YANKEE ATOMIC POWER COMPANY By ------------------------------ EX-10.10.3 12 Amendment No. 3 to Power Contract AMENDMENT, dated as of this 24th day of April, 1985, between VERMONT YANKEE NUCLEAR CORPORATION ("Vermont Yankee"), a Vermont corporation, and THE CONNECTICUT LIGHT AND POWER COMPANY, a Connecticut corporation (the "Purchaser"), for itself and as successor to The Hartford Electric Light Company ("HELC"), to the Power Contracts dated February 1, 1968, as heretofore amended on June 1, 1972 and April 15, 1983, one between Vermont Yankee and HELC (collectively the "Power Contract"), as previously amended. WITNESSETH WHEREAS, pursuant to the Power Contract, Vermont Yankee supplies to the Purchaser and, pursuant to separate power contracts substantially identical to the Power Contract except for the names of the parties, to the other Sponsors of Vermont Yankee, each of whom is contemporaneously entering into an amendment to its power contract which is identical hereto except for the necessary changes in the names of the parties, all of the capacity and the electric energy available from the nuclear generating unit owned by Vermont Yankee at a site adjacent to the Connecticut River at Vernon, Vermont (such unit being herein together with the site and all related facilities owned by Vermont Yankee, referred to as the "Unit"). WHEREAS, Vermont Yankee, the Purchaser and the other Sponsors of Vermont Yankee believe that the monthly payments provided in the Power Contracts are no longer sufficient to provide a return on the equity investment in the Unit which is equal to the return achieved on investments of comparable risk. WHEREAS, in order to assure the maintenance of an appropriate level of return on common equity, Vermont Yankee and the Purchaser have agreed to enter into this Agreement. NOW, THEREFORE, in consideration of the above and of other good and valuable consideration, receipt of which is hereby acknowledged, the parties hereto agree that the Power Contract is hereby amended as follows: 1. Terms used herein and not defined shall have the meanings set forth in the Power Contract. 2. The fourth paragraph of Section 7 of the Power Contract is amended to read as follows: "Equity percentage" as of any date shall be eight and one-half percent (8 1/2%) or such greater percentage, if any, as shall be obtained by dividing (a) the sum of (i) fifteen and one-half percent (15.5%) multiplied by common stock equity investment as of such date plus (ii) the stated dividend rate per annum of each issue of preferred stock bearing a particular dividend rate outstanding on such date multiplied by the aggregate par value of said issue, by (b) equity investment as of such date. This Agreement shall become effective on May 14, 1985, or upon such later date as it shall be permitted to become effective by the Federal Energy Regulatory Commission or other governmental regulatory authority having jurisdiction. The 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 both parties to all of the counterparts had signed the same instrument. Any signature page of the Agreement may be detached from any counterpart without impairing the legal effect of any signatures thereon, and may be attached to another counterpart of this contract identical in form hereto but having to it one more signature pages. IN WITNESS WHEREOF, the parties have executed this Agreement by their respective officers hereto duly authorized, as of the date first above written. VERMONT YANKEE NUCLEAR POWER CORPORATION By /s/John T. Pearson ------------------------- Its Treasurer ------------------------- Title Address: THE CONNECTICUT LIGHT AND POWER COMPANY By /s/E. James Ferland ------------------------------ E. JAMES FERLAND Its PRESIDENT AND CHIEF OPERATING OFFICER Title Address: 107 SELDEN STREET BERLIN, CT 06307 Amendment No. 3 to Power Contract AMENDMENT, dated as of this 24th day of April, 1985, between VERMONT YANKEE NUCLEAR CORPORATION ("Vermont Yankee"), a Vermont corporation, and PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE, a New Hampshire corporation (the "Purchaser"), for itself and as successor to The Hartford Electric Light Company ("HELC"), to the Power Contracts dated February 1, 1968, as heretofore amended on June 1, 1972 and April 15, 1983, one between Vermont Yankee and HELC (collectively the "Power Contract"), as previously amended. WITNESSETH WHEREAS, pursuant to the Power Contract, Vermont Yankee supplies to the Purchaser and, pursuant to separate power contracts substantially identical to the Power Contract except for the names of the parties, to the other Sponsors of Vermont Yankee, each of whom is contemporaneously entering into an amendment to its power contract which is identical hereto except for the necessary changes in the names of the parties, all of the capacity and the electric energy available from the nuclear generating unit owned by Vermont Yankee at a site adjacent to the Connecticut River at Vernon, Vermont (such unit being herein together with the site and all related facilities owned by Vermont Yankee, referred to as the "Unit"). WHEREAS, Vermont Yankee, the Purchaser and the other Sponsors of Vermont Yankee believe that the monthly payments provided in the Power Contracts are no longer sufficient to provide a return on the equity investment in the Unit which is equal to the return achieved on investments of comparable risk. WHEREAS, in order to assure the maintenance of an appropriate level of return on common equity, Vermont Yankee and the Purchaser have agreed to enter into this Agreement. NOW, THEREFORE, in consideration of the above and of other good and valuable consideration, receipt of which is hereby acknowledged, the parties hereto agree that the Power Contract is hereby amended as follows: 1. Terms used herein and not defined shall have the meanings set forth in the Power Contract. 2. The fourth paragraph of Section 7 of the Power Contract is amended to read as follows: "Equity percentage" as of any date shall be eight and one-half percent (8 1/2%) or such greater percentage, if any, as shall be obtained by dividing (a) the sum of (i) fifteen and one-half percent (15.5%) multiplied by common stock equity investment as of such date plus (ii) the stated dividend rate per annum of each issue of preferred stock bearing a particular dividend rate outstanding on such date multiplied by the aggregate par value of said issue, by (b) equity investment as of such date. This Agreement shall become effective on May 14, 1985, or upon such later date as it shall be permitted to become effective by the Federal Energy Regulatory Commission or other governmental regulatory authority having jurisdiction. The 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 both parties to all of the counterparts had signed the same instrument. Any signature page of the Agreement may be detached from any counterpart without impairing the legal effect of any signatures thereon, and may be attached to another counterpart of this contract identical in form hereto but having to it one more signature pages. IN WITNESS WHEREOF, the parties have executed this Agreement by their respective officers hereto duly authorized, as of the date first above written. VERMONT YANKEE NUCLEAR POWER CORPORATION By /s/John T. Pearson ------------------------------- Its Treasurer ------------------------------- Title Address: PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE By /s/R. J. Hanson -------------------------------- Its PRESIDENT AND CHIEF EXECUTIVE OFFICER Title Amendment No. 3 to Power Contract AMENDMENT, dated as of this 24th day of April, 1985, between VERMONT YANKEE NUCLEAR CORPORATION ("Vermont Yankee"), a Vermont corporation, and WESTERN MASSACHUSETTS ELECTRIC COMPANY, a Massachusetts corporation (the "Purchaser"), for itself and as successor to The Hartford Electric Light Company ("HELC"), to the Power Contracts dated February 1, 1968, as heretofore amended on June 1, 1972 and April 15, 1983, one between Vermont Yankee and HELC (collectively the "Power Contract"), as previously amended. WITNESSETH WHEREAS, pursuant to the Power Contract, Vermont Yankee supplies to the Purchaser and, pursuant to separate power contracts substantially identical to the Power Contract except for the names of the parties, to the other Sponsors of Vermont Yankee, each of whom is contemporaneously entering into an amendment to its power contract which is identical hereto except for the necessary changes in the names of the parties, all of the capacity and the electric energy available from the nuclear generating unit owned by Vermont Yankee at a site adjacent to the Connecticut River at Vernon, Vermont (such unit being herein together with the site and all related facilities owned by Vermont Yankee, referred to as the "Unit"). WHEREAS, Vermont Yankee, the Purchaser and the other Sponsors of Vermont Yankee believe that the monthly payments provided in the Power Contracts are no longer sufficient to provide a return on the equity investment in the Unit which is equal to the return achieved on investments of comparable risk. WHEREAS, in order to assure the maintenance of an appropriate level of return on common equity, Vermont Yankee and the Purchaser have agreed to enter into this Agreement. NOW, THEREFORE, in consideration of the above and of other good and valuable consideration, receipt of which is hereby acknowledged, the parties hereto agree that the Power Contract is hereby amended as follows: 1. Terms used herein and not defined shall have the meanings set forth in the Power Contract. 2. The fourth paragraph of Section 7 of the Power Contract is amended to read as follows: "Equity percentage" as of any date shall be eight and one-half percent (8 1/2%) or such greater percentage, if any, as shall be obtained by dividing (a) the sum of (i) fifteen and one-half percent (15.5%) multiplied by common stock equity investment as of such date plus (ii) the stated dividend rate per annum of each issue of preferred stock bearing a particular dividend rate outstanding on such date multiplied by the aggregate par value of said issue, by (b) equity investment as of such date. This Agreement shall become effective on May 14, 1985, or upon such later date as it shall be permitted to become effective by the Federal Energy Regulatory Commission or other governmental regulatory authority having jurisdiction. The 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 both parties to all of the counterparts had signed the same instrument. Any signature page of the Agreement may be detached from any counterpart without impairing the legal effect of any signatures thereon, and may be attached to another counterpart of this contract identical in form hereto but having to it one more signature pages. IN WITNESS WHEREOF, the parties have executed this Agreement by their respective officers hereto duly authorized, as of the date first above written. VERMONT YANKEE NUCLEAR POWER CORPORATION By /s/John T. Pearson ---------------------------- Its Treasurer ----------------------------- Title Address: WESTERN MASSACHUSETTS ELECTRIC COMPANY By /s/E. James Ferland ---------------------------------- E. JAMES FERLAND Its PRESIDENT AND CHIEF OPERATING EX-10.12 13 AMENDED AND RESTATED MILLSTONE PLANT AGREEMENT This Amended and Restated Millstone Plant Agreement (the "Agreement") is dated as of December 1, 1984, and is by and among Northeast Nuclear Energy Company ("NNECO"), The Connecticut Light and Power Company ("CL&P"), and Western Massachusetts Electric Company ("WMECO"). BACKGROUND CL&P, WMECO and NNECO are parties to an Amended and Restated Millstone Plant Agreement dated as of December 1, 1982 (the "Millstone Plant Agreement"), which is a comprehensive restatement and amendment of a prior agreement dated as of June 30, 1966, as supplemented by a Supplemental Agreement dated as of December 1, 1967 and as amended by an amendment dated as of December 1, 1972. Under the Millstone Plant Agreement, NNECO agreed to act as CL&P's and WMECO's agent for the following purposes: (1) Operating and maintaining Millstone 1 and 2 ("Unit 1" and "Unit 2," respectively), which are two nuclear electric generating units located at a site of approximately 500 acres (the "Millstone Site") at Millstone Point in the Town of Waterford, Connecticut, in which units CL&P and WMECO have 81 percent and 19 percent, respectively, joint ownership interests as tenants in common, and (2) Designing, constructing, operating, and maintaining a third nuclear generating unit ("Unit 3") located at the Millstone Site, as agent for CL&P and WMECO in their capacities as Lead Participants for Unit 3 pursuant to a Sharing Agreement dated as of September 1, 1973, as amended on August 1, 1974 and December 15, 1975 (as the same may be further amended or modified from time to time, and in effect, the "Sharing Agreement"), by and among CL&P and WMECO and the Associate Participants (as defined in the Sharing Agreement) named therein. When the Millstone Plant Agreement was amended and restated in 1982, it was contemplated that NNECO would arrange under separate agreements to construct and finance a building (the "Simulator Building") at the Millstone Site in which would be located a separate control room simulator for each of Unit 1 (the "Unit 1 Simulator"), Unit 2 (the "Unit 2 Simulator"), Unit 3 (the "Unit 3 Simulator") (collectively the "Millstone Simulators") and a nuclear electric generating unit (the "Haddam Neck Unit") owned and operated by Connecticut Yankee Atomic Power Company ("CYAPC") in the Town of Haddam, Connecticut (the "CY Simulator") (each a "Simulator" and all four collectively the "Simulators"). It was also contemplated at that time that the Niantic Bay Fuel Trust would assume all of NNECO's prior responsibilities for procuring, supplying and financing nuclear fuel on behalf of CL&P and WMECO. Subsequently, it has been determined that it is desirable for NNECO to acquire the Millstone Simulators and the Simulator Building upon their completion and to operate and maintain the Simulator Building for CL&P and WMECO with respect to the Unit 1 and 2 Simulators, for CL&P, WMECO and the Associate Participants with respect to the Unit 3 Simulator, and for CYAPC with respect to the CY Simulator. In furtherance thereof, NNECO and CYAPC have entered into an agreement as of the date hereof (the "CYAPC Agreement") setting forth the rights and responsibilities of NNECO and CYAPC with respect to the CY Simulator and the Simulator Building. It has also been recognized that there are many opportunities for NNECO to apply its nuclear engineering, construction and operations expertise for the benefit of the Northeast Utilities System and/or the Associate Participants, and that there may in the future be benefits to the Northeast Utilities system and/or the Associate Participants in having NNECO assume all or part of the functions involved in procuring, financing, owning, leasing (as lessor or lessee) and otherwise performing supply and disposal functions with respect to nuclear fuel, the Simulators, the Simulator Building, and any other assets for any one or more of Units 1, 2 and 3 (collectively the "Millstone Units"). Accordingly, the parties desire to restate further the Millstone Plant Agreement to remove the current restrictions on NNECO's activities with respect to the Simulator Building and the Millstone Simulators, and to provide more generally for NNECO to render such services with respect to the Millstone Units and the nuclear fuel for the Millstone Units as CL&P and/or WMECO may from time to time request. AGREEMENTS Now, therefore, in consideration of the premises and the mutual agreements hereinafter contained, and for other good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged, the parties agree as follows: 1. Description of Millstone Plant and Ownership. CL&P and WMECO own the Millstone Site as tenants in common. Unit 1, a 660 MW boiling water reactor nuclear electric generating unit, and Unit 2, an 870 MW pressurized water reactor nuclear electric generating unit, are both currently licensed for operation at the Millstone Site. Unit 3, a 1,150 MW pressurized water reactor electric generating unit, is under construction at the Millstone Site and is scheduled to begin commercial operations in May, 1986. CL&P owns an 81 percent undivided interest in Units 1 and 2, the portion of the Millstone Site on which Units 1 and 2 are located, and all existing and future improvements thereto, except for a refuel outage building, the Simulator Building and the Simulators, and WMECO owns an 19 percent interest similarly therein. These percentage interests, as the same may change from time to time to reflect the acquisition or disposition of interests in Units 1 and 2, are hereinafter referred to as the "Unit 1 and 2 Ownership Percentages." Pursuant to the Sharing Agreement, CL&P and WMECO collectively own a 64.85 percent undivided interest in Unit 3 (representing approximately 745.8 MW), the portion of the Millstone Site on which Unit 3 is located, and all existing and future improvements thereto. CL&P and WMECO presently own, respectively, 52.6115 percent (605.032 MW) and 12.2385 percent (140.743 MW) undivided interests in Unit 3. These shares, as the same may change from time to time as a result of acquisition or disposition of undivided interests in Unit 3 in compliance with the Sharing Agreement, are hereinafter referred to as the "Unit 3 Ownership Percentages." Certain facilities and structures constructed on or used in connection with the Millstone Site, including but not limited to, an information center, a training building, an emergency operations center, the refuel outage building, and warehouses, serve Units l, 2 and 3. Such facilities and structures (other than the Simulator Building), and all renewals, replacements, additions, retirements and modifications thereto, are hereinafter referred to as the "Millstone Common Facilities." Title to the Millstone Common Facilities (other than the refuel outage building, which is owned by Interet Land Co. and leased to CL&P and WMECO) is held by CL&P and WMECO in accordance with their Unit 1 and 2 Ownership Percentages. For the purposes of this Agreement, Units 1, 2 and 3, the associated transmission substations, the Millstone Common Facilities and other related facilities (other than [i] related transmission lines and rights of way, which are to be separately owned, and [ii] the Simulator Building and the Simulators), are hereinafter referred to as the "Millstone Plant." 2. NNECO's General Responsibility. CL&P and WMECO hereby each severally appoint and authorize NNECO as its respective agent, with the right to employ employees and subagents, and NNECO hereby agrees, as such agent, all subject to and in accordance with the requirements of this Agreement and, in the case of Unit 3, the Sharing Agreement, (i) to act for CL&P and WMECO in all matters with respect to the procurement of materials, nuclear fuel, supplies and services for the Millstone Plant, (ii) to operate and maintain the Millstone Plant, (iii) to manage the Millstone Site, (iv) to act for CL&P and WMECO in all matters with respect to the performance of their obligations as the Lead Participants under the Sharing Agreement, including, but not limited to, their obligations concerning the design, engineering, licensing and construction of Unit 3, (v) to own, operate and maintain the Simulator Building on behalf of CL&P and WMECO, (vi) to enter into leasing and/or financing transactions with respect to, and to operate and maintain, each of the Millstone Simulators on behalf of each of the respective owners thereof, and for the benefit of the respective owners of the Millstone Unit to which each Millstone Simulator relates, and (vii) to provide, at the request of CL&P and/or WMECO, in general or in specific circumstances, such engineering, design, construction, operations, leasing (as lessor or lessee), maintenance, management, financing and other related services with respect to any or all of the Millstone Units and the Millstone Simulators, or portions thereof, as the owner and/or operator thereof may reasonably request and to which NNECO may consent, including, without limiting the generality thereof, the procurement, financing, ownership, leasing (as lessor or lessee), supply and disposal of nuclear fuel for any such Millstone Unit, and the ownership or leasing (as lessor or lessee) of facilities, equipment, materials or supplies. In furtherance of this general authority, and without limiting the generality thereof, CL&P and WMECO severally hereby authorize NNECO, as such agent, (a) to enter into contracts and other arrangements in the name and on behalf of CL&P and WMECO with respect to the operation and maintenance of the Millstone Plant, the procurement of equipment, materials, nuclear fuel, supplies and services for the Millstone Plant, the design, engineering, licensing or construction of Unit 3, and with respect to renewals replacements, additions, retirements and modifications to the Millstone Plant; (b) to enter into contracts and other arrangements in the name or on behalf of CL&P, WMECO and/or any or all of the Associate Participants with respect to the leasing (as lessee or lessor), financing, operation and/or maintenance of the Millstone Simulators, the procurement of equipment, materials, supplies and services for the Millstone Simulators, and with respect to renewals, replacements, additions, retirements and modifications to the Millstone Simulators; (c) if requested by CL&P, WMECO, and/or any or all of the Associate Participants to act for CL&P, WMECO and/or such Associate Participants in all respect administration and enforcement of all such contracts and other arrangements; (d) to take such steps as may be required to obtain and keep in force all licenses and permits required by law, rule, regulation or order of any governmental agency for the ownership, construction, operation and maintenance of the Millstone Plant; (e) to make and receive all payments in connection with the foregoing, in the name or on behalf of CL&P and WMECO; and (f) to enter into, renew and modify leases and other arrangements permitting the use of portions of the Millstone Site and the Simulator Building by others where such arrangements will not interfere with the operation of the Millstone Plant and will be to the benefit of CL&P and/or WMECO. CL&P and WMECO each hereby affirms and ratifies any and all such contracts, arrangements and actions heretofore taken by NNECO within the scope of the authority conferred by this Agreement. 3. Financial Obligations of CL&P and WMECO. (a) General. CL&P and WMECO each agrees to pay its respective Unit 1 and 2 Ownership Percentage of all amounts required to be paid with respect to the ownership, licensing, maintenance, operation, leasing (including all amounts payable by NNECO as lessee under any lease, including rent and amounts payable upon termination of such lease) and financing of Units 1 and 2, the Unit 1 and 2 Simulators, and all renewals, replacements, additions, retirements and modifications to any thereof, and of that portion of the costs incurred with respect to the Simulator Building and the ownership, maintenance and operation of the Millstone Common Facilities and the Millstone Site that is allocable to Units 1 and 2. Pursuant to the Sharing Agreement, each Associate Participant is liable for its respective ownership percentage of the costs with respect to the ownership, design, construction, maintenance and operation of Unit 3, the Unit 3 Simulator, and all renewals, replacements, additions, retirements and modifications to either thereof, and for its respective ownership percentage of that portion of the costs incurred with respect to the Simulator Building and the ownership, maintenance and operation of the Millstone Common Facilities and the Millstone Site that is allocable to Unit 3. CL&P and WMECO each agrees to pay its respective Unit 3 Percentage Share, as hereinafter defined, of all amounts required to be paid with respect to the ownership, design, construction, licensing, maintenance, operation, leasing (including all amounts payable by NNECO as lessee under any lease, including rent and amounts payable upon termination of such lease) and financing of Unit 3, the Unit 3 Simulator, and all renewals, replacement, additions, retirements and modifications to either thereof, and of that portion of the costs incurred with respect to the Simulator Building and the ownership, maintenance and operation of the Millstone Common Facilities and the Millstone Site that is allocable to Unit 3, except to the extent that NNECO is directly reimbursed for such amounts by the Associate Participants. For purposes of this Agreement, the "Unit 3 Percentage Share of each Lead Participant shall be that number, expressed as a percentage, determined by dividing such Lead Participant's Unit 3 Ownership Percentage by the sum of the Unit 3 Ownership Percentages of both Lead Participants. NNECO shall allocate, in an equitable manner as instructed by CL&P and WMECO, costs related to the Millstone Common Facilities and the Millstone Site among Units 1, 2 and 3, and costs related to the Simulator Building among Units 1, 2 and 3 and the Haddam Neck Unit. (b) Reimbursement payments. With respect to each month commencing as of December 1, 1984, CL&P and WMECO each shall pay NNECO an amount equal to such company's Allocable Share (as defined below) of the sum of (i) all expenses of NNECO (other than those for which NNECO is directly reimbursed by Associate Participants and/or CYAPC) for the month with respect to the ownership, design, construction, licensing, maintenance, operation, leasing and financing of the Millstone Plant, or any part thereof, the Millstone Site or any portion thereof, the Simulator Building, and the Millstone Simulators, including, but not limited to, all interest expenses, cost of preferred stock, commitment fees and other similar fees and expenses with respect to short-term borrowings, long-term borrowings, preferred stock and any and all other securities issued by NNECO, other than those described in clause (ii) below, as well as any rentals, lease payments, termination payments, or other amounts payable by NNECO as lessee under or in connection with any lease of the Millstone Simulators or other assets, to finance assets and to finance other costs of performance of this Agreement; and (ii) to the extent not directly paid to NNECO by the Associate Participants and/or CYAPC, an amount equal to one-twelfth of the Annual Equity Return based on NNECO's Total Equity Capitalization as at the end of the preceding month. Payments made by CL&P and WMECO under this Subsection (b) shall be made by each such company both in its capacity as an owner of Units 1 and 2 and as a Lead Participant (as defined in the Sharing Agreement). For purposes of this Subsection (b): (A) The term "Allocable Share" shall mean that percentage of the total payments to be made pursuant to this Subsection (b) as NNECO shall determine is equitably attributable to each of CL&P and WMECO on the basis of the ownership of the Unit with respect to which the costs to be reimbursed are allocable, with allocations to Units 1 and 2 being made to each of CL&P and WMECO on the basis of its Unit 1 and 2 Ownership Percentage, and allocations to Unit 3 being made to each of CL&P and WMECO on the basis of its Unit 3 Ownership Percentage. (B) the term "NNECO's Total Equity Capitalization" shall include the amount properly reflected on NNECO's balance sheet at month end for common stock, retained earnings, capital contributions and other paid-in capital (other than preferred stock), and for any non-interest bearing notes or other non-interest bearing evidences of indebtedness issued by NNECO to CL&P, WMECO, Northeast Utilities or any other associate company (as said term is defined in the Public Utility Holding Company Act of 1935) of NNECO, so long as the payment of such indebtedness is expressly subordinated to borrowings by NNECO from persons which are not affiliates of NNECO; and (C) the term "Annual Equity Return" shall mean the weighted average return on equity approved for CL&P and WMECO in their most recent retail rate proceedings before the Connecticut and Massachusetts regulatory commissions, such weighted average return to be determined annually as of December 31 for the following calendar year and to be calculated by taking the equity return approved for each of CL&P and WMECO in its most recent retail rate proceeding on or before the applicable December 31 and weighting each company's equity return by the average of its respective December 31 for the following calendar Unit 1 and 2 Ownership Percentage and its Share. NNECO shall allocate, in accordance with instructions from CL&P and WMECO, the amount of NNECO's Total Equity Capitalization not payable by CYAPC under the CYAPC Agreement among Units 1, 2 and 3 so as to result in an equitable sharing of the monthly payments with respect to Annual Equity Return among CL&P, WMECO and the Associate Participants. Pursuant to the Sharing Agreement, each Associate; Participant will be liable each month for its applicable ownership percentage of one-twelfth of the Annual Equity Return on that portion of NNECO's Total Equity Capitalization applicable to Unit 3 as of the end of the preceding month. The expenses referred to in clause (i) of this Subsection (b) shall include, but shall not be limited to: operation and maintenance expenses as determined in accordance with the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission; license fees; assessments and other governmental charges and sales, use, excise, franchise, personal property, gross receipts, income and other taxes which are payable by NNECO on account of the ownership, occupation, lease or use of the Millstone Plant, the Millstone Site or any portion thereof, the Simulator Building, the Millstone Simulators or other assets therefor, the construction, maintenance or operation of the Millstone Plant, the Simulator Building or the Millstone Simulators, earnings arising therefrom and the receipt of payments hereunder, the shutdown or demolition of the Millstone Plant or any portion thereof, the Millstone Simulators, earnings arising therefrom and the receipt of payments hereunder, the shutdown or demolition of the Millstone Plant or any portion thereof, the Simulator Building or the Millstone Simulators or on account of costs and expenses for administration, labor, payroll taxes, employee benefits, research and development. The costs and expenses of NNECO with respect to the Ownership of the Simulator Building shall be allocated among the Millstone Units so that the respective Lead Participants or owners of each such Unit shall pay an amount each month which will result in the payment to NNECO by such Lead Participants or owners, over the useful life of each such Unit, in equal monthly installments, of twenty-five percent (25%) of the cost of the Simulator Building and all renewals, replacements, additions, retirements and modifications thereto. NNECO shall bill CL&P and WMECO and, as agent of CL&P and WMECO in their capacities as Lead Participants under the Sharing Agreement, each Associate Participant, as soon as practicable after the end of each month for all amounts payable to NNECO by CL&P, WMECO or such Associate Participant with respect to such month. Such bills shall be rendered in such detail as CL&P or WMECO (on behalf of itself or on behalf of any Associate Participant) may determine is reasonable and may be rendered on an estimated basis subject to corrective adjustments in subsequent billing periods. CL&P and WMECO shall pay in full all bills addressed to them within fifteen (15) days after the invoice date. In the event CL&P or WMECO fails to pay any bill within fifteen (15) days after the invoice date, it shall be obligated to pay interest thereon from the date of the bill at a rate per annum two percent (2%) above the prime rate (or comparable rate) in effect at The Connecticut Bank and Trust Company, N.A., in Hartford, Connecticut, from time to time. Each Associate Participant shall pay NNECO in full all bills rendered to such Associate Participant, in accordance with the payment terms of the Sharing Agreement, including interest on late payments. If any bill so rendered to an Associate Participant is not paid within sixty (60) days after thereof, CL&P and WMEC0 shall pay such bill and any interest due thereon under the Sharing Agreement and shall be reimbursed for such payment by such Associate Participant as provided in the Sharing Agreement. All costs and expenses with respect to the ownership, design, construction, operation, licensing and maintenance of the Millstone Plant and the Millstone Site and renewals, replacements, additions, modifications and retirements in respect thereof shall be accounted for in accordance with the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission. Notwithstanding the foregoing, interest charges on borrowed funds, depreciation and amortization, income taxes, and property, business and occupation and like taxes of CL&P and WMECO shall be borne entirely by such companies. 4. Records and Accounting. (a) NNECO shall keep all necessary books of records, books of account and memoranda of all transactions involving the Millstone Plant, the Millstone Site, the Simulator Building and the Millstone Simulators, and shall make such calculations on behalf of CL&P and WMECO as may be necessary or appropriate (i) to enable each to conform to the record keeping and reporting requirements of the Federal Energy Regulatory Commission, (ii) to permit each to maintain its own records and books of account, and (iii) to enable each to fulfill its record keeping and accounting obligations under the Sharing Agreement. NNECO shall perform all necessary invoicing and other actions on behalf of CL&P and WMECO as required in any instance by the foregoing, all in accordance with and subject to the provisions of this Agreement. CL&P and WMECO shall have the right to inspect and audit NNECO books and records during normal business hours and in a reasonable manner and for so long as such books and records shall be preserved. (b) NNECO shall account at least annually to all Participants (as defined under the Sharing Agreement) in Unit 3 in such form as CL&P and WMECO may reasonably determine for all expenses incurred in the design, engineering, procurement, installation, construction, operation, maintenance, insuring, licensing and shutdown of Unit 3. NNECO shall provide to Participants all other reports required by the Sharing Agreement, including, but not limited to, cash flow estimates, projected costs and construction progress reports. 5. Renewals, Replacements, Additions, Retirements and Modifications. NNECO, as the agent of CL&P and WMECO, shall make on their behalf all such renewals, replacements, additions, retirements and modifications to or with respect to the Millstone Plant, the Millstone Common Facilities, the Millstone Site, the Simulator Building, and the Millstone Simulators as it deems necessary or appropriate, except that the approval of CL&P and WMECO shall be required for any expenditure of more than $500,000 or for the replacement or retirement of any property having an original cost of more than $500,000, and except that no commitment, whether preliminary or otherwise, shall be made with respect to additional generating units at the Millstone Site without the consent of both CL&P and WMECO. Retirements, sales and other dispositions of Millstone Plant property (including the Millstone Plant, the Millstone Common Facilities, the Simulator Building, and the Millstone Simulators) shall be effected only in a manner consistent with the respective mortgage indentures and other instruments or documents under which liens on all or part of such Millstone Plant property may arise, and, in the case of retirements, sales and other dispositions of Unit 3 property, in a manner consistent with the Sharing Agreement. Renewals, replacements, additions, retirements and related dispositions and sales shall be effected for the respective accounts of CL&P and/or WMECO, or, in the case of Unit 3 property, the Participants. 6. Millstone Plant Operations. NNECO shall have sole authority to determine when and how the Millstone Plant shall be operated. If, in its opinion, the requests of CL&P and WMECO as to the time or manner of operation are, in any respect, inconsistent with safety of operation, it shall operate the Millstone Plant in accordance with its judgment as to the requirements of safety. Subject to the foregoing, NNECO agrees to use its best efforts to operate the Millstone Plant in accordance with good utility operating practice and such policies as are established from time to time by CL&P and WMECO. NNECO shall consult with CL&P and WMECO as to times for scheduled shutdowns for refueling and maintenance, but in any case when, in its opinion, a non-scheduled shutdown is required, it shall have full authority to effect the shutdown. 7. Title to Property. Except for property conveyed by any Lead Participant or Associate Participant to a third party in connection with a leasing or other transaction permitted by the Sharing Agreement, including but not limited to the Lead Participants' interest in the Unit 3 Simulator, title to all property acquired or constructed in connection with Unit 3 (including, without limitation, property acquired for use or consumption in connection with the design, construction, operation and maintenance of Unit 3 and any related leasehold estate), including the Unit 3 Simulator but excluding the Simulator Building and the refuel outage building, and also excluding materials and supplies acquired, paid for and owned by NNECO and held in inventory (until such materials and supplies are used), shall be held in accordance with the Sharing Agreement and shall be in CL&P and WMECO and the Associate Participants as tenants in common in proportion to their ownership percentages set forth in the Sharing Agreement, subject to the right of NNECO under other provisions of this Agreement to convey title to such property to a third party in connection with a leasing or other transaction. Except for property conveyed by CL&P or WMECO to a third party in connection with a leasing or other transaction, title to all other property acquired or constructed in connection with the Millstone Plant or the Millstone Site (including, without limitation, property acquired for use or consumption in connection with the operation and maintenance of the Millstone Plant and any related leasehold estate), including the Unit 1 and 2 Simulators but excluding the Simulator Building and the refuel outage building, and also excluding materials and supplies acquired, paid for and owned by NNECO and held in inventory (until such materials and supplies are used), shall be in CL&P and WMECO as tenants in common in proportion to their Unit 1 and 2 Ownership Percentages, subject to the right of NNECO under other provisions of this Agreement to convey title to such property to a third party in connection with a leasing or other transaction. Title to the Simulator Building shall be in NNECO and shall be held in accordance with this Agreement, subject to the right of NNECO under other provisions of this Agreement to convey title to such property to a third party in connection with a leasing or other transaction. 8. Capacity and Energy of Millstone Units. CL&P and WMECO shall at all times have full ownership of, and available to it at Units 1 and 2, that portion of the generating capability of Units 1 and 2 and the net electrical output associated therewith corresponding to their Unit 1 and 2 Ownership Percentages, and CL&P and WMECO shall each be obligated to take its Unit 1 and 2 Ownership Percentage of the net electrical output of Units 1 and 2. The portion of the generating capability and net electrical output of Unit 3 to which CL&P, WMECO and each Associate Participant shall be entitled shall be governed by the Sharing Agreement and subsequent agreements among the Participants in Unit 3. Subject to NNECO's right to determine when and how the Millstone Plant shall be operated, the dispatching of generation shall be done on behalf of the respective owners by and through such dispatching agency as they may designate from time to time. 9. Limitation of NNECO's Activities and Liability. NNECO agrees that, during the term of this Agreement, it will confine its activities to those contemplated by and reasonably incidental to its responsibilities under this Agreement and the CYAPC Agreement and such other incidental activities as may be required in order to preserve its corporate existence, its right to do business and its other rights and franchises. Accordingly, and inasmuch as NNECO is intended as an instrumentality for the design, construction, operation, maintenance, leasing and financing of the Millstone Plant, the Millstone Site, the Millstone Common Facilities, the Simulator Building and the Millstone Simulators, it is expressly agreed that the costs and expenses of NNECO to be reimbursed hereunder, extent not payable by CYAPC under the Letter Agreement, shall include all of NNECO's necessary corporate and general expenses and all other expenses, if any, necessarily incurred by NNECO for the payment of taxes on its income or property, or necessarily incurred by NNECO to protect and preserve its corporate existence, its right to do business or its rights and franchises. Further, it is expressly understood and agreed that neither CL&P, WMECO nor any Associate Participant shall, at any time, or under any circumstances, have or make any claim for damages against NNECO on account of damages to property, if any, caused by it or the nondelivery by it, at any time, of all or any portion of the net electrical output agreed to be made available from the Millstone Plant, or for any reduction or delay in such delivery, however caused, or for any other reason of any nature; all such claims for money damages, however and whenever arising, being hereby expressly waived and released by each owner respectively. No provision herein shall be construed as waiving, impairing or releasing such rights as CL&P or WMECO may have to require the specific performance of this Agreement. 10. Furnishing of Funds to NNECO. CL&P and WMECO shall make funds available to NNECO for NNECO's use in carrying out its functions under this Agreement, either by directly turning over such funds to NNECO or by making such funds available in bank accounts of CL&P and WMECO (either joint or several), as NNECO may request from time to time, and NNECO may draw upon any such bank accounts. 11. Term of Agreement. This Agreement shall continue in full force and effect, with respect to each Unit, for the useful life and decommissioning periods of Units 1, 2 and 3, as applicable, unless earlier terminated with respect to any or all Millstone Units by mutual agreement of NNECO and the respective Lead Participants or owners of the affected Millstone Unit; provided, however, that this Agreement, or any part thereof, shall be canceled to the extent and from the time that the performance hereunder may conflict with any rule, regulation or order of the Securities and Exchange Commission adopted before or after the execution hereof under the provisions of the Public Utility Holding Company Act of 1935 or with any rule regulation or order of any federal or state regulatory body having jurisdiction to review and to make determinations with respect to any provision of this Agreement, this Agreement to be subject to such review and determinations in accordance with applicable law. In the event that this Agreement is terminated with respect to one or more of the Millstone Units prior to the payment by the respective Lead Participants or owners of each such Unit of a twenty-five percent (25%) share of the cost of the Simulator Building and any renewals, replacements, additions, retirements and modifications thereto, such respective Lead Participants or owners shall within thirty (30) days of such termination pay to NNECO the remaining balance of such share. 12. Amendments. This Agreement may be amended at any time by mutual written agreement of the parties hereto. 13. Successors and Assigns. This Agreement shall inure to the benefit of and bind the successors and assigns of the parties hereto, but it may be assigned in whole or in part by CL&P and/or WMECO only as part of an assignment (including any assignment in connection with a financing) of a corresponding ownership interest in one or more of the Millstone Units and/or any part of the Millstone Plant, the Millstone Site, the Millstone Common Facilities, the Simulator Building, any one or more of the Millstone Simulators, the nuclear fuel or other assets for any one or more of the Millstone Units. IN WITNESS WHEREOF each of the parties has caused this Agreement to be duly executed. THE CONNECTICUT LIGHT AND POWER COMPANY By /s/Leonard A. O'Connor ---------------------------------------------- Name: Leonard A. O'Connor Title: Vice President & Treasurer WESTERN MASSACHUSETTS ELECTRIC COMPANY By /s/Leonard A. O'Connor ---------------------------------------------- Name: Leonard A. O'Connor Title: Vice President & Treasurer NORTHEAST NUCLEAR ENERGY COMPANY By /s/Leonard A. O'Connor ---------------------------------------------- EX-10.21.2 14 MEMORANDUM OF UNDERSTANDING JOINT USE OF SPECIFIED LOCAL TRANSMISSION AND DISTRIBUTION FACILITIES Memorandum of Understanding dated as of January 1, 1984 by and among The Connecticut Light and Power Company, Holyoke Power and Electric Company, Holyoke Water Power Company and Western Massachusetts Electric Company, each an operating subsidiary of Northeast Utilities (the "Companies"). RECITALS Certain of the Companies presently serve portions of their respective local load areas by making joint use of particular local transmission and distribution facilities with one or more of the other Companies under the terms of the agreement listed in Exhibit A hereof. The Companies have entered into a MEMORANDUM OF UNDERSTANDING regarding POOLING OF GENERATION AND TRANSMISSION, dated as of June 1, 1970, whereby the Companies have agreed to pool their generation and backbone transmission facilities on a one-system basis. Said MEMORANDUM OF UNDERSTANDING superseded portions of various agreements between the Companies pursuant to which certain of the Companies had formerly made joint use of both backbone and local transmission and distribution facilities. The Companies have constructed and are operating local transmission and distribution facilities on a joint basis, and intend to plan, construct and operate additional facilities of this type with the objective of supplying the electric requirements of their customers at the lowest practicable costs consistent with proper standards of reliability. The Companies have agreed that their respective joint uses of local transmission and distribution facilities will be on the basis of coordinated operations by the Companies and in accordance with good utility practice. The Companies contemplate that their joint use of specified local transmission and distribution facilities will be for relatively long periods of time and should be made in accordance with consistent and uniform understandings regarding sharing of resulting benefits and burdens. The Companies intend, with the assistance of Northeast Utilities Service Company, from time to time to review the adequacy of jointly used local transmission and distribution facilities and appropriately adjust charges for such use. The Companies, with the assistance of Northeast Utilities Service Company, further intend to coordinate and share the use of local transmission and distribution facilities wherever practicable in order that such facilities will have the least adverse effect on the environment. In the light of these circumstances, therefore, the Companies have concluded that a more comprehensive arrangement among them is necessary and desirable to provide reasonable assurance of attaining the above objectives and have decided to share the costs of specified local transmission and distribution facilities commencing as of the effective date of the Agreement. ACCORDINGLY, it is agreed that: SECTION 1. DATES OF COMMENCEMENT, TERMINATION, ETC. (a) Subject to the acceptance of this Memorandum as a rate filing by the Federal Energy Regulatory Commission, this Memorandum shall be effective as of January 1, 1984. The agreement listed in Exhibit A attached hereto shall be terminated as of the effective date of this Agreement and relating to the respective facility. (b) This Memorandum shall continue in effect until amended or terminated by mutual agreement or by order of public authority having jurisdiction. SECTION 2. JOINT-USE FACILITIES The Companies shall plan, construct, participate in and operate local transmission and distribution facilities for joint use wherever practicable in order to achieve the objectives recited above. Each such specified facility shall be known as a Joint-Use Facility. The non-owner(s) of such Joint-Use Facilities shall be known as the joint user(s). SECTION 3. GENERAL PRINCIPLES OF JOINT USE (a) Normally, the use of a Joint-Use Facility will be in order to transmit electricity from one point, station or substation, to another location, using one (or more) Company's local transmission and distribution facilities which have sufficient load carrying capabilities to permit the efficient use of a portion of such capacity by another Company, or such joint use may take the form of utilizing substation and distribution facilities (either existing or jointly planned) thereby making duplicate investments unnecessary. In some instances, one Company may install new facilities for the initial sole use of another Company. (b) The owner of a Joint-Use Facility should be reimbursed by the joint user(s) for an appropriate share of the owner's costs with respect thereto. The components of costs to be considered in determining such amount to be paid to the owner should include an adequate provision for investment return to the owner and all operation and maintenance expense, depreciation expense and tax expense borne by the owner with respect to the Joint-Use Facility. (c) The Companies agree that it is generally reasonable to determine the amount to be paid by one Company for the use of another's local transmission and distribution facilities by allocating the costs with respect to such facilities between the owner and joint user(s) in proportion to the respective relative loads supplied therefrom. It is recognized, however, that in many circumstances, allocation of costs based on factors other than, or in addition to, the actual load supplied may result in a more equitable sharing of costs. (d) It is expected that the joint use of certain facilities will continue for many years. Therefore, the load carrying capabilities (existing and potential) of particular facilities and the forecasted use by each Company of such facilities should be considered in making decisions with respect to joint use. (e) If, in the opinion of the owning Company, the total load carrying capability of a Joint-Use Facility may became inadequate for its own needs together with the joint use of another Company, the facilities required for the purposes of the owning Company and those required to continue to adequately serve the particular local area load of the joint user(s), and the extent, if any, of continued joint use of such facilities shall be determined by mutual agreement. (f) The extent of joint use of facilities, the amounts to be paid for such use, and the method of determining such amounts shall be reviewed periodically and changed by mutual agreement to the extent appropriate. (g) Each Company shall be solely responsible for providing all electricity required to supply its own loads including all capacity and energy losses incidental to the transmission, transformation and distribution of such electricity incurred on any Joint-Use Facility owned by another Company. (h) Metering of electricity provided by one Company and transmitted and distributed on transmission and distribution facilities of another Company shall be done in such manner and at such places as may be mutually agreed from time to time. For accounting purposes, segregation shall be made of such electricity from other electricity flowing on and between the systems of the Companies. SECTION 4. SHARING COSTS OF JOINT-USE FACILITIES (a) The Companies shall share the costs of Joint-Use Facilities on the basis of the relation of their respective uses of each such facility. For the purposes of this Memorandum, the method of determination of the respective uses of each Joint-Use Facility will be specified in Appendix I attached hereto. (b) Costs of each such Joint-Use Facility for any month shall be those costs associated with the Operation and Maintenance Expense, Depreciation Expense, Property Tax Expense, Leasing Expense, Investment Return, Income Tax Expense and Other Tax Expense with respect to each such facility for each month of joint use. (c) Northeast Utilities Service Company shall act as accounting and billing agent for the Companies under this Memorandum. Bills shall be rendered monthly on a net basis and may be based on estimates subject to subsequent correction to actual. SECTION 5. DEFINITIONS As used in this Memorandum and all Attachments, Exhibits and Appendices hereto, the following terms shall have the following respective meanings: (a) The term Accumulated Depreciation means an amount equal to the accrued Depreciation Expense minus the original cost of retirements and the cost of removal plus any salvage with respect thereto. (b) The term Billing Peak Load means the maximum load supplied by a Company on a Joint-Use Facility during any clock hour during the preceding sixteen (16) calendar months. The Billing Peak load may be adjusted by mutual agreement to reflect transfer of load from one Joint-Use Facility to another or otherwise, provided that such transfer shall be part of a mutually agreed upon system change or coordinated operation among the Companies. (c) The term Depreciable Investment, as applied to any Joint-Use Facility means the part of the Investment in such Joint-Use Facility which is depreciable in accordance with the provisions of the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission. (d) The term Investment as applied to any Joint-Use Facility means the original cost thereof as shown on the books of the owner in accordance with the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission at the applicable time (reflecting the cost of any betterments, improvements and additions thereto and the cost of any retirements therefrom ). (e) The term Joint-Use Facilities and/or Local Facilities as used herein means any facility included in Utility Plant (including, but not limited to, station structures and improvements, station equipment, overhead and underground lines, land and land rights) which by mutual agreement is used by a joint user(s) to supply its local loads and is described in an attachment to Appendix I attached hereto. References in this Section to mutual agreement relate to the agreement between the owner of the Joint-Use Facility and the one or more joint users participating in or directly affected by the joint use of the Joint-Use Facility which agreement is to be included as part of the appropriate attachment to Appendix I attached hereto relating to each specified Joint-Use Facility. SECTION 6. REIMBURSEMENT OF CERTAIN TAXES If at any time, any of the Companies is required by any state or local governmental authority to pay a gross revenue or other similar tax with respect to payments made to it under this Memorandum by any other Company, the Company paying the tax must be promptly reimbursed by the joint user(s) for such amount of the tax. SECTION 7. LIABILITY (a) As among the Companies, each Company will indemnify and save the others harmless from and against all costs and damages by reason of bodily injury, death or damage to the property of third persons caused by or sustained on facilities owned by it, except that each Company shall be solely responsible and shall bear all costs of claims by its own employees growing out of any workmen's compensation law. (b) The Companies agree that they shall endeavor to operate and maintain the irrespective facilities involved in this Memorandum in accordance with good utility practice, but none of the Companies guarantees an uninterrupted transfer of electricity on its facilities, and each Company hereby waives all claims against any other Company for damages of any kind resulting from any stoppage, interruption, increase, diminution or variation in service whether resulting from the negligence of another Company otherwise. SECTION 8. TREATMENT OF HOLYOKE COMPANIES Holyoke Water Power Company and Holyoke Power and Electric Company shall constitute a single party for all purposes of Sections 3 and 4 of this Memorandum. SECTION 9. TERMINATION (a) Upon termination of this Memorandum or the retirement of one or more of the jointly uses local facilities or upon a significant decrease in the use of the facilities specified in one or more of the attachments to Appendix I attached hereto, the Companies shall determine by mutual agreement such appropriate adjustments and provisions as may be necessary to provide for reasonable reimbursement to each owning Company for and with respect to such portions of the facilities constructed to effectuate the purposes of this Memorandum but which are not required by the owning Company in connection with its own operations after such termination or decrease. (b) Notwithstanding the termination of this Memorandum or the retirement of one or more of the facilities list in the attachments to Appendix I attached hereto, the applicable provisions shall continue in effect after such termination to the extent necessary to provide for adjustments and provisions under this Section and for final billing and other adjustments. SECTION 10. ARBITRATION In the event of any dispute between any of Companies or failure of any of the Companies to agree as to any matter to be determined by mutual agreement under the provisions of this Memorandum or as to the interpretation of or operation under any provision of this Memorandum upon notice from any Company, such dispute shall be submitted to arbitration. If agreement is not reached regarding appointment of an arbitrator within 30 days after the notice of submission to arbitration is given by a Company, any affected Company may apply to the American Arbitration Association for appointment of the arbitrator. The arbitrator shall be a disinterested person who is qualified in the area of the matter in dispute. The arbitrator shall conduct the proceeding in accordance with and subject to the rules of the American Arbitration Association and shall render his decision with respect to the matter in controversy as promptly as practicable. The arbitrator shall be authorized only to interpret and apply the provisions of this Memorandum, and he shall have no power to modify or change this Memorandum in any manner. The decision of the arbitrator shall be final and binding on the Companies. Each of the Companies in any arbitration proceeding shall bear its own expenses, and the expenses and fees of the arbitrator and any other expenses arising from the arbitration proceeding shall be shared equally by the Companies participating in the arbitration. SECTION 11. MISCELLANEOUS (a) This Memorandum shall be binding upon and shall inure to the benefit of the Companies and their respective successors and assigns. (b) This Memorandum including all Appendices, Exhibits and Attachments is subject to present and future state or federal statutes and to present or future regulations or orders properly issued by any regulatory agencies having jurisdiction over matters contained herein. SECTION 12. APPLICABLE LAW This Memorandum shall be interpreted, performed and controlled by and in accordance with the laws of the state of Connecticut. THE CONNECTICUT LIGHT AND POWER COMPANY By /s/ Frank P. Sabatino Its Vice President WESTERN MASSACHUSETTS ELECTRIC COMPANY By /s/ Frank P. Sabatino Its HOLYOKE WATER POWER COMPANY By /s/ Frank P. Sabatino Its HOLYOKE POWER AND ELECTRIC COMPANY By /s/ Frank P. Sabatino Its EXHIBIT A The following agreement is to be terminated as of the effective date of this Agreement and relating to the specific facility: 1. Agreement between The Hartford Electric Light Company and Western Massachusetts Electric Company relating to the Southwick Substation (MWME FPC Rate Schedule 13). Appendix I Local Facilities Agreement The annual costs of the Local Facilities shall be the estimated annual costs of owning, operating, maintaining, and supporting those facilities, including applicable leasing costs. These costs shall be computed annually. In determining such costs, the provisions of the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission for major electric utilities and licensees shall be controlling, to the extent applicable. I. Determination of Investment Base The Investment Base is the sum of Net Investment and Working Capital as determined at the end of the preceding calendar year unless there is a substantial change (of $500,000 or more) in the Investment Base during the calendar year. A. Net Investment Net investment shall be the original cost (including the cost of any betterments, improvements, and additions thereto and excluding the cost of any retirements therefrom) of the Local Facility, as reflected on the Owner's books of account, less the sum of (1) accumulated depreciation and (2) accumulated deferred federal and state income taxes arising from liberalized depreciation and accelerated amortization. Accumulated depreciation shall reflect retirements and net salvage realized. Accumulated deferred income taxes shall be computed using the same life, methods, rates, salvage factors, and accounting practices as reflected on the Owner's books of account, and shall be applicable to investments made in such facilities on or subsequent to the effective date of this Agreement. In the event that the Owner has employed a liberalized tax depreciation or accelerated depreciation method and thereafter employs a different method, any necessary allowance or adjustment shall be made in order to insure that any such change of methods does not result in any overcollection or undercollection by the Owner. B. Working Capital Working capital to be included in the Investment Base shall include 45 days (out of 360) of related operation and maintenance expense and the Owner's best estimate of the cost of related materials and supplies and an appropriate allowance for any payments made pursuant to the prepayment provisions applicable leases. II. Determination of Annual Carrying Costs of Local Facilities The following cost factors shall be used in determining the annual carrying costs of the Local Facilities: A. Operation and Maintenance Expense B. Property Tax Expense C. Depreciation Expense D. Investment Return E. Income Tax Expense F. Investment Tax Credit Allowance G. Leasing Expense H. Other Tax Expense A. Operation and Maintenance Expense Operation and maintenance expense means an amount equal to the sum of the following: (1) the actual cost (or the best estimate thereof) of the annual expense of operating and maintaining the Local Facility; (2) an appropriate allowance to cover the related administrative and general expenses, including, but not limited to, employee pensions and benefits, federal and state taxes related to the direct payroll expense, and property insurance expense for the Local Facility. The allowance for the administrative and general expenses is initially estimated at 40 percent of the operation and maintenance expense provided in (1) above. This allowance shall be subject to periodic review, and shall be revised, when and to the extent deemed appropriate by the Owner, in accordance with the results of any such review. B. Property Tax Expense Property tax expense shall consist of those taxes or excise payments that are based upon the assessed value of the Local Facility, and specifically identified with that facility, or the Owner's best estimate thereof. The procedures for determining the amounts of any such estimates shall be determined by the Owner. The Owner shall have the sole discretion in any negotiations with taxing authorities. C. Depreciation Expense Depreciation expense shall be determined on the same basis as recorded on the Owner's books of account. D. Investment Return Investment return for the Local Facility shall be determined by multiplying the Owner's investment base by the Owner's composite cost of capital. The Owner's composite cost of capital shall be computed on the basis of its cost, expressed in percentages, for (1) bonds and other long-term indebtedness, (2) preferred stock, and (3) for the return on common equity as granted in its most recent rate order from the regulatory authority having principal jurisdiction over the Owner's rates. These costs shall be combined in accordance with the following formula to determine the Owner's composite cost of capital: Composite Cost of Capital = Ax8 + CxD + ExF in which: A - the Owner's cost for long-term indebtedness B - the percentage of the Owner's capitalization represented by long-term indebtedness C - the Owner's cost for preferred stock D - the percentage of the Owner's capitalization represented by preferred stock E - the Owner's return on common equity F - the percentage of the Owner's capitalization represented by common equity In the above formula, the Owner's capitalization consists of its components of long-term indebtedness, preferred stock, and common equity. Those components and the percentage of capitalization represented by each of those components shall be rounded off to the nearest whole number. The Owner's cost of long-term indebtedness in the above formula is the weighted average of the costs of its various issues of long-term indebtedness. The cost of an issue of long-term indebtedness shall be computed in accordance with the following formula: Cost of Issue in Percent = (Dividend Rate (%) x Aggregate Par or Stated Value) / (Proceeds to Company from Underwriter or Investor less Company Expenses of Issue) The Owner's investment return for a year shall be computed initially at the beginning of the year on the basis of its investment base and its composite cost of capital as of the beginning of the year. The investment return, as so computed, shall be recomputed each time that a substantial change in its Investment Base or composite cost of capital occurs during the year, and at any such other time as the Companies mutually agree is appropriate. E. Income Tax Expense An allowance for income taxes shall be computed in accordance with the following formula: (Te / 1-Te) x [(IB (PE + CE)) + (DB - DT)] Te - the effective combined federal and state statutory income tax rate of the Owner IB - Investment Base PE - Weighted Preferred Stock Component (C x D in II.D.) CE - Weighted Common Equity Component (E x F in II.D.) DB - Book depreciation DT - Tax depreciation Where the book depreciation (DB) and tax depreciation (DT) apply only to investments made in the Local Facility prior to the effective date of this Agreement. F. Investment Tax Credit Allowance Applicable investment tax credits are those based upon the Owner's applicable investments placed in service on or subsequent to the effective date of this Agreement. An allowance for any applicable investment tax credit shall be reflected ratably over the remaining book depreciable life of the Local Facility. This allowance for the normalized investment tax credit shall be calculated by dividing the investment tax credit by the estimated remaining book depreciable life, by one minus the effective tax rate, as described below: IC / (1-Td)N IC - the applicable investment tax credit Te - as previously defined N - remaining book depreciable life of the Local Facility expressed in years G. Leasing Expense Leasing expense shall consist of those leasing costs (or rental payments) charged to the Owner and related to the Local Facility. H. Other Tax Expense Other tax expense shall consist of any taxes or excises which are incurred in the future as a result of constructing, owning, operating, or leasing the Local Facility. Such tax expense shall include any tax, on gross revenues or any tax pertaining to the billing of those annual costs, which is not recognized elsewhere in this Agreement. III. Allocation of Annual Carrying Costs of NU Local Facilities The Annual Carrying Costs listed above (II.A. through II.E.) shall be allocated to the Participants as follows: A. Transmission Facilities Jointly used transmission facilities shall be allocated in accordance with the provisions of the NUG&T Agreement. B. Substation Facilities One-half of the cost of such jointly used substation facilities shall be allocated in accordance with the provisions of the NUG&T Agreement and the remainder of such costs shall be allocated on the basis of the number of feeder positions assigned. Spare (unloaded) feeder positions shall be included in this allocation. When one party's feeder is tapped in the field, this allocation will still reflect the number of feeder positions assigned to each party. C. Distribution Facilities 1. Duct Lines - Shall be allocated on the basis of the number of ducts actually utilized by each party. Spare ducts shall be included in this allocation. 2. Feeders - When one party's feeder is tapped in the field, the costs of the jointly used portion shall be allocated on an equal basis between the parties. ATTACHMENT 1 January 6, 1993 TO: H. C. Walmsley FROM: B. K. Morton (x5369) SUBJECT: NU Local Facilities Adjustment Below are the adjustments to the December 1992 NU Local Facilities billings: Chicopee Franconia Silver St Southwick Trans. S/S S/S S/S S/S Distrib. HWP=User CL&P=User CL&P=User CL&P=User CL&P=User Total User Carrying Charge $ 0 $78,285 $24,165 $47,096 $18,041 Less: Amount Billed Jan-Nov 1992 369,600 67,100 20,900 79,200 14,300 Less: Adjustment for Nov & Dec 1991 67,169 Adjustment Due To/ (Reimbursed By) WMECO ($436,769) $11,185 $3,265 ($32,104) $3,741 Detailed below are the 1993 monthly billings for NU Local Facilities. Monthly Billing To Be Collected Jan-Nov $ 0 $6,500 $2,000 $3,900 $1,500 We will provide you with the December adjustment to actual carrying cost in January of 1994. Please contact me if you have any questions. bkm/bm cc: R. A. Baumann J. M. Geruch J. J. Roman NORTHEAST UTILITIES LOCAL FACILITIES FRANCONIA SUBSTATION 1992 CHARGES SOLE USE SOLE USE JOINT USE NON-OWNER (CL&P) OWNER (WMECO) INVESTMENT BASE: NON-DEPRECIABLE LAND $37,660 5,380 10,760 ALLOW FOR WKNG CAP: MAT. & SUPPLIES 11,475 221 1,367 WKNG CAP ALLOW 20,621 465 3,043 TOTAL ALLOWANCE 32,096 686 4,410 TOTAL NON-DEPRECIABLE 69,756 6,066 15,170 DEPRECIABLE INVESTMENT 1,311,950 25,231 156,312 ACCUMULATED DEPRECIATION (595,088) (19,918) (66,865) ACCUM DEFERRED INC TAXES (21,582) 0 (1,133) NET INVESTMENT $765,036 11,379 103,484 ANNUAL CARRYING CHARGES: OPER. AND MAINT. EXPENSE $112,265 2,328 14,427 ADMIN. & GEN. EXPENSE 44,906 931 5,771 LEASING EXPENSE 31,192 1,843 16,591 DEPRECIATION EXPENSE 25,580 487 3,017 PROPERTY TAX EXPENSE 13,328 302 1,650 INVESTMENT RETURN 72,143 1,073 9,758 INCOME TAX EXPENSE 23,537 329 3,224 INVESTMENT TAX CREDIT (114) 0 0 OTHER TAX EXPENSE 0 0 0 TOTAL CARRYING CHARGES $322,837 7,293 54,438 ALLOCATED % TO NON-OWNER 21.99% 100.00% CARRYING CHARGE ALLOCATION $70,992 7,293 TOTAL CARRYING CHARGE TO NON-OWNER (CL&P) 78,285 NORTHEAST UTILITIES LOCAL FACILITIES SILVER ST SUBSTATION 1992 CHARGES SOLE USE SOLE USE JOINT USE NON-OWNER (CL&P) OWNER (WMECO) INVESTMENT BASE: NON-DEPRECIABLE LAND $ 0 N/A 0 ALLOW FOR WKNG CAP: MAT. & SUPPLIES 8,135 N/A 1,648 WKNG CAP ALLOW 14,642 N/A 3,018 TOTAL ALLOWANCE 22,777 N/A 4,666 TOTAL NON-DEPRECIABLE 22,777 N/A 4,666 DEPRECIABLE INVESTMENT 930,072 N/A 188,428 ACCUMULATED DEPRECIATION (379,849) N/A (113,096) ACCUM DEFERRED INC TAXES (33,735) N/A (1,092) NET INVESTMENT $539,265 N/A 78,906 ANNUAL CARRYING CHARGES: OPER. AND MAINT. EXPENSE $83,668 N/A 17,248 ADMIN. & GEN. EXPENSE 33,467 N/A 6,899 DEPRECIATION EXPENSE 18,138 N/A 3,639 PROPERTY TAX EXPENSE 11,962 N/A 2,423 INVESTMENT RETURN 50,853 N/A 7,441 INCOME TAX EXPENSE 17,118 N/A 2,293 INVESTMENT TAX CREDIT (26) N/A 0 OTHER TAX EXPENSE 0 N/A 0 TOTAL CARRYING CHARGES $215,180 N/A 39,943 ALLOCATED % TO NON-OWNER 11.23% CARRYING CHARGE ALLOCATION TO NON-OWNER (CL&P) $24,165 NORTHEAST UTILITIES LOCAL FACILITIES SOUTHWICK SUBSTATION 1992 CHARGES SOLE USE SOLE USE JOINT USE NON-OWNER (CL&P) OWNER (WMECO) INVESTMENT BASE: NON-DEPRECIABLE LAND $8,355 0 440 ALLOW FOR WKNG CAP: MAT. & SUPPLIES 8,208 0 264 WKNG CAP ALLOW 14,685 0 477 TOTAL ALLOWANCE 22,893 0 741 TOTAL NON-DEPRECIABLE 31,248 0 1,181 DEPRECIABLE INVESTMENT 938,352 0 30,143 ACCUMULATED DEPRECIATION (574,715) 0 (21,113) ACCUM DEFERRED INC TAXES (14,552) 0 (524) NET INVESTMENT $380,333 0 9,687 ANNUAL CARRYING CHARGES: OPER. AND MAINT. EXPENSE 83,914 0 2,727 ADMIN. & GEN. EXPENSE 33,566 0 1,091 DEPRECIATION EXPENSE 18,254 0 583 PROPERTY TAX EXPENSE 8,633 0 279 INVESTMENT RETURN 35,865 0 914 INCOME TAX EXPENSE 11,227 0 272 INVESTMENT TAX CREDIT (90) 0 (22) OTHER TAX EXPENSE 0 0 0 TOTAL CARRYING CHARGES $191,369 0 5,844 ALLOCATED % TO NON-OWNER 24.61% 0.00% CARRYING CHARGE ALLOCATION $47,096 0 TOTAL CARRYING CHARGE TO NON-OWNER (CL&P) $47,096 NORTHEAST UTILITIES LOCAL FACILITIES FRANCONIA DISTRIBUTION 1992 CHARGES WMECO INVESTMENT BASE: NON-DEPRECIABLE LAND $ 0 ALLOW FOR WKNG CAP: MAT. & SUPPLIES 1,656 WKNG CAP ALLOW 1,195 TOTAL ALLOWANCE 2,851 TOTAL NON-DEPRECIABLE 2,851 DEPRECIABLE INVESTMENT 189,271 ACCUMULATED DEPRECIATION (97,944) ACCUM DEFERRED INC TAXES 0 NET INVESTMENT $ 94,178 ANNUAL CARRYING CHARGES: OPER. AND MAINT. EXPENSE $ 6,827 ADMIN. & GEN. EXPENSE 2,731 DEPRECIATION EXPENSE 3,785 PROPERTY TAX EXPENSE 2,421 INVESTMENT RETURN 8,881 INCOME TAX EXPENSE 3,061 INVESTMENT TAX CREDIT 0 OTHER TAX EXPENSE 0 TOTAL CARRYING CHARGES $ 27,706 ADJUSTMENT PERCENTAGE 0.1875 CL&P OWES TO WMECO $ 5,195 NORTHEAST UTILITIES LOCAL FACILITIES FRANCONIA DISTRIBUTION 1992 CHARGES CL&P INVESTMENT BASE: NON-DEPRECIABLE LAND $ 0 ALLOW FOR WKNG CAP: MAT. & SUPPLIES 807 WKNG CAP ALLOW 583 TOTAL ALLOWANCE 1,390 TOTAL NON-DEPRECIABLE 1,390 DEPRECIABLE INVESTMENT 92,225 ACCUMULATED DEPRECIATION (46,380) ACCUM DEFERRED INC TAXES 0 NET INVESTMENT $ 47,235 ANNUAL CARRYING CHARGES: OPER. AND MAINT. EXPENSE $ 3,333 ADMIN. & GEN. EXPENSE 1,333 DEPRECIATION EXPENSE 3,042 PROPERTY TAX EXPENSE 1,180 INVESTMENT RETURN 4,454 INCOME TAX EXPENSE 1,618 INVESTMENT TAX CREDIT 0 OTHER TAX EXPENSE 0 TOTAL CARRYING CHARGES $ 14,960 ADJUSTMENT PERCENTAGE 0.5000 CL&P OWES TO WMECO $ 7,480 NORTHEAST UTILITIES LOCAL FACILITIES SILVER STREET DISTRIBUTION 1992 CHARGES COMMON INVESTMENT BASE: NON-DEPRECIABLE LAND $ 0 ALLOW FOR WKNG CAP: MAT. & SUPPLIES 1,865 WKNG CAP ALLOW 1,348 TOTAL ALLOWANCE 3,213 TOTAL NON-DEPRECIABLE 3,213 DEPRECIABLE INVESTMENT 213,187 ACCUMULATED DEPRECIATION (21,019) ACCUM DEFERRED INC TAXES 0 NET INVESTMENT $195,381 ANNUAL CARRYING CHARGES: OPER. AND MAINT. EXPENSE $ 7,702 ADMIN. & GEN. EXPENSE 3,081 DEPRECIATION EXPENSE 4,100 PROPERTY TAX EXPENSE 2,727 INVESTMENT RETURN 18,424 INCOME TAX EXPENSE 6,485 INVESTMENT TAX CREDIT (39) OTHER TAX EXPENSE 0 TOTAL CARRYING CHARGES $ 42,480 ADJUSTMENT PERCENTAGE 0.0833 CL&P OWES TO WMECO $ 3,539 NORTHEAST UTILITIES LOCAL FACILITIES SOUTHWICK DISTRIBUTION 1992 CHARGES COMMON INVESTMENT BASE: NON-DEPRECIABLE LAND $ 0 ALLOW FOR WKNG CAP: MAT. & SUPPLIES 489 WKNG CAP ALLOW 353 TOTAL ALLOWANCE 842 TOTAL NON-DEPRECIABLE 842 DEPRECIABLE INVESTMENT 55,908 ACCUMULATED DEPRECIATION (6,357) ACCUM DEFERRED INC TAXES 0 NET INVESTMENT $ 50,393 ANNUAL CARRYING CHARGES: OPER. AND MAINT. EXPENSE $ 2,018 ADMIN. & GEN. EXPENSE 807 DEPRECIATION EXPENSE 1,085 PROPERTY TAX EXPENSE 715 INVESTMENT RETURN 4,752 INCOME TAX EXPENSE 1,595 INVESTMENT TAX CREDIT (14) OTHER TAX EXPENSE 0 TOTAL CARRYING CHARGES $ 10,958 ADJUSTMENT PERCENTAGE 0.1667 CL&P OWES TO WMECO $ 1,827 NOT EFFECTIVE AS OF NOVEMBER 1, 1991 EXHIBIT 1 TO APPENDIX I LOCAL FACILITIES CHICOPEE SUBSTATION 1984 CHARGES SOLE USE SOLE USE JOINT USE NON-OWNER (HWP) OWNER (WMECO) INVESTMENT BASE: NON-DEPRECIABLE LAND $ 3,295 1,098 1,098 ALLOW FOR WKNG CAP: MAT. & SUPPLIES 12,297 2,390 1,378 WKNG CAP ALLOW 12,429 2,584 1,503 TOTAL ALLOWANCE 24,726 4,974 2,881 TOTAL NON-DEPRECIABLE 28,021 6,072 3,979 DEPRECIABLE INVESTMENT 1,218,604 236,837 136,537 ACCUMULATED DEPRECIATION (508,492) (66,191) (39,641) ACCUM DEFERRED INC TAXES 0 0 0 NET INVESTMENT $ 738,133 176,718 100,875 ANNUAL CARRYING CHARGES: OPER. AND MAINT. EXPENSE $ 71,023 14,764 8,589 ADMIN. & GEN. EXPENSE 28,409 5,906 3,436 DEPRECIATION EXPENSE 39,447 7,759 4,481 PROPERTY TAX EXPENSE 22,825 4,445 2,571 INVESTMENT RETURN 88,945 21,295 12,155 INCOME TAX EXPENSE 54,991 13,119 7,501 INVESTMENT TAX CREDIT (2,287) (559) (311) OTHER TAX EXPENSE 0 0 0 TOTAL CARRYING CHARGES $ 303,353 66,730 38,422 ALLOCATED % TO NON-OWNER * 81.28% 100.00% CARRYING CHARGE ALLOCATION 246,565 66,730 TOTAL CARRYING CHARGE TO NON-OWNER (HWP) 313,295 * SEE PAGE 3 OF EXHIBIT 1 TO APPENDIX I NOT EFFECTIVE AS OF NOVEMBER 1, 1991 EXHIBIT 1 TO APPENDIX I LOCAL FACILITIES CHICOPEE SUBSTATION 1984 INVESTMENTS SOLE USE SOLE USE ITEM JOINT USE NON-OWNER (HWP) OWNER (WMECO) TOTAL STATION LAND INVEST. $ 3,295 1,098 1,098 "PTF" LAND INVEST. 0 0 0 "NUG&T" LAND INVEST. 0 0 0 LOCAL FACIL. LAND INVEST. $ 3,295 1,098 1,098 TOTAL STATION DEPR. INVEST. $ 1,218,604 236,837 136,537 "PTF" DEPRECIABLE INVEST. 0 0 0 "NUG&T" DEPRECIABLE INVEST. 0 0 0 LOCAL FACIL. DEPR. INVEST. $ 1,218,604 236,837 136,537 LOCAL FACIL. TOTAL INVEST. $ 1,221,899 237,935 137,635 NOT EFFECTIVE AS OF NOVEMBER 1, 1991 EXHIBIT 1 TO APPENDIX I LOCAL FACILITIES CHICOPEE SUBSTATION 1984 ALLOCATORS LOAD PERCENTAGES: NON-OWNER PEAK (HWP) 238.2 MW OWNER PEAX (WMECO) 10.2 MW TOTAL OF PEAK LOADS 248.4 MW NON-OWNER PERCENTAGE 95.89% 50% OF TOTAL ALLOCATOR X .5 NET LOAD ALLOCATOR 47.95% FEEDER POSITIONS: NON-OWNER FEEDERS (HWP) 8.0 OWNER FEEDERS (WMECO) 4.0 TOTAL OF FEEDER POSITIONS 12.0 NON-OWNER PERCENTAGE 66.67% 50% OF TOTAL ALLOCATOR X .5 NET LOAD ALLOCATOR 33.33% TOTAL NON-OWNER ALLOCATOR (HWP) 81.28% ALLOCATED PER APPENDIX I SECTION III EXHIBIT 1 TO APPENDIX I LOCAL FACILITIES FRANCONIA SUBSTATION 1984 CHARGES SOLE USE SOLE USE JOINT USE NON-OWNER (CL&P) OWNER (WMECO) INVESTMENT BASE: NON-DEPRECIABLE LAND $ 37,660 5,380 10,760 ALLOW FOR WKNG CAP: MAT. & SUPPLIES 10,274 383 1,288 WKNG CAP ALLOW 11,579 613 1,953 TOTAL ALLOWANCE 21,853 996 3,241 TOTAL NON-DEPRECIABLE 59,513 6,376 14,001 DEPRECIABLE INVESTMENT 1,018,179 37,932 127,635 ACCUMULATED DEPRECIATION (303,273) (10,426) (37,407) ACCUM DEFERRED INC TAXES 0 0 0 NET INVESTMENT $ 774,419 33,882 104,229 ANNUAL CARRYING CHARGES: OPER. AND MAINT. EXPENSE $ 60,937 2,526 8,501 ADMIN. & GEN. EXPENSE 24,375 1,010 3,400 LEASING EXPENSE 29,280 5,459 14,888 DEPRECIATION EXPENSE 33,094 1,259 4,237 PROPERTY TAX EXPENSE 15,688 644 2,056 INVESTMENT RETURN 93,317 4,083 12,560 INCOME TAX EXPENSE 57,181 22,510 7,758 INVESTMENT TAX CREDIT (2,721) (124) (343) OTHER TAX EXPENSE 0 0 0 TOTAL CARRYING CHARGES $ 311,151 17,367 53,057 ALLOCATED % TO NON-OWNER * 24.91% 100.00% CARRYING CHARGE ALLOCATION 77,508 17,367 TOTAL CARRYING CHARGE TO NON-OWNER (HWP) 94,875 * SEE PAGE 7 OF EXHIBIT 1 TO APPENDIX I EXHIBIT 1 TO APPENDIX I LOCAL FACILITIES FRANCONIA SUBSTATION 1984 INVESTMENTS SOLE USE SOLE USE ITEM JOINT USE NON-OWNER (CL&P) OWNER (WMECO) TOTAL STATION LAND INVEST. $ 37,660 5,380 10,760 "PTF" LAND INVEST. 0 0 0 "NUG&T" LAND INVEST. 0 0 0 LOCAL FACIL. LAND INVEST. $ 37,660 5,380 10,760 TOTAL STATION DEPR. INVEST. $ 1,018,179 37,932 127,635 "PTF" DEPRECIABLE INVEST. 0 0 0 "NUG&T" DEPRECIABLE INVEST. 0 0 0 LOCAL FACIL. DEPR. INVEST. $ 1,018,179 37,932 127,635 LOCAL FACIL. TOTAL INVEST. $ 1,055,839 43,312 138,395 EXHIBIT 1 TO APPENDIX I LOCAL FACILITIES FRANCONIA SUBSTATION 1984 ALLOCATORS LOAD PERCENTAGES: NON-OWNER PEAK (CL&P) 85.8 MW OWNER PEAX (WMECO) 259.8 MW TOTAL OF PEAK LOADS 345.6 MW NON-OWNER PERCENTAGE 24.83% 50% OF TOTAL ALLOCATOR X .5 NET LOAD ALLOCATOR 12.41% FEEDER POSITIONS: NON-OWNER FEEDERS (CL&P) 2.0 OWNER FEEDERS (WMECO) 6.0 TOTAL OF FEEDER POSITIONS 8.0 NON-OWNER PERCENTAGE 25.00% 50% OF TOTAL ALLOCATOR X .5 NET LOAD ALLOCATOR 12.50% TOTAL NON-OWNER ALLOCATOR (CL&P) 24.91% ALLOCATED PER APPENDIX I SECTION III EXHIBIT 1 TO APPENDIX I LOCAL FACILITIES SILVER ST. SUBSTATION 1984 CHARGES SOLE USE SOLE USE JOINT USE NON-OWNER (CL&P) OWNER (WMECO) INVESTMENT BASE: NON-DEPRECIABLE LAND $ 0 N/A 0 ALLOW FOR WKNG CAP: MAT. & SUPPLIES 5,884 N/A 1,973 WKNG CAP ALLOW 6,592 N/A 2,258 TOTAL ALLOWANCE 12,476 N/A 4,231 TOTAL NON-DEPRECIABLE 12,476 N/A 4,231 DEPRECIABLE INVESTMENT 583,085 N/A 195,535 ACCUMULATED DEPRECIATION (194,276) N/A (65,328) ACCUM DEFERRED INC TAXES 0 N/A 0 NET INVESTMENT $ 401,285 N/A 134,438 ANNUAL CARRYING CHARGES: OPER. AND MAINT. EXPENSE $ 37,670 N/A 12,903 ADMIN. & GEN. EXPENSE 15,068 N/A 5,161 DEPRECIATION EXPENSE 19,239 N/A 6,480 PROPERTY TAX EXPENSE 8,336 N/A 2,796 INVESTMENT RETURN 48,355 N/A 16,200 INCOME TAX EXPENSE 30,056 N/A 10,098 INVESTMENT TAX CREDIT (1,540) N/A (349) OTHER TAX EXPENSE 0 N/A 0 TOTAL CARRYING CHARGES $ 157,184 N/A 53,289 ALLOCATED % TO NON-OWNER * 9.77% TOTAL CARRYING CHARGE TO NON-OWNER (CL&P) $ 15,357 * SEE PAGE 11 OF EXHIBIT 1 TO APPENDIX I EXHIBIT 1 TO APPENDIX I LOCAL FACILITIES SILVER ST. SUBSTATION 1984 INVESTMENTS SOLE USE SOLE USE ITEM JOINT USE NON-OWNER (CL&P) OWNER (WMECO) TOTAL STATION LAND INVEST. $ 0 N/A 0 "PTF" LAND INVEST. 0 N/A 0 "NUG&T" LAND INVEST. 0 N/A 0 LOCAL FACIL. LAND INVEST. $ 0 N/A 0 TOTAL STATION DEPR. INVEST. $ 583,085 N/A 195,535 "PTF" DEPRECIABLE INVEST. 0 N/A 0 "NUG&T" DEPRECIABLE INVEST. 0 N/A 0 LOCAL FACIL. DEPR. INVEST. $ 583,085 N/A 195,535 LOCAL FACIL. TOTAL INVEST. $ 583,085 N/A 195,535 EXHIBIT 1 TO APPENDIX I LOCAL FACILITIES SILVER ST. SUBSTATION 1984 ALLOCATORS LOAD PERCENTAGES: NON-OWNER PEAK (CL&P) 38.4 MW OWNER PEAX (WMECO) 304.4 MW TOTAL OF PEAK LOADS 342.8 MW NON-OWNER PERCENTAGE 11.20% 50% OF TOTAL ALLOCATOR X .5 NET LOAD ALLOCATOR 5.60% FEEDER POSITIONS: NON-OWNER FEEDERS (CL&P) 0.5 * OWNER FEEDERS (WMECO) 5.5 * TOTAL OF FEEDER POSITIONS 6.0 NON-OWNER PERCENTAGE 8.33% 50% OF TOTAL ALLOCATOR X .5 NET LOAD ALLOCATOR 4.17% TOTAL NON-OWNER ALLOCATOR (CL&P) 9.77% ALLOCATED PER APPENDIX I SECTION III * 1 WMECO FEEDER TAPPED IN THE FIELD EXHIBIT 1 TO APPENDIX I LOCAL FACILITIES SOUTHWICK SUBSTATION 1984 CHARGES SOLE USE SOLE USE JOINT USE NON-OWNER (CL&P) OWNER (WMECO) INVESTMENT BASE: NON-DEPRECIABLE LAND $ 7,036 1,319 440 ALLOW FOR WKNG CAP: MAT. & SUPPLIES 7,127 829 257 WKNG CAP ALLOW 7,923 936 288 TOTAL ALLOWANCE 15,050 1,765 545 TOTAL NON-DEPRECIABLE 22,086 3,084 985 DEPRECIABLE INVESTMENT 706,305 82,153 25,442 ACCUMULATED DEPRECIATION (312,397) (47,011) (14,013) ACCUM DEFERRED INC TAXES 0 0 0 NET INVESTMENT $ 415,994 38,226 12,414 ANNUAL CARRYING CHARGES: OPER. AND MAINT. EXPENSE $ 45,274 5,351 1,648 ADMIN. & GEN. EXPENSE 18,110 2,140 659 DEPRECIATION EXPENSE 23,267 2,715 840 PROPERTY TAX EXPENSE 10,635 1,244 386 INVESTMENT RETURN 50,127 4,606 1,496 INCOME TAX EXPENSE 31,435 2,962 957 INVESTMENT TAX CREDIT (1,128) (17) (14) OTHER TAX EXPENSE 0 0 0 TOTAL CARRYING CHARGES $ 177,720 19,001 5,972 ALLOCATED % TO NON-OWNER * 40.59% 100.00% CARRYING CHARGE ALLOCATION $ 72,137 19,001 TOTAL CARRYING CHARGE TO NON-OWNER (CL&P) 91,138 * SEE PAGE 15 OF EXHIBIT 1 TO APPENDIX I EXHIBIT 1 TO APPENDIX I LOCAL FACILITIES SOUTHWICK SUBSTATION 1984 INVESTMENT SOLE USE SOLE USE ITEM JOINT USE NON-OWNER (CL&P) OWNER (WMECO) TOTAL STATION LAND INVEST. $ 7,036 1,319 440 "PTF" LAND INVEST. 0 0 0 "NUG&T" LAND INVEST. 0 0 0 LOCAL FACIL. LAND INVEST. $ 7,036 1,319 440 TOTAL STATION DEPR. INVEST. $ 706,305 82,153 25,442 "PTF" DEPRECIABLE INVEST. 0 0 0 "NUG&T" DEPRECIABLE INVEST. 0 0 0 LOCAL FACIL. DEPR. INVEST. $ 706,305 82,153 25,442 LOCAL FACIL. TOTAL INVEST. $ 713,341 83,472 25,882 EXHIBIT 1 TO APPENDIX I LOCAL FACILITIES SOUTHWICK SUBSTATION 1984 ALLOCATORS LOAD PERCENTAGES: NON-OWNER PEAK (CL&P) 60.8 MW OWNER PEAX (WMECO) 134.2 MW TOTAL OF PEAK LOADS 195.0 MW NON-OWNER PERCENTAGE 31.18% 50% OF TOTAL ALLOCATOR X .5 NET LOAD ALLOCATOR 15.59% FEEDER POSITIONS: NON-OWNER FEEDERS (CL&P) 1.5 * OWNER FEEDERS (WMECO) 1.5 * TOTAL OF FEEDER POSITIONS 3.0 NON-OWNER PERCENTAGE 50.00% 50% OF TOTAL ALLOCATOR X .5 NET LOAD ALLOCATOR 25.00% TOTAL NON-OWNER ALLOCATOR (CL&P) 40.59% ALLOCATED PER APPENDIX I SECTION III * 1 WMECO FEEDER TAPPED IN THE FIELD EXHIBIT 1 TO APPENDIX I LOCAL FACILITIES SOUTHWICK TRANSMISSION 1984 CHARGES CL&P (OWNER) INVESTMENT BASE: NON-DEPRECIABLE LAND $ 223,363 ALLOW FOR WORKING CAPITAL: MATERIALS & SUPPLIES 3,556 WORKING CAPITAL ALLOWANCE 1,506 TOTAL ALLOWANCE 5,062 TOTAL NON-DEPRECIABLE 228,425 DEPRECIABLE INVESTMENT 352,434 ACCUMULATED DEPRECIATION (122,698) ACCUM DEFERRED INC TAXES 0 NET INVESTMENT $ 458,161 ANNUAL CARRYING CHARGES: OPER. AND MAINT. EXPENSE $ 8,607 ADMIN. & GEN. EXPENSE 3,443 DEPRECIATION EXPENSE 11,253 PROPERTY TAX EXPENSE 4,300 INVESTMENT RETURN 55,208 INCOME TAX EXPENSE 32,979 INVESTMENT TAX CREDIT (7) OTHER TAX EXPENSE 0 TOTAL CARRYING CHARGES $ 115,783 ALLOCATED % TO NON-OWNER (WMECO) * 0.1624 WMECO OWES TO CL&P $ 18,803 * SEE PAGE 20 OF EXHIBIT 1 TO APPENDIX I EXHIBIT 1 TO APPENDIX I LOCAL FACILITIES SOUTHWICK TRANSMISSION 1984 CHARGES WMECO (OWNER) INVESTMENT BASE: NON-DEPRECIABLE LAND $ 135,280 ALLOW FOR WORKING CAPITAL: MATERIALS & SUPPLIES 2,890 WORKING CAPITAL ALLOWANCE 1,224 TOTAL ALLOWANCE 4,114 TOTAL NON-DEPRECIABLE 139,394 DEPRECIABLE INVESTMENT 286,424 ACCUMULATED DEPRECIATION (99,094) ACCUM DEFERRED INC TAXES 0 NET INVESTMENT $ 326,724 ANNUAL CARRYING CHARGES: OPER. AND MAINT. EXPENSE $ 6,995 ADMIN. & GEN. EXPENSE 2,798 DEPRECIATION EXPENSE 8,981 PROPERTY TAX EXPENSE 6,725 INVESTMENT RETURN 39,370 INCOME TAX EXPENSE 23,429 INVESTMENT TAX CREDIT 0 OTHER TAX EXPENSE 0 TOTAL CARRYING CHARGES $ 88,298 ALLOCATED % TO NON-OWNER (CL&P) * 0.8376 CL&P OWES TO WMECO $ 73,959 * SEE PAGE 20 OF EXHIBIT 1 TO APPENDIX I EXHIBIT 1 TO APPENDIX I LOCAL FACILITIES TRANSMISSION 1984 INVESTMENT TRANSMISSION TRANSMISSION LINE SOUTHWICK LINE SOUTHWICK ITEM CL&P (OWNER) WMECO (OWNER) LOCAL TRANS. LAND INVEST. $ 223,363 $ 135,280 "PTF" LAND INVEST. 0 0 "NUG&T" LAND INVEST. 0 0 LOCAL TRANS. LAND INVEST. $ 223,363 $ 135,280 LOCAL TRANS. DEPRE. INVEST. $ 352,434 $ 286,424 "PTF" DEPRECIABLE INVEST. 0 0 "NUG&T" DEPRECIABLE INVEST. 0 0 LOCAL TRANS. DEPR. INVEST. $ 352,434 $ 286,424 LOCAL FACIL. TOTAL INVEST. $ 575,797 $ 421,704 EXHIBIT 1 TO APPENDIX I LOCAL FACILITIES SOUTHWICK TRANSMISSION 1984 ALLOCATORS CL&P (OWNERS) LOAD PERCENTAGES: NON-OWNER PEAK (WMECO) 7873.0 * MW OWNER PEAX (CL&P) 40594.7 * MW TOTAL OF PEAK LOADS 48467.7 MW NON-OWNER PERCENTAGE 16.24% SOUTHWICK TRANSMISSION 1984 ALLOCATORS WMECO (OWNERS) LOAD PERCENTAGES: NON-OWNER PEAK (CL&P) 40594.7 * MW OWNER PEAX (WMECO) 7873.0 * MW TOTAL OF PEAK LOADS 48467.7 MW NON-OWNER PERCENTAGE 83.76% ALLOCATED PER APPENDIX I SECTION III * SUM OF THE MONTHLY RATCHETED PEAK LOADS PER NUG&T EXHIBIT 1 TO APPENDIX I LOCAL FACILITIES FRANCONIA DISTRIBUTION 1984 CHARGES COMMON INVESTMENT BASE: NON-DEPRECIABLE LAND $ 0 ALLOW FOR WORKING CAPITAL: MATERIALS & SUPPLIES 78 WORKING CAPITAL ALLOWANCE 166 TOTAL ALLOWANCE 244 TOTAL NON-DEPRECIABLE 244 DEPRECIABLE INVESTMENT 7,771 ACCUMULATED DEPRECIATION (2,767) ACCUM DEFERRED INC TAXES 0 NET INVESTMENT $ 5,248 ANNUAL CARRYING CHARGES: OPER. AND MAINT. EXPENSE $ 949 ADMIN. & GEN. EXPENSE 380 DEPRECIATION EXPENSE 341 PROPERTY TAX EXPENSE 190 INVESTMENT RETURN 632 INCOME TAX EXPENSE 477 INVESTMENT TAX CREDIT (3) OTHER TAX EXPENSE 0 TOTAL CARRYING CHARGES $ 2,966 ADJUSTMENT PERCENTAGE * 0.1875 CL&P OWES TO WMECO $ 556 * SEE PAGE 26 OF EXHIBIT 1 TO APPENDIX I EXHIBIT 1 TO APPENDIX I LOCAL FACILITIES FRANCONIA DISTRIBUTION 1984 CHARGES COMMON INVESTMENT BASE: NON-DEPRECIABLE LAND $ 0 ALLOW FOR WORKING CAPITAL: MATERIALS & SUPPLIES 267 WORKING CAPITAL ALLOWANCE 566 TOTAL ALLOWANCE 833 TOTAL NON-DEPRECIABLE 833 DEPRECIABLE INVESTMENT 26,455 ACCUMULATED DEPRECIATION (7,193) ACCUM DEFERRED INC TAXES 0 NET INVESTMENT $ 20,095 ANNUAL CARRYING CHARGES: OPER. AND MAINT. EXPENSE $ 3,232 ADMIN. & GEN. EXPENSE 1,293 DEPRECIATION EXPENSE 929 PROPERTY TAX EXPENSE 648 INVESTMENT RETURN 2,421 INCOME TAX EXPENSE 137 INVESTMENT TAX CREDIT (26) OTHER TAX EXPENSE 0 TOTAL CARRYING CHARGES $ 8,634 ADJUSTMENT PERCENTAGE * 0.7500 CL&P OWES TO WMECO $ 6,476 * SEE PAGE 26 OF EXHIBIT 1 TO APPENDIX I EXHIBIT 1 TO APPENDIX I LOCAL FACILITIES SILVER STREET DISTRIBUTION 1984 CHARGES COMMON INVESTMENT BASE: NON-DEPRECIABLE LAND $ 0 ALLOW FOR WORKING CAPITAL: MATERIALS & SUPPLIES 361 WORKING CAPITAL ALLOWANCE 765 TOTAL ALLOWANCE 1,126 TOTAL NON-DEPRECIABLE 1,126 DEPRECIABLE INVESTMENT 35,781 ACCUMULATED DEPRECIATION (11,404) ACCUM DEFERRED INC TAXES 0 NET INVESTMENT $ 25,503 ANNUAL CARRYING CHARGES: OPER. AND MAINT. EXPENSE $ 4,371 ADMIN. & GEN. EXPENSE 1,748 DEPRECIATION EXPENSE 1,432 PROPERTY TAX EXPENSE 876 INVESTMENT RETURN 3,073 INCOME TAX EXPENSE 357 INVESTMENT TAX CREDIT (74) OTHER TAX EXPENSE 0 TOTAL CARRYING CHARGES $ 11,783 ADJUSTMENT PERCENTAGE * 0.0833 CL&P OWES TO WMECO $ 982 * SEE PAGE 27 OF EXHIBIT 1 TO APPENDIX I EXHIBIT 1 TO APPENDIX I LOCAL FACILITIES SOUTHWICK DISTRIBUTION 1984 CHARGES COMMON INVESTMENT BASE: NON-DEPRECIABLE LAND $ 0 ALLOW FOR WORKING CAPITAL: MATERIALS & SUPPLIES 87 WORKING CAPITAL ALLOWANCE 185 TOTAL ALLOWANCE 272 TOTAL NON-DEPRECIABLE 272 DEPRECIABLE INVESTMENT 8,653 ACCUMULATED DEPRECIATION (3,144) ACCUM DEFERRED INC TAXES 0 NET INVESTMENT $ 5,781 ANNUAL CARRYING CHARGES: OPER. AND MAINT. EXPENSE $ 1,057 ADMIN. & GEN. EXPENSE 423 DEPRECIATION EXPENSE 387 PROPERTY TAX EXPENSE 212 INVESTMENT RETURN 697 INCOME TAX EXPENSE 126 INVESTMENT TAX CREDIT (37) OTHER TAX EXPENSE 0 TOTAL CARRYING CHARGES $ 2,865 ADJUSTMENT PERCENTAGE * 0.5000 CL&P OWES TO WMECO $ 1,432 * SEE PAGE 27 OF EXHIBIT 1 TO APPENDIX I EXHIBIT 1 TO APPENDIX I LOCAL FACILITIES DISTRIBUTION 1984 INVESTMENT Distrib. Distrib. Distrib. Distrib. Franconia Franconia Silver St Southwick ITEM Common Common Common Common TOTAL STATION LAND INVEST. $ 0 0 0 0 "PTF" LAND INVEST. 0 0 0 0 "NUG&T" LAND INVEST. 0 0 0 0 LOCAL FACIL. LAND INVEST. $ 0 0 0 0 TOTAL STATION DEPRE. INVEST. $ 7,771 26,455 35,781 8,653 "PTF" DEPRECIABLE INVEST. 0 0 0 0 "NUG&T" DEPRECIABLE INVEST. 0 0 0 0 LOCAL FACIL. DEPR. INVEST. $ 7,771 26,455 35,781 8,653 LOCAL FACIL. TOTAL INVEST. $ 7,771 26,455 35,781 8,653 EXHIBIT 1 TO APPENDIX I LOCAL FACILITIES FRANCONIA DISTRIBUTION 1984 ALLOCATORS COMMON LOAD PERCENTAGES: NON-OWNER PEAK (CL&P) 1.5 * OWNER PEAX (WMECO) 6.5 * TOTAL OF PEAK LOADS 8.0 NON-OWNER PERCENTAGE (CL&P) 18.75% FRANCONIA DISTRIBUTION 1984 ALLOCATORS CL&P LOAD PERCENTAGES: NON-OWNER PEAK (CL&P) 5.1 * OWNER PEAX (WMECO) 0.5 * TOTAL OF PEAK LOADS 2.0 NON-OWNER PERCENTAGE (CL&P) 75.00% ALLOCATED PER APPENDIX I SECTION III * 1 WMECO FEEDER TAPPED IN THE FIELD EXHIBIT 1 TO APPENDIX I LOCAL FACILITIES SILVER STREET DISTRIBUTION 1984 ALLOCATORS COMMON LOAD PERCENTAGES: NON-OWNER PEAK (CL&P) 0.5 * OWNER PEAX (WMECO) 5.5 * TOTAL OF PEAK LOADS 6.0 NON-OWNER PERCENTAGE (CL&P) 8.33% SOUTHWICK DISTRIBUTION 1984 ALLOCATORS COMMON LOAD PERCENTAGES: NON-OWNER PEAK (CL&P) 1.5 * OWNER PEAX (WMECO) 1.5 * TOTAL OF PEAK LOADS 3.0 NON-OWNER PERCENTAGE (CL&P) 50.00% EX-10.26 15 THE PRUDENTIAL INSURANCE COMPANY OF AMERICA SIMULATOR FINANCING LEASE AGREEMENT Simulator Financing Lease Agreement (the "Agreement") dated as of the 2nd day of May, 1985, by and between THE PRUDENTIAL INSURANCE COMPANY OF AMERICA, a New Jersey corporation, as lessor and secured party (herein called "Lessor") and NORTHEAST NUCLEAR ENERGY COMPANY, a Connecticut corporation, as lessee and debtor (herein called "Lessee"). In consideration of the mutual covenants contained herein, the parties covenant and agree as follows: 1. Definitions. As herein used: (a) "Acquisition Cost" of the Unit (as hereinafter defined) or Units or any part thereof is an amount equal to the sum of the vendor's invoice price (less any discounts or credits actually utilized by Lessor), any progress payments, any costs of freight, packing, insurance, handling, storage, shipment and delivery, any sales, use and other taxes, capitalized overheads, labor and interest, allowance for funds used during construction and reasonable consultants and attorneys fees, and such other costs as may be agreed to by Lessor and Lessee in writing. (b) "Applicable Percentage" is equal to the sum of (i) 1.50% plus (ii) either (x) the "C/P Rate" or (y) the "Fixed Rate". The "C/P Rate" for any month shall mean the yield adjusted rate (meaning the nominal rate increased by the cost of any discount) charged to Prudential Funding Corporation, a subsidiary of Lessor, on 30-day, dealer-placed commercial paper issued by Prudential Funding Corporation ("Commercial Paper") on the fifteenth day of such month or, if such fifteenth day is not a Business Day, on the next succeeding Business Day (such Business Day being herein called the "Rate Day"), or if Commercial Paper has not been issued on the Rate Day, the rate quoted for Commercial Paper by the commercial paper dealer on the Rate Day. If, on any Rate Day, more than one rate is charged or quoted for Commercial Paper, the last of such charged or quoted rates, whichever is applicable, shall be used. Upon execution of this Agreement, Lessor shall notify Lessee in writing of the then C/P Rate. Thereafter, Lessor shall notify Lessee in writing of an) change in such C/P Rate. "Fixed Rate" shall mean the yield on 10 year Treasury Notes (based on the bid price on the "Fixed Rate Day" (as hereinafter defined)) as reported by "Telerate - the Financial Information Network," published by Telerate Systems, Incorporated, or its successor company and provided to Lessee by Lessor. The "Fixed Rate Day" shall be the Business Day or Business Days on or before June 24, 1986 on which Lessee shall request verbally, Lessor shall provide verbally, and Lessee shall accept verbally and confirm in writing, the Fixed Rate for each Interim Leasing Record (as hereinafter defined) relating to the Acquisition Cost of each Unit or portion thereof as estimated by the Lessee (the "Fixed Rate Amount"); provided, however, Lessee may request no more than two Fixed Rate Amounts for all portions of each Unit; provided further, however, if Lessee does not request and accept a Fixed Rate for all such portions of a Unit prior to June 24, 1986, the Fixed Rate Day for all such portions of such Unit shall be June 24, 1986. At the time Lessee requests the Fixed Rate, Lessee shall also notify Lessor, and confirm in writing, as to the date on which such Fixed Rate shall become applicable to the lease of each portion of each Unit ("Fixed Rate Effective Date"); provided, however, the Fixed Rate Effective Date may not be a date earlier than four Business Days following the Fixed Rate Day nor, in any event, later than June 30, 1986. (c) "Basic Lease Term" shall have the meaning set forth in Section 5 hereof. (d) "Business Day" means every day except Saturday, Sunday any other day which in New York, New York or Hartford, Connecticut shall be a legal holiday and any day on which banking institutions in New York, New York or Hartford, Connecticut are authorized by law to close. (e) "Equipment" means all or any portion of the two nuclear power plant control room simulator systems (hereinafter referred to each in its entirety as "Unit" or "Units"), for the Millstone Nuclear Power Station, Units No. 1 and 2, each evidenced by an Individual Leasing Record (as hereinafter defined) and all related materials, parts and accessions leased or to be leased by Lessor to Lessee as provided herein including any replacements of such related materials, parts and accessions, approved in writing by Lessor and Lessee. (f) "Individual Leasing Record" is a form signed by Lessor and Lessee to record the leasing of each Unit hereunder. The first Individual Leasing Record for each Unit shall be dated the date of the acceptance by Lessee of the lease hereunder of the Unit or Units specified in such Individual Leasing Record. Such date shall constitute the effective beginning date as of which such Unit is subject to the terms and provisions of this Agreement. The signature of Lessee on an Individual Leasing Record shall constitute acknowledgment by Lessee (x) that the Equipment specified in such Individual Leasing Record has been delivered to Lessee in good condition and has been accepted for lease hereunder by Lessee as of the date of such Individual Leasing Record, and (y) that the Equipment specified in such Individual Leasing Record is subject to all of the covenants, terms and conditions of this Agreement. An Individual Leasing Record shall give a full description of the Equipment specified therein, the Acquisition Cost, Rent (as hereinafter defined), location and such other details with respect to the Equipment specified therein as the parties may agree. An Individual Leasing Record may be either an "Interim Leasing Record" or a "Final Leasing Record" (as hereinafter defined), as the case may be. (i) An "Interim Leasing Record" is a form of Individual Leasing Record signed by Lessor and Lessee to record the leasing of each Unit during any period that such Unit or a portion thereof is subject to the provisions of this Agreement prior to a "Lease Commencement Date" (as hereinafter defined). Each entry for a Unit on an Interim Leasing Record which reflects a payment of Acquisition Cost shall be dated the date Lessee authorized payment by Lessor with respect to the Acquisition Cost of such Unit specified in such Interim Leasing Record. During the period Equipment is subject to the provisions hereof prior to a Lease Commencement Date, if Lessor shall make any further payment or payments with respect to such Equipment, a supplemental entry shall be made on an Interim Leasing Record dated the date Lessee authorizes Lessor to make such further payments to record the revised Acquisition Cost (after giving effect to any such payment), the revised Rent, any change in location and such additional details as the parties may agree; provided, however, when the Rent on an Interim Leasing Record is based on a Fixed Rate, subsequent to an initial non-funding Individual Leasing Record, there may not be more than two such Interim Leasing Records for each Unit and after such Interim Leasing Records have been delivered to Lessor, such Interim Leasing Records may no longer be revised. An Interim Leasing Record shall be substantially in the form as set forth on Exhibit A hereto. (ii) A "Final Leasing Record" is a form of Individual Leasing Record signed by Lessor and Lessee to record the leasing of each Unit during any period that such Unit is leased hereunder as of a Lease Commencement Date. A Final Leasing Record shall be dated the Lease Commencement Date and shall be delivered to Lessor promptly following the Lease Commencement Date of such Unit. In addition to the provisions of this Section 1(f) concerning the effect of the signature of Lessee on an Individual Leasing Record, such signature on a Final Leasing Record shall constitute acknowledgment by Lessee that the Equipment specified in such Final Leasing Record requires the addition of no further Acquisition Cost thereto. A Final Leasing Record shall be substantially in the form as set forth on Exhibit B hereto. (g) "Interim Lease Term" shall mean the period beginning after the date hereof commencing with the effective date of an Interim Leasing Record of a Unit and ending on the day immediately prior to the Lease Commencement Date for such Unit. (h) "Lease Commencement Date" for a Unit shall mean a "Rent Payment Date" (as hereinafter defined in Section 6) designated in writing by Lessee to Lessor which date shall be on or prior to July 1, 1986; provided, however, such date must be concurrent with or subsequent to the Fixed Rate Effective Dates for all portions of such Unit. Each such Lease Commencement Date shall constitute the beginning of the Basic Lease Term of such Unit. (i) "Renewal Lease Term" shall have the meaning set forth in Section 5 hereof. (j) "Rent" shall mean either "Interim Rent" or "Basic Rent": (i) "Interim Rent" for any month of this Agreement during an Interim Lease Term for Equipment with respect to which Lessor has made a payment of Acquisition Cost shall be an amount computed by multiplying the following: (a) the Acquisition Cost of such Equipment, by (b) a fraction, the numerator of which is equal to the number of days in such month during which such Equipment is covered by an Interim Leasing Record, and the denominator of which is 360, by (c) the Applicable Percentage. (ii) "Basic Rent" for a Unit for each full month during the Basic Lease Term and Renewal Lease Terms shall be made in level payments, monthly in arrears, and the present value of such Rent payments (each discounted at a rate equal to the sum of (x) the Fixed Rates for such Unit or portion thereof, and (y) 1.50%, from the Rent Payment Date (as hereinafter defined in Section 6) thereof to the Lease Commencement Date) over the Basic Lease Term and Renewal Lease Terms of such Unit, as of the Lease Commencement Date, shall be equal to the Acquisition Cost of such Unit, as such Basic Rent is set forth on the Exhibit attached to each Final Leasing Record substantially in the form of Exhibit C attached hereto. (k) "Stipulated Termination Value" for each Unit for any full month during the Basic Lease Term and the Renewal Lease Terms of such Unit shall be a dollar amount determined by multiplying the Unamortized Cost of such Unit by the "Termination Rate" (as hereinafter defined). (l) "Termination Rate" for each Unit or portion thereof shall be a rate equal to the sum of (x) the applicable Fixed Rate for such Unit or portion thereof, and (y) 101.5%. The Termination Rate shall decline ratably annually to 100% from the beginning of the First Renewal Lease Term through the end of the 96th Renewal Lease Term as set forth on the Exhibit attached to each Final Leasing Record substantially in the form of Exhibit C attached hereto. (m) "Unamortized Cost" for each Unit shall be the amount set forth for each month of the Basic Lease Term and the Renewal Lease Terms on the Exhibit attached to each Final Leasing Record substantially in the form of Exhibit C attached hereto. (n) "Delayed Takedown Fee" for all or any portion of a Unit shall be an amount computed by multiplying the following: (A) the Fixed Rate Amount of such Unit or portion thereof, by (B) a fraction having a numerator equal to the number of days from the applicable Fixed Rate Day for such Unit or portion thereof to but not including the applicable Fixed Rate Effective Date for such Unit or portion thereof and a denominator of 360, by (C) 1/2 of 1%. (o) "Cancellation Fee" shall be an amount computed by multiplying (i) 1/2 of 1% by (ii) the "Deficiency". The "Deficiency" is an amount equal to the amount by which the aggregate of the Fixed Rate Amounts of both Units exceeds the sum of (x) the aggregate of the Acquisition Costs shown on the Final Leasing Records for both Units and (y) $500,000. (p) Notwithstanding subsection (j) above, when the Unamortized Cost of a Unit has been reduced to zero, the lease term of such Unit shall terminate, and Lessor shall release to Lessee all of Lessor's right, title and security interest in such Unit and execute such documents as Lessee may reasonably request to evidence such release. 2. This Agreement is Intended as Security. Lessor and Lessee declare and agree that this Agreement is intended as security. Subject to the terms, conditions and limitations contained herein, Lessor shall make available funds for the acquisition of Equipment. Title to the Equipment shall be retained or reserved by Lessor for the purpose of securing payment by Lessee to Lessor of Rent, Unamortized Cost, and other amounts as provided herein and to secure performance by Lessee of the other terms and conditions hereof. Lessee shall promptly execute and deliver to Lessor such documents as Lessor shall deem necessary to further evidence Lessor's security interests hereunder and in the Equipment. Such documents, or evidence thereof, shall be filed and recorded as provided in Section 7. Lessor and Lessee agree that the Lessor holds legal title to the Equipment only to evidence Lessor's security interest therein and the Equipment is and shall be treated as, owned by Lessee for all other purposes. 3. Agreement for Lease of Equipment. Subject to satisfaction of all terms and conditions of this Agreement, including, without limitation, the conditions set forth in Section 20 hereof, Lessor commits to lease to Lessee and Lessee commits to lease from Lessor the Equipment, provided that Lessee is not in default hereunder, and further provided that the aggregate total Acquisition Cost of Equipment leased hereunder shall not exceed $23,000,000 or such other amount as Lessor and Lessee may agree in writing. Lessor and Lessee shall evidence their agreement to lease a specific Unit under this Agreement by executing and promptly upon execution delivering to each other an Individual Leasing Record covering such Unit. 4. Delivery. Lessor shall not be liable to Lessee for any failure or delay in obtaining Equipment or making delivery thereof. Upon acceptance for lease (as provided in Section 1(f) hereof) of Equipment by Lessee and receipt by Lessor of vendor's invoice approved by Lessee or Lessee's invoice signed by Lessee for such Equipment together with an Individual Leasing Record with respect to such Equipment duly executed by Lessee, Lessor shall pay such invoice for such Equipment. If the amount paid to vendors by Lessor is less than the Acquisition Cost of such Equipment, to the extent that costs includable in the Acquisition Cost of Equipment have been paid, incurred, or accrued by Lessee, Lessor shall reimburse Lessee to the extent of such payment, incurrence or accrual made by Lessee. Lessee shall (i) pay all costs and expenses of freight, packing, insurance, handling, storage, shipment and delivery of the Equipment to the extent that the same have not been included in Acquisition Cost and (ii) at its own cost and expense, furnish such labor, equipment and other facilities and supplies, if any, as may be required to install and erect the Equipment to the extent that the cost and expense thereof have not been included in the Acquisition Cost. Such installation and erection shall be in accordance, in all material respects, with the specifications and requirements of each vendor as set forth in the contracts between Lessee and such vendors, as the same may have been or may hereafter be amended. AS BETWEEN LESSOR AND LESSEE, ACCEPTANCE FOR LEASE OF THE EQUIPMENT (AS PROVIDED IN SECTION 1(f) HEREOF) SHALL CONSTITUTE LESSEE'S ACKNOWLEDGEMENT AND AGREEMENT THAT LESSEE HAS FULLY INSPECTED SUCH EQUIPMENT, THAT THE EQUIPMENT IS IN GOOD ORDER AND CONDITION AND IS OF THE MANUFACTURE, DESIGN, SPECIFICATIONS AND CAPACITY SELECTED BY LESSEE, THAT LESSEE IS SATISFIED THAT THE SAME IS SUITABLE FOR ITS PURPOSE AND THAT LESSOR IS NOT A MANUFACTURER OR ENGAGED IN THE SALE OR DISTRIBUTION OF EQUIPMENT, AND HAS NOT MADE AND DOES NOT HEREBY MAKE ANY REPRESENTATION, WARRANTY OR COVENANT WITH RESPECT TO MERCHANTABILITY, CONDITION, QUALITY, DURABILITY OR SUITABILITY OF THE EQUIPMENT IN ANY RESPECT OR IN CONNECTION WITH, OR FOR THE PURPOSES OR USES OF LESSEE, OR ANY OTHER REPRESENTATION, WARRANTY OR COVENANT OF ANY KIND OR CHARACTER, EXPRESS OR IMPLIED, WITH RESPECT THERETO. 5. Basic Lease Term; Renewal Lease Terms. The Basic Lease Term for each Unit shall become effective on the Lease Commencement Date as provided in Section 1(h) hereof. The Basic Lease Term of each Unit shall be for a period beginning with the Lease Commencement Date and ending five years thereafter. Following the Basic Lease Term with respect to a Unit, the lease thereof shall be extended from month to month (the "Renewal Lease Terms") until terminated as provided in Section 1(p), 11, 12(c), 14, 15 or 18 hereof, provided, however, the last Renewal Lease Term shall end no later than fifteen (15) years from the Lease Commencement Date for such Unit. Notwithstanding the foregoing, the provisions of Section 10 hereof and the first sentence of Section 12 hereof shall apply as between Lessor and Lessee with respect to any Equipment from the time such Equipment is ordered by Lessor pursuant to a request from Lessee. Notwithstanding any other provision of this Agreement to the contrary, Lessee shall not terminate the lease hereunder of Equipment for the purpose of refinancing such Equipment with funds borrowed at a rate which is less than the Applicable Percentage set forth in Section 1(b) hereof. 6. Rent and Other Payments. Lessee shall pay Rent monthly in arrears in such a manner that payment is received by Lessor on the first day of the month following the month for which such Rent is tue ("Rent Payment Date"). If any such Rent Payment Date is not a Business Day then payment shall be made on the next preceding Business Day. Lessor shall give Lessee written notice of the address to which all payments of Rent and other payments to be made hereunder shall be directed and all such payments shall be made by check and shall be deemed to have been received by Lessor when received in immediately available funds at such address. Without prejudice to the full exercise by Lessor of its rights under Section 13 and 14 hereof for failure of Lessee to pay Rent when due as provided above, to the extent legally enforceable Lessee shall promptly pay Lessor additional Rent with respect to all sums not paid by Lessee to Lessor as provided in this Agreement on or before the Rent Payment Date said additional Rent to be in an amount equal to such unpaid sums multiplied by (i) the Applicable Percentage referred to in Section 1(b) hereof and (ii) a fraction having a numerator equal to the number of days in the period from and including such Rent Payment Date and ending upon the date of payment thereof and a denominator of 360. Lessee shall also promptly pay to Lessor an amount equal to any expenses incurred by Lessor in collecting such unpaid sums. Lessee shall pay Lessor a Delayed Takedown Fee if the Fixed Rate Effective Date for all or any portion of a Unit occurs more than 90 days after the Fixed Rate Day for such Unit or portion thereof. Such Delay Takedown Fee shall be payable by Lessee on the Fixed Rate Effective Date for such Unit or portion thereof. Lessee shall pay Lessor a Cancellation Fee, if any, on the Lease Commencement Date of the second Unit leased hereunder; provided, however, if, notwithstanding Lessee's best efforts, any regulatory body having jurisdiction over Lessee or this Agreement denies approval of this Agreement within 90 days of a Fixed Rate Day, Lessee shall not be required to pay Lessor a Cancellation Fee or Delayed Takedown Fee on the Fixed Rate Amount pertaining to such Fixed Rate Day. 7. Restricted Use and Compliance with Laws So long as Lessee is not in default pursuant to Section 13 hereof, Lessee may use Equipment in the regular course of its business or the business of any subsidiary or affiliate of Lessee, and may permit others to use the same for any lawful purpose. Such use shall be confined to the United States. Lessee shall promptly and duly execute, deliver, file and record all such documents, statements, filings and registrations, and take such further actions as Lessor shall from time to time reasonably request in order to establish, perfect and maintain the rights and remedies created or intended to be created in favor of Lessor hereunder and Lessor's security interest in the Equipment as against Lessee or any third party in any applicable jurisdiction. Lessee may after notice in writing to Lessor and at Lessee's sole expense change the place of principal location of any Equipment. Notwithstanding the foregoing, no change of location shall be undertaken unless such Equipment shall be and remain subject to the security interest of Lessor, subject to this Agreement and until all legal requirements shall have been met or obtained and all necessary or advisable recordings, filings and registrations which Lessor shall reasonably request shall have been duly made in order to protect the validity and effectiveness of this Agreement. If Lessor reasonably so requests, Lessee shall advise Lessor in writing where all Equipment leased hereunder as of such date is principally located. Lessee shall not use any Equipment or allow the same to be used for any unlawful purpose. Lessee shall use every reasonable precaution to prevent loss or damage to Equipment and to prevent injury to third persons or property of third persons arising out of Equipment or the use thereof. Lessee shall cooperate fully with Lessor and all insurance companies providing insurance under Section 9 hereof in the investigation and defense of any claims and suits arising from the operation of Equipment. To the extent necessary to avoid any impairment of Lessor's rights and interests hereunder and to avoid any adverse affect on Lessee's ability to perform under this Agreement and the transactions contemplated hereby, Lessee shall comply and shall cause all persons operating Equipment to comply with all insurance policy conditions and with all statutes, decrees, ordinances and regulations regarding acquiring, titling, perfecting a security interest in, registering, leasing, insuring, using, operating and disposing of Equipment, and the licensing of operators thereof. Lessor or any authorized representative of Lessor may during reasonable business hours from time to time inspect Equipment and registration certificates, certificates of title and related documents covering Equipment wherever the same be located. Lessee shall not without prior written consent of Lessor sublease any Equipment nor permit, or suffer to exist, any lien or encumbrance on any Equipment other than those placed thereon by Lessor or by persons claiming only against Lessor and not against Lessee, nor shall Lessee assign any right or interest herein or in any Equipment, provided, however, that Lessee may sublet Equipment to any subsidiary or affiliate of Lessee, or to any contractor for use in performing work for Lessee, provided that such subletting shall in no way affect the obligations of Lessee hereunder, or the rights of Lessor hereunder, with respect to any Equipment. Lessee agrees to furnish Lessor, upon reasonable request, a certificate that all registration certificates and certificates of title required by applicable law and regulations, endorsed to show Lessor's security interest, have been obtained and are being held on behalf of Lessor. Lessee shall not without the prior permission of Lessor change or remove (or permit to be changed or removed or otherwise permit a decrease in the visibility of) any insignia or lettering which is on any Equipment at the time of delivery thereof or which is thereafter placed thereon indicating Lessor's security interest therein, and at any time during the term of this Agreement, upon request of Lessor, or if necessary or advisable under applicable law, Lessee shall affix to Equipment, in the place designated by Lessor (or, if no such place shall have been designated, in a prominent place), labels, plates or other markings as provided by Lessor indicating Lessor's security interest in the Equipment. 8. Maintenance, Improvement and Repair of Equipment. Upon request of Lessee, Lessor will assign or otherwise make available to Lessee all of its rights under any vendor's or manufacturer's warranty on Equipment. Lessee shall pay all costs, expenses, fees and charges incurred in connection with the use and operation of Equipment during the lease term thereof. Except as otherwise provided in Section 12 hereof, Lessee shall at all times, at its own expense, and subject to reasonable wear and tear, keep Equipment in good mechanical condition and repair. The foregoing undertaking to maintain Equipment in good repair shall apply regardless of the cause necessitating repair, and as between Lessor and Lessee all risks of damage to Equipment are assumed by Lessee. It is acknowledged by Lessor and Lessee that the Units to be leased hereunder will be modified, upgraded or enhanced from time to time in order that the Units may continue to replicate the actual operation of and reflect changes to the nuclear power plants whose control rooms they simulate. Lessee shall not make any material alterations to any Equipment without giving prior notice thereof to Lessor. Without the prior written consent of Lessor, Lessee shall not make any material alterations of Equipment which, in Lessee's reasonable judgment, will result in a reduction of value of such Equipment. At the same time that Lessee provides notice to Lessor of any material alterations, Lessee shall certify to Lessor that such alterations will not result in a reduction of the value of such Equipment. Any improvements or additions to any Equipment shall be deemed to constitute an accession to such Equipment, except that any addition to Equipment made by Lessee shall not be deemed to constitute an accession to such Equipment if it can be disconnected from Equipment without impairing the functioning of such Equipment or it's resale value excluding such addition. 9. Insurance. Lessee shall, at its own cost and expense, with respect to Equipment maintain insurance insuring the respective interests of Lessor and Lessee and covering (a) physical damage to Equipment and (b) liability for bodily injury and property damage resulting from the operation of Equipment. All such insurance shall be with reputable companies. Policies covering physical damage risks shall be an amount not less than the Unamortized Cost of Equipment. Policies covering bodily injury and property damage shall provide not less than $5,000,000 for injury to or death of one person and, subject to that limit for each person, a total liability of not less than $10,000,000 for all persons injured or killed in the same accident and shall also provide not less than $5,000,000 for damage, destruction and loss of use of property of third persons as a result of any one accident. Lessor shall be named as an additional insured and, with respect to physical damage coverage, a named loss payee in all insurance policies required under this Section. All such policies or certificates of insurance with respect thereto shall provide for thirty days prior written notice to Lessor of any cancellation or material alteration of such policies. Lessee shall furnish Lessor certificates or other evidence satisfactory to Lessor of compliance by Lessee with the provisions hereof, but Lessor shall be under no duty to examine such certificates or to advise Lessee in the event its insurance is not in compliance herewith. Lessee covenants that it will not use or operate or permit the use or operation of any Equipment at any time when the insurance required by this Section is not in force with respect to such Equipment. The foregoing coverage may be subject to such deductible amounts and Lessee may itself insure such portions of the foregoing coverage as Lessor may approve in writing. 10. Indemnity. Lessee agrees to indemnify and hold harmless Lessor and its representative, PruCapital Management, Inc., and their respective directors, officers and employees, and all companies, persons or firms controlling, controlled by or under common control with any of them (including, without limitation, PruCapital, Inc. and PRUCO, Inc.) against any and all claims, demands and liabilities of whatsoever nature and all costs and expenses (including but not limited to attorneys' fees) directly or indirectly relating to or in any way arising out of: (a) the ordering, delivery, acquisition, security interest in, title on acquisition, rejection, installation, possession, titling, retitling, registration, reregistration, custody by Lessee of title and registration documents, use, non-use, misuse, operation, transportation, inspection, repair, control or disposition of Equipment leased or to be leased hereunder, except to the extent that such costs are included in the Acquisition Cost of such Equipment within the dollar limit provided in Section 3 hereof (or within any change of such limit agreed to in writing by Lessor and Lessee) and except for any general administrative or overhead expenses of Lessor and of its representative; (b) all costs, charges, damages or expenses for royalties and claims and expenses of litigation arising out of or necessitated by the assertion of any claim or demand based upon any infringement or alleged infringement of any patent or other right, by or in respect of any Equipment, provided, however, that Lessor will make available to Lessee Lessor's rights under any similar indemnification from the manufacturer of equipment arising by contract, by quasi-contract or by operation of law; (c) all federal, state, county, municipal, foreign or other fees and taxes of whatsoever nature, including but not limited to license, qualification, franchise, sales, use, gross receipts, ad valorem, business, property (real or personal), excise, motor vehicle, and occupation fees and taxes, and penalties and interest thereon, to the extent not incurred solely as a result of Lessor's failure to make payments in a timely fashion, which failure is not due to the negligence or willful misconduct of the Lessee, whether assessed, levied against or payable by Lessor or otherwise, with respect to Equipment or the acquisition, purchase, security interest in, sale, rental, use, operation, control, ownership or disposition of Equipment or measured in any way by the value thereof or by the business of, investment in, financing of, security interest in, or ownership by Lessor with respect thereto, excepting only (i) net income taxes on the net income of Lessor determined substantially in the same manner but not necessarily at the same rates as net income is presently determined under the Federal Internal Revenue Code, and (ii) any sales, use, excise or other taxes included in Acquisition Cost of the Equipment; (d) any violation or alleged violation, of this Agreement by Lessee or of any contracts or agreements to which Lessee is a party or by which it is bound or any laws, rules, regulations, orders, writs, injunctions, decrees, consents, approvals, exemptions, authorizations, licenses and withholdings of objection, of any governmental or public body or authority and all other requirements having the force of law applicable at any time to Equipment or any action or transaction by Lessee with respect thereto or pursuant to this Agreement, or any representation or statement by Lessee in this Agreement or in any written instrument furnished by Lessee to Lessor in connection with this Agreement which is not true and correct in all material respects on the date as of which made and on the date Lessor makes any payment with respect to the Acquisition Cost of Equipment, or such representation or statement omits to state a material fact necessary in order to make such representation or statement not misleading in light of the circumstances under which it is made. Lessee shall forthwith upon demand reimburse Lessor for any sum or sums expended with respect to any of the foregoing, or shall pay such amounts directly upon request from Lessor. To the extent that Lessee in fact indemnifies Lessor under the indemnity provisions of this Agreement, Lessee shall be subrogated to Lessor's right in the affected transaction and shall have a right to determine the settlement of claims therein. Lessor shall not settle any claim for which Lessor is indemnified by Lessee hereunder without first notifying Lessee of such claim and providing Lessee with the opportunity to in fact indemnify Lessor. The foregoing indemnity shall not be affected by any termination of this Agreement as a whole or in respect of any unit of Equipment leased hereunder. 11. Termination of the Lease of Equipment. After the expiration of the Basic Lease Term or any Renewal Lease Term of any Unit, provided that Lessee is not in default hereunder, Lessee may notify Lessor in writing that it desires to terminate the lease term of such Unit; provided, however, that Lessee shall not terminate the lease term hereunder of any Unit for the purpose of refinancing such Unit with funds borrowed at a rate which is less than the Applicable Percentage set forth in Section 1(b) hereof. Within thirty (30) days after the date of such notice Lessee shall pay to Lessor an amount equal to the Stipulated Termination Value of such Unit. The obligation of Lessee to pay Rent for such Unit shall continue until the end of the month during which Lessor has received payment of the Stipulated Termination Value thereof. Upon receipt of such payment, Lessor shall release its title and security interest in such Unit and execute such documents as Lessee may reasonably request to evidence such release and upon such release the lease of such Unit shall terminate. 12. Loss of or Damage to Equipment. (a) Lessee hereby assumes all risk of loss or damage of Equipment however caused. No loss of or damage to any Equipment shall impair any obligation of Lessee under this Agreement, which shall continue in full force and effect. (b) In the event of damage of any kind whatsoever to any Equipment (unless the same is determined by Lessee to be damaged beyond repair) Lessee, at its own expense, shall place the same in good operating order, repair, condition and appearance. (c) If any Equipment is lost, stolen, destroyed, seized, confiscated, rendered unfit for use or damaged beyond repair, or if the use thereof by Lessee in its regular course of business is prevented by the act of any third person or persons, or any governmental instrumentality for a period exceeding ninety (90) days, or if such Equipment is attached (other than on a claim against Lessor but not Lessee) and the attachment is not removed within ninety (90) days, then in any such event, (a) Lessee shall notify Lessor in writing of such fact, (b) within sixty (60) days of such event Lessee shall pay to Lessor an amount equal to the difference between any proceeds of insurance collected by Lessor as a result of such loss, damage or destruction and the Unamortized Cost of such Equipment at the time of payment by Lessee and (c) the lease term of such Equipment shall continue until the end of the month during which Lessor receives payment from Lessee and shall thereupon terminate. 13. Events of Default. The following events of default by Lessee shall give rise to rights on the part of Lessor described in Section 14 hereof: (a) Default in the payment of Rent (or additional Rent or expenses of collection, as provided by Section 6 hereof), or any other amount payable by Lessee hereunder beyond the tenth (10th) day after such payment is due; or (b) Default in the payment or performance of any other liability, obligation or covenant of Lessee to Lessor and the continuance of such default for fifteen (15) days after written notice to Lessee sent by registered or certified mail; or (c) Lessee suspends or discontinues its business operations or becomes insolvent, as such term is defined in the Bankruptcy Reform Act, 11 USC para. 101 (26), (however such insolvency may be evidenced) or admits in writing insolvency or bankruptcy or its inability to pay its debts as they mature, makes an assignment for the benefit of creditors or applies for or consents to the appointment of a trustee or receiver for Lessee, or for the major part of its property; or (d) Bankruptcy, reorganization, liquidation or receivership proceedings for relief under any bankruptcy law or similar law for the relief of debtors are instituted by or against Lessee and, if instituted against Lessee, its consent thereto or the pendency of such proceedings for sixty (60) days; or (e) An event of default (the effect of which is to permit the holder or holders of any instrument, or a trustee or agent on behalf of such holder or holders, to cause the indebtedness evidenced by such instrument to become due prior to its stated maturity) shall occur under the provisions of any instrument evidencing indebtedness for borrowed money of Lessee (or under the provisions of any agreement pursuant to which such instrument was issued) or any obligation of Lessee for the payment of such indebtedness shall become or be declared to be due and payable prior to its stated maturity (other than at the option of Lessee) or shall not be paid when due, provided, in each such case, that such event could, in the reasonable judgment of Lessor, materially and adversely affect Lessee's ability to perform its obligations under this Agreement; or (f) Any representation or statement made by Lessee herein or in any written instrument furnished by Lessee to Lessor in connection herewith shall not be true and correct in all material respects on the date as of which made and on the date Lessor makes any payment with respect to the Acquisition Cost of Equipment, or any such representation or statement omits to state of material fact necessary in order to make such representation or statement not misleading in light of the circumstances under which it is made. 14. Rights of Lessor Upon Default of Lessee. (a) Upon the occurrence of any of the events of default described in Section 13, Lessor may in its discretion terminate the lease of any or all Equipment hereunder upon 5 days written notice to Lessee sent by registered or certified mail and upon such termination Lessee shall immediately pay to Lessor (i) all Rent and other amounts then due and payable under this Agreement, (ii) the then Stipulated Termination Value of such Equipment and (iii) all losses, damages and expenses (including, without limitation, reasonable attorneys' fees and disbursements) sustained by Lessor by reason of such default and the exercise of Lessor's remedies with respect thereto. (b) If Lessee shall fail to pay Lessor all or any part of the amounts specified in Section 14(a) on any such termination date, Lessor may in its discretion do one or more of the following: (i) subject to any applicable law or regulation, and subject to Lessee's normal and reasonable security arrangements in effect where the Equipment is located, take immediate possession of and remove any or all Equipment or cause such Equipment to be taken from the possession of Lessee, and/or take immediate possession of and remove other property of Lessor in the possession of Lessee, wherever situated, and for such purpose, subject to any applicable law or regulation and subject to Lessee's normal and reasonable security arrangements in effect where the Equipment is located, enter upon any premises without liability for so doing or require Lessee, at Lessee's expense, to deliver the Equipment to Lessor or to such other person as Lessor may designate, in which case the risk of loss shall be upon Lessee until such delivery is made; (ii) subject to any applicable law or regulation, sell any Equipment (with or without the concurrence or request of Lessee) at public or private sale and Lessee shall be liable for and shall promptly pay to Lessor all unpaid Rent to the date of receipt by Lessor of the proceeds of such sale plus any deficiency between the net proceeds of such sale and the Stipulated Termination Value of such Equipment plus all losses, damages and expenses (including, without limitation, reasonable attorneys' fees and disbursements) sustained by Lessor by reason of Lessee's default and the exercise of Lessor's remedies with respect thereto, and to the extent that the net proceeds of any such sale are in excess of such Stipulated Termination Value plus all such losses, damages and expenses, Lessor shall promptly pay to Lessee such excess; (iii) proceed by appropriate judicial proceedings, either at law or in equity to enforce performance or observation by Lessee of the applicable provisions of this Agreement, or to recover damages for the breach of any thereof. (c) The remedies herein provided in favor of Lessor in case of any default by Lessee shall not be deemed to be exclusive, but shall be cumulative and shall be in addition to all other remedies in its favor existing at law, in equity or in bankruptcy. 15. Equipment to be and Remain Personal Property. It is the intention and understanding of both Lessor and Lessee that all Equipment shall be and at all times remain personal property. Lessee shall obtain and record such instruments and take such steps as may be necessary to prevent any person from acquiring any rights in Equipment paramount to the rights of Lessor, its assignees or mortgagees by reason of such Equipment being deemed to be real property. If notwithstanding the intention of the parties and the provisions of this Section 15, any person acquires or reasonably claims to have acquired any rights in any Equipment superior to the rights of Lessor, its assignees or mortgagees, by reason of such Equipment being deemed to be real property, and such person seeks by judicial process or by taking possession to interfere with the continued quiet enjoyment of the Equipment by Lessee as contemplated by this Agreement, then Lessee shall promptly notify Lessor in writing of such fact (unless the basis for such interference is waived or eliminated to the satisfaction of Lessor within a period of ninety (90) days from the date it is asserted) and Lessee shall within ninety (90) days after such notice pay to Lessor or Lessor's assignee an amount equal to the Unamortized Cost of such Equipment at the time of payment. The lease term of such Equipment shall continue until such payment and shall thereupon terminate at the end of the month during which such payment shall have been received by Lessor. Upon receipt of such payment, Lessor shall release to Lessee all of Lessor's right, title and security interest in such Equipment and execute such documents as Lessee may reasonably request to evidence such release. 16. Sale or Assignment by Lessor. Lessor shall have the right to finance the acquisition of such Equipment by selling or assigning its right, title and interest in moneys due from Lessee and any third party under this Agreement and in that connection to assign its security interest in Equipment, provided that in no event may Lessor assign any of its obligations hereunder without remaining secondarily liable therefor, and provided, further, that any such sale or assignment shall be subject and subordinate to the rights and interest of Lessee in such Equipment and under this Agreement. Lessor's transferee or assignee shall have all the rights, powers, privileges and remedies of Lessor hereunder and Lessee's obligations as between itself and such transferee or assignee hereunder shall not be subject to any claims or defense which Lessee may have against Lessor. Upon written notice to Lessee of any such sale or assignment, Lessee shall thereafter make payments of all rents and other sums due hereunder to the party specified in such notice and such payments shall discharge the obligation of Lessee to Lessor hereunder to the extent of such payments. 17. Unconditional Obligation of Lessee to Pay Rent. Lessee's obligation to pay all Rent and other amounts payable hereunder shall be absolute and unconditional and shall not be affected by any circumstance, including, without limitation, (i) any setoff, counterclaim, recoupment, defense or other right which Lessee may have against Lessor or anyone else for any reason whatsoever, (ii) any defect in the title, compliance with specifications, condition, design, operation or fitness for use of, or any damage to or loss or destruction of, any Equipment, or (iii) any interruption or cessation in the use or possession of any Equipment by Lessee for any reason whatsoever, provided, however, that if an interruption or cessation in Lessee's use or possession of any Equipment is caused by any attachment or similar act by or on behalf of any creditor of Lessor, and is not attributable to any failure by Lessee to perform its obligations under this Agreement, then Lessee's obligation to pay Rent with respect to such Equipment shall be appropriately reduced for the period of such interruption or cessation, and, provided further, that the foregoing shall be without prejudice to Lessee's right to pursue by separate legal action any claim Lessee may have against Lessor arising out of this Agreement. Lessee hereby waives, to the extent permitted by applicable law, any and all rights which it may now have or which at any time hereafter may be conferred upon it, by statute or otherwise, to terminate, cancel, quit or surrender this Agreement except in accordance with the express terms hereof. Subject to the second proviso in the first sentence of this Section 17, each Rent and other payment made by Lessee shall be final and Lessee will not seek to recover all or any part of such payment from Lessor for any reason whatsoever. 18. Additional Right of Termination. A. In addition to any other right of termination contained in this Agreement, Lessor may terminate the lease of all Equipment upon any "Special Terminating Event", by giving Lessee 5 days prior written notice of such termination. For purposes of this Section 18A, "Special Terminating Events" shall mean any of the following: (i) any assignment of the Millstone Plant Agreement by and among The Connecticut Light and Power Company ("CL&P"), Western Massachusetts Electric Company ("WMECO") and Lessee ("Plant Agreement"), without Lessor's prior written consent, which consent shall not be unreasonably withheld; provided that this clause (i) shall not apply to any assignment of the Millstone Plant Agreement as part of any merger, consolidation or reorganization of CL&P or WMECO with or into each other or with or into Northeast Utilities ("NU"); (ii) any modification to the Plant Agreement which could materially adversely affect Lessee's ability to perform all of its obligations under this Agreement; (iii) cancellation of the Plant Agreement; (iv) the Plant Agreement shall become illegal, unenforceable or invalid; (v) any merger, consolidation or reorganization of Lessee which in Lessor's reasonable judgment could cause an adverse material change in Lessee's ability to perform all of its obligations under this Agreement; or (vi) Lessee shall no longer be a direct or indirect wholly-owned subsidiary of Northeast Utilities or any successor thereof. B. In addition to any other right of termination contained in this Agreement, Lessee may terminate the lease of all Equipment upon Lessee paying Lessor for taxes on the net income of Lessor under the tax indemnity provisions of Section 10(c) hereof as a result of any change in the applicable laws, rules or regulations from those in effect on the date of this Agreement, by giving Lessor 5 days prior written notice of such termination. Upon the termination date specified in such notice, Lessee shall pay to Lessor an amount equal to the Unamortized Cost of the Equipment and upon receipt by Lessor of such amount, Lessor shall release all of its right, title and security interest therein and execute such documents as Lessee may reasonably request to evidence such release. 19. Notice and Request Any notice or request which by any provision of this Agreement is required or permitted to be given by either party to the other shall be deemed to have been given when deposited in the mail, postage prepaid, by first class mail or air mail (unless certified or registered mail is otherwise specified for such notice under this Agreement), and addressed as follows (or to such other address as either party may specify by written notice to the other party): If to Lessor - The Prudential Insurance Company of America c/o PruCapital Management, Inc. Box 1613 Newark, New Jersey 07101 Attention: Comptroller If to Lessee - Northeast Nuclear Energy Company P.O. Box 270 Hartford, Connecticut 06141-0270 Attention: Treasurer 20. Conditions to Lease. This Agreement, and the rights and obligations of the parties hereunder, is subject to the following conditions: A. Regulatory Approvals Lessee shall obtain all federal and state regulatory approvals which are required in connection with the execution, delivery and performance of this Agreement and the transactions contemplated hereby. B. Board of Directors and Other Approvals Lessee shall obtain the approval of its Board of Directors, if required, and Lessor shall obtain the approval of the Finance Committee of its Board of Directors, if required, for the execution, delivery and performance of this Agreement and the transactions contemplated hereby. C. Indenture Release Lessee shall obtain a release of the Equipment from the lien of the Indenture of Mortgage, Assignment and Security Agreement dated as of August 26, 1983, granted by NUSIMCO, Inc. to The Toronto-Dominion Bank, Atlanta Agency, as amended and supplemented to the date hereof. D. Consent of Singer/Link Lessee shall obtain the consent of the Link Simulation Systems Division of The Singer Company ("Singer/Link"), the vendor of the Equipment, if such consent shall be required under the Contract for Nuclear Power Plant Control Room Simulators dated as of July 1, 1982, between Northeast Utilities Service Company acting as agent for certain other entities, and Singer/Link, as the same may have been amended, modified, and supplemented. E. Material and Adverse Change At the time each Individual Leasing Record is executed by Lessee, since March 31, 1985 there shall not have occurred or be threatened (i) a material and adverse change in Lessee's financial condition, or (ii) any condition, event or act which would materially and adversely affect Lessee's financial condition or its ability to perform its obligations under this Agreement, and Lessee shall have delivered to Lessor an officer's certificate to both such effects. F. Representations and Warranties All representations and warranties of Lessee contained in Exhibit D attached hereto or in any document or certificate furnished to Lessor in connection herewith shall be true and correct on the date of each Individual Leasing Record subsequent to May 2, 1985 and Lessee shall have delivered to Lessor an officer's certificate to such effect. G. Additional Assurances by Lessee Lessee shall provide Lessor with such additional certificates, documents, evidences of title and opinions of counsel, and shall make such filings and recordations, as Lessor shall reasonably request, and all legal and title matters with respect to this Agreement and the transactions contemplated hereby shall be satisfactory in form and substance to Lessor. 21. Miscellaneous. The parties hereto agree that the other party shall not by act, delay, omission or otherwise be deemed to have waived any of its rights or remedies hereunder unless such waiver is given in writing. A waiver on one occasion shall not be construed to be a waiver on any other occasion. This Agreement, the Individual Leasing Records covering Equipment leased pursuant to this Agreement, agreements in the form of exhibits annexed hereto and the certificate certifying as to various matters relating to Lessee furnished by Lessee to Lessor in connection herewith constitute the entire agreement between the parties hereto with respect to the leasing of and creation of a security interest in the Equipment and no representations, warranties, promises, guaranties or agreements, oral or written, express or implied have been made by either party hereto with respect to this Agreement or the Equipment, except as expressly provided herein. Any change or modification of this Agreement must be in writing and duly executed by the parties hereto. The captions in this Agreement are for convenience or reference only and shall not be deemed to affect the meaning or construction of any of the provisions hereof. Any provision of this Agreement which is prohibited or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such prohibition or unenforceability without invalidating the remaining provisions hereof, and any such prohibition or unenforceability in any jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction. To the extent permitted by applicable law, Lessee hereby waives any provision of law which renders any provision hereof prohibited or unenforceable in any respect. Lessee from time to time shall deliver to Lessor, promptly upon reasonable request such information with respect to Lessee's operations, business, property, assets, financial condition or litigation as Lessor shall reasonably request, including without limitation annual unaudited financial statements and quarterly unaudited financial statements of Lessee and Lessee's annual Form 1 filing with the Federal Energy Regulatory Commission, and promptly after filing, copies of any prospectus on any proposed public issue, any report on Form 10-K, Form 10-Q, or Form 8-K which CL&P, WMECO and NU or their successors shall file with the Securities and Exchange Commission or any securities exchange. Lessee hereby certifies to Lessor that any representation or statement made by Lessee herein or in any written instrument furnished by Lessee to Lessor in connection herewith shall be true and correct in all material respects as of the date when made, and further certifies to Lessor that no such representation or statement omitted to state a material fact necessary in order to make such representation or statement not misleading in light of the circumstances under which it was made. This Agreement and the rights and obligations of the parties hereunder shall be construed in accordance with and be governed by the laws of the State of Connecticut. Lessor hereby agrees that whenever this Agreement requires Lessor to convey title to Equipment to Lessee or its designee, Lessor shall convey title free and clear of all liens, charges and encumbrances created by or against Lessor. IN WITNESS WHEREOF, Lessor and Lessee have caused this Agreement to be executed and delivered by their duly authorized officers as of the day and year first above written. (Corporate Seal) THE PRUDENTIAL INSURANCE COMPANY OF AMERICA ATTEST: By its authorized agent, PRUCAPITAL MANAGEMENT INC., Lessor /s/ /s/ John K. Wand Assistant Secretary Vice President (Corporate Seal) NORTHEAST NUCLEAR ENERGY COMPANY Lessee /s/ Cheryl W. Grise /s/ David H. Boguslawski Assistant Secretary Assistant Treasurer STATE OF ) ss: COUNTY OF ) On this 14th day of June, 1985, before me personally appeared John K. Wand, to me personally known, who, being by me duly sworn, says that he is Vice President of PruCapital Management Inc., that one of the seals affixed to the foregoing instrument is the corporate seal of said corporation, that said instrument was signed and sealed on behalf of said corporation by proper corporate authority and he acknowledged that the execution of the foregoing instrument was the free act and deed of said corporation. /s/ Marcia L. Grimes Notary Public My Commission Expires: 2/28/91 STATE OF CONNECTICUT ) ss: BERLIN COUNTY OF HARTFORD ) On this 19th day of June, 1985, before me personally appeared David H. Boguslawski, to me personally known, who, being by me duly sworn, says that he is Assistant Treasurer of Northeast Nuclear Energy Company, that one of the seals affixed to the foregoing instrument is the corporate seal of said corporation, that said instrument was signed and sealed on behalf of said corporation by proper corporate authority and he acknowledged that the execution of the foregoing instrument was the deed of said corporation. /s/ Andrea Allen EX-13.1 16 Exhibit 13.1 1994 PORTIONS OF ANNUAL REPORT TO SHAREHOLDERS NORTHEAST UTILITIES FINANCIAL AND STATISTICAL SECTION TABLE OF CONTENTS Page 16-23 Management's Discussion and Analysis Page 24 Company Report Page 24 Report of Independent Public Accountants Page 25 Consolidated Statements of Income Page 26 Consolidated Statements of Cash Flows Page 27 Consolidated Statements of Income Taxes Page 28-29 Consolidated Balance Sheets Page 30-31 Consolidated Statements of Capitalization Page 32 Consolidated Statements of Common Shareholders' Equity Page 33-46 Notes to Consolidated Financial Statements Page 47 Consolidated Statements of Quarterly Financial Data Page 47 Consolidated General Operating Statistics Page 48-49 Selected Consolidated Financial Data Page 50 Consolidated Electric Operating Statistics MANAGEMENT DISCUSSION AND ANALYSIS FINANCIAL CONDITION Overview Earnings per common share were $2.30 in 1994, as compared to $2.02 in 1993. The 1994 earnings were higher as a result of higher retail kilowatt-hour sales, retail rate increases for CL&P and PSNH, the deferral of cogeneration expenses in Connecticut, and reduced operation and interest costs. These increases were partially offset by lower revenues from wholesale sales. The 1993 earnings were impacted by a number of one-time items, including the cumulative effect of a one-time change in the accounting for Connecticut municipal property taxes, which resulted in an increase in 1993 earnings of $0.42 per common share. In addition, 1993 earnings reflected a decrease of $0.14 per share for the costs of the company's employee-reduction program and a decrease of $0.12 per share for disallowances in 1993 ordered by Connecticut regulators in the CL&P rate case. Earnings per common share before the effects of the change in accounting for property taxes and other one-time items were $1.86 in 1993. Increased earnings will help the company to achieve its objective of increasing total return to shareholders (stock price plus dividend return). In 1994, total return to shareholders was more than 13 percentage points better than the Dow Jones Utilities Index. In 1994, NU experienced its most significant retail kilowatt-hour sales growth in six years, due in large part to the beginning of an economic recovery in New England. Employment levels-particularly in New Hampshire - have risen, unemployment rates have fallen, and personal income has increased in all three states served by the NU operating companies (the system). NU's 1994 retail sales rose by 2.9 percent over 1993. Overall, weather had little effect on sales volume, with mild weather after mid-August offsetting unusually cold weather in January and hot weather in late June and July. In 1995, the company expects little retail sales growth over 1994, primarily because of the effects of higher interest rates on the regional economy and further cutbacks in defense-related industries in Connecticut. Over the longer term, retail kilowatt-hour sales growth is expected to be strongest in New Hampshire, which by some measures has the fastest growing economy in New England. In 1994, many businesses announced plans to expand in New Hampshire. NU estimates PSNH to have compounded annual sales growth of 1.9 percent from 1994 through 1999, compared with 1.4 percent for CL&P and 0.9 percent for WMECO. Competitive forces within the electric utility industry are continuing to increase due to a variety of influences, including legislative and regulatory actions, technological advances, and changes in consumer demand. The company has developed, and is continuing to develop, a number of initiatives to retain and to continue to serve its existing customers and to expand its retail and wholesale customer base. NU believes the steps it is taking, including a companywide process reengineering effort, will have significant, positive effects, including reduced operating costs and improved customer service, in the next few years. The system also benefits from a diverse retail base with no significant dependence on any one retail customer or industry. NU's electric utility subsidiaries 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 and require the local electric utility to transmit the power to the customer's site, is not required in any of the system's jurisdictions. In 1994, Connecticut regulators reviewed the desirability of retail wheeling and determined that it was not in the best interest of the state until new generating capacity is needed, which the company projects to be in the year 2009. In New Hampshire and Massachusetts, bills related to retail wheeling have been introduced in the legislature. Connecticut, New Hampshire, and Massachusetts regulators are presently studying the potential restructuring of the electric utility industry. To date, none of these bills have been enacted and none of the regulatory proceedings have progressed to the point where management can assess the impact of any potential outcomes on the company. While retail competition is not required in the system's retail service territory, competitive forces are nonetheless influencing retail pricing. These forces include competition from alternate fuels such as natural gas, competition from customer-owned generation, and regional competition for business retention and expansion. The company's retail business group continues to work with customers to address their concerns. The system has reached long-term rate agreements with many new and existing customers to gain or retain their business. In general, these rate agreements have terms of about five years. Negotiated retail rate reductions for system customers under rate agreements in effect for 1994 amounted to approximately $20 million. Management believes that the aggregate amount of negotiated retail rate reductions will increase in 1995 but that the related agreements will continue to provide significant benefits to the company, including the preservation of approximately 4 percent of retail revenues. The company is also working with regulators to address the needs of customers more widely. The company has multiyear rate plans in effect in each of its retail jurisdictions. Management will continue to evaluate the use of agreements of this type to keep retail rates competitive. 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). Many of the contracts signed in the late 1980s have or will expire in the mid-1990s and much of the revenue produced by such contracts has not been replaced through new wholesale power arrangements. As a result, wholesale power revenues fell to approximately $331 million in 1994 from approximately $383 million in 1993. Unless prices on the wholesale market improve, revenues are expected to fall still further in 1995 before stabilizing in late 1996 and 1997. Wholesale sales are made primarily to investor-owned utilities and municipal or cooperative electric systems in the Northeast. The system will be increasing its efforts to increase wholesale sales through intensified marketing efforts. The system's wholesale power marketing efforts benefit from the interconnection of its transmission system with all of the major utilities in New England, as well as with three of the larger electric utilities in New York state. Rate Matters The operating companies of the system follow accounting principles that allow the rate treatment for certain events or transactions to be reflected. These principles may differ from the accounting principles followed by nonregulated enterprises. Regulators may permit incurred costs, which would normally be treated as expenses by nonregulated enterprises, to be deferred as regulatory assets and recovered in revenues at a later date. Regulatory assets at December 31, 1994 were approximately $2.7 billion. Based on current regulation, the company believes that its use of regulatory accounting is still appropriate. See the "Notes To Consolidated Financial Statements," Note 1H, for further details on regulatory accounting. Connecticut CL&P's retail rates increased by approximately $47 million, or 2.04 percent, in July 1994, representing the second step of a three-year rate plan approved by the Department of Public Utility Control (DPUC) in 1993. The third step of an approximately $48-million, or 2.06 percent, increase will become effective in July 1995. CL&P's 1993 rate decision has been appealed by the Connecticut Office of Consumer Counsel and the city of Hartford. If this appeal prevails, there may be revenues subject to refund; however, management believes that the possibility of the appeal prevailing is unlikely. CL&P recovers from or refunds to customers certain fuel costs if the nuclear units do not operate at a predetermined capacity factor (currently 72 percent) through a Generation Utilization Adjustment Clause (GUAC). For the GUAC year ended July 31, 1994, the DPUC found that CL&P overrecovered its fuel costs and reduced by approximately $8 million CL&P's overall request to recover approximately $24 million of deferred GUAC costs. The company plans to appeal the decision in court as it did for a similar DPUC decision on the 1992-1993 GUAC period, which also disallowed approximately $8 million of GUAC costs. For the GUAC year ended July 31, 1995, CL&P expects to defer in excess of $50 million of GUAC fuel costs for projected nuclear performance below 72 percent. As of December 31, 1994, CL&P has reserved approximately $13 million against this amount, based on the methodology applied by the DPUC in the previous GUAC decisions. New Hampshire In June 1994, PSNH's base rates increased by 5.5 percent under a seven-year 1989 rate agreement approved by the New Hampshire Public Utilities Commission (NHPUC). The costs associated with purchases by PSNH from certain nonutility generators (NUGs) over the level assumed in rates are deferred and recovered over ten-year periods through the Fuel and Purchased Power Adjustment Clause (FPPAC). At December 31, 1994, the unrecovered deferrals were approximately $174 million. PSNH is attempting to renegotiate these arrangements with the NUGs. On September 23, 1994, the NHPUC approved settlement agreements with two wood-fired NUGs covering approximately 20 megawatts (MW) of capacity. These two NUGs gave up their rights to sell their output to PSNH in exchange for lump-sum cash payments by PSNH totaling approximately $40 million. The buyout payments were added to the deferred balance of NUG costs. The savings resulting from the agreements will be used to reduce the NUG deferred balance over the remaining period of the canceled arrangements. PSNH is involved in mediations with the owners of the six remaining wood-fired facilities, which account for approximately 87 MW of capacity. PSNH has reached an agreement with one of these six NUGs, which calls for a payment by PSNH of $52 million in return for a substantial reduction in the rates charged to PSNH. This agreement was filed with the NHPUC in February 1995. Massachusetts On May 26, 1994, the Massachusetts Department of Public Utilities (DPU) approved a settlement agreement under which WMECO's customers received a base-rate reduction of approximately $13 million over a 20-month period effective June 1, 1994 and a guarantee of no general base-rate increases before February 1996. This agreement also terminated, without findings, all performance review proceedings regarding the treatment of replacement-power costs incurred by WMECO during power outages from mid-1987 through mid-1993. The DPU also approved the amortization of previously deferred expenses for postretirement benefits beginning in July 1994. In addition, under the agreement, WMECO's larger customers will be offered discounts on their electric bills in return for providing WMECO with five years' notice of any plans to self-generate or purchase electricity from a different provider. The combined base-rate reduction and service-extension discounts will total 5 percent for those larger customers. The settlement agreement did not have a significant adverse impact on WMECO's earnings. Nuclear Performance The composite capacity factor of the five nuclear generating units that the system operates-including the Connecticut Yankee (CY) nuclear unit-was 67.5 percent for 1994, compared with 80.8 percent for 1993 and a 1994 national average of 73.2 percent. The lower 1994 capacity factor was primarily the result of extended refueling and maintenance outages for Millstone 1, Millstone 2, and Seabrook. CY, Seabrook, and Millstone 2 were also out of service for varying lengths of time in 1994 because of unexpected technical and operating difficulties. These difficulties included a manual shutdown of CY when both service water headers were declared inoperable, an automatic trip from 100 percent power for Seabrook when a main steam isolation valve closed during quarterly surveillance testing, and a Millstone 2 shutdown to replace a degraded lower seal on a reactor coolant pump. On October 1, 1994, Millstone 2 was shut down for a planned 63-day refueling and maintenance outage. The outage has encountered several unexpected difficulties, which will lengthen the duration of the outage. The outage extensions were caused by a significant scope increase in service water system repairs, as identified through a comprehensive inspection plan and by a need for management to exercise a deliberate approach to the conduct of work during the early portions of the outage. The outage schedule is currently under review, but the unit is not expected to return to service before April 1995. Total replacement-power costs attributable to the extension of the outage for CL&P and WMECO are expected to be in the range of $8 million per month. CL&P's share of these costs is deferred for future recovery through the GUAC. (See page 18 for further discussion of the GUAC.) In addition, operation and maintenance costs to be incurred during the outage are estimated to be $52 million, an increase of $19 million as a result of the extension. The recovery of these costs is subject to prudence reviews in both Connecticut and Massachusetts. The Nuclear Regulatory Commission's (NRC's) latest report for the Millstone Station noted significant weaknesses in Millstone 2's operations and maintenance. In a public statement in late 1994, a senior NRC official expressed disappointment with the continued weaknesses in Millstone 2's performance. The primary cause of the NRC's disappointment with Millstone 2's performance appears to be that, despite significant management attention and action over a period of years, the NRC does not believe it has seen enough objective evidence of improvement in reducing procedural noncompliance and other human errors. Management has acknowledged the basis for the NRC's concern with Millstone 2 and has been devoting increased attention to resolving these issues. Management and the NRC expect to continue to monitor closely the developments at Millstone 2. Environmental Matters The system devotes substantial resources to identify and then to meet the multitude of environmental requirements it faces. The company has active auditing programs addressing a variety of different regulatory requirements, including an environmental auditing program to detect and remedy noncompliance with environmental laws or regulations. The system 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 the company. At December 31, 1994, the liability recorded by the company amounted to approximately $11 million. These costs could rise to as much as $16 million if alternate remedies become necessary. The company expects that the implementation of the 1990 Clean Air Act Amendments (CAAA) as they relate to sulfur-dioxide emissions will require only modest emission reductions for the NU system. NU's exposure is minimal because of the company's investment in nuclear energy in the 1970s and 1980s and the burning of low-sulfur fuels. PSNH is subject to more stringent emission limits for nitrogen oxides within the next five years under the CAAA requirements. PSNH will install at Merrimack Station a selective catalytic reduction (SCR) pollution control system by May 1995 to comply with CAAA requirements. The cost of the SCR installation is approximately $22 million, with approximately $10 million of costs incurred as of December 31, 1994. Nuclear Decommissioning The system's estimated cost to decommission its shares of Millstone units 1, 2, and 3 and Seabrook is approximately $1.2 billion in year-end 1994 dollars. In addition, the system's estimated cost to decommission its shares of the regional nuclear generating units is estimated to be approximately $300 million. These costs are being recognized over the lives of the respective units and a portion of the costs is being recovered through rates. Yankee Atomic Electric Company (YAEC) has begun component removal activities related to the decommissioning of its nuclear facility. The system's estimated obligation to YAEC has been recorded on the Consolidated Balance Sheets. Management expects that the system will continue to be allowed to recover these costs. The staff of the Securities and Exchange Commission has questioned certain of the current accounting practices of the electric utility industry, including this company, regarding the recognition, measurement, and classification of decommissioning costs for nuclear generating stations in the financial statements of electric utilities. The Financial Accounting Standards Board is currently reviewing the accounting for removal costs, including decommissioning and similar costs. If current electric utility industry accounting practices for such decommissioning costs were changed: (1) annual provisions for decommissioning could increase, (2) the estimated costs for decommissioning could be recorded as a liability rather than as accumulated depreciation, and (3) trust fund income from the external decommissioning trust could be reported as investment income rather than as a reduction to decommissioning expense. See the "Notes To Consolidated Financial Statements," Note 3, for further information on nuclear decommissioning. Two separate stacked bar graphs illustrate the sources and uses of cash requirements for 1993 and 1994 and projections for 1995 through 1999. NORTHEAST UTILITIES SOURCES AND USES OF CASH REQUIREMENTS 1993 - 1999 Sources of Cash Requirements 1993 1994 1995 1996 1997 1998 1999 --------------- ---- ---- ---- ---- ---- ---- ---- (Percentages) Internally Generated Funds 36.7 46.7 80.5 80.4 86.2 88.3 69.0 Nuclear Fuel Trust 5.2 6.7 7.2 16.3 13.8 9.3 11.5 LTD and Preferred Stock 56.9 44.3 12.3 0.0 0.0 0.0 17.5 Short-Term Debt 0.0 1.2 0.0 1.1 0.0 0.0 0.0 Common Stock 1.2 1.1 0.0 2.2 0.0 2.4 2.0 ----- ----- ----- ----- ----- ----- ----- Total Sources 100.0 100.0 100.0 100.0 100.0 100.0 100.0 Uses of Cash Requirements 1993 1994 1995 1996 1997 1998 1999 --------------- ---- ---- ---- ---- ---- ---- ---- (Percentages) Construction 15.6 18.4 31.1 34.8 32.4 35.8 27.7 Nuclear Fuel 5.9 7.2 9.1 18.9 14.3 11.7 13.7 Maturities and Sinking Fund 66.1 70.2 36.5 43.1 43.4 41.0 49.1 Repayment of Short-Term Debt 10.1 0.0 19.6 0.0 8.2 10.6 8.6 Other 2.3 4.2 3.7 3.2 1.7 0.9 0.9 ----- ----- ----- ----- ----- ----- ----- Total Uses 100.0 100.0 100.0 100.0 100.0 100.0 100.0 Property Taxes CY and PSNH have had significant court appeals for municipal property tax assessments in the towns of Haddam, Connecticut, and Bow, New Hampshire. In each case, the central issue is the fair market value of utility property. The company 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, Massachusetts, and in some of New Hampshire. However, towns such as Haddam and Bow advocate a method that approximates reproduction costs. PSNH's appeal of the property tax as assessed against them by Bow has been dismissed by the Supreme Court of New Hampshire. CY's appeal is still pending. The company estimates that, for assessments in towns such as Haddam and Bow, the change to the reproduction cost methodology could result in property valuations approximately three times greater than values approximating net book cost. If other towns adopt this methodology, there could be a significant adverse impact on the company's future results of opera tions and financial condition. However, the extent to which other towns successfully adopt this methodology and any subsequent increase in the company's property tax liability cannot be determined at this time. Liquidity And Capital Resources Cash provided from operations increased approximately $7 million in 1994, as compared to 1993, primarily due to higher revenues from rate increases and sales, combined with lower cash operating expenses. Cash used for financing activities was approximately $10 million higher in 1994, as compared to 1993, primarily due to higher net reacquisition and retirements of long-term debt, partially offset by an increase in short-term debt. Cash used for investments was approximately $20 million lower in 1994, as compared to 1993, primarily due to lower construction expenditures in 1994. The charts opposite illustrate the sources and uses of cash requirements for 1993 and 1994 and the projections for 1995 through 1999. In 1994, the NU system companies refinanced $625 million of debt, which is expected to reduce interest costs by approximately $3 million annually. With interest rates rising in mid-1994, a lot of refinancing completed, and construction needs remaining modest, the focus in NU's financing activities will shift toward using the significant amount of cash generated by each subsidiary to retire debt and to prepare the company for an increasingly competitive business environment. The system companies are obligated to meet approximately $1.4 billion of long-term debt and preferred stock maturities and cash sinking-fund requirements during the 1995 through 1999 period, including approximately $176 million for 1995. The system's construction program expenditures, including allowance for funds used during construction, for the period 1995 through 1999 are estimated to be approximately $1.2 billion, including approximately $254 million for 1995. The construction program's main focus is maintaining and upgrading the existing transmission and distribution system, as well as nuclear and fossil-generating facilities. The company does not foresee the need for new, major generating facilities until at least the year 2009. Construction expenditures and debt maturities and sinking-fund requirements will continue to be met through internal cash generation. PSNH may need to supplement its internal cash generation with outside financing, including additional borrowings, if additional agreements are reached with the wood-fired NUGs. CL&P, PSNH, and WMECO entered into interest-rate cap contracts to reduce a portion of the interest-rate risk on certain variable-rate tax-exempt pollution control revenue bonds and a PSNH variable-rate term loan. CL&P also uses fossil-fuel-swap agreements to hedge against fuel-price risk on certain long-term, negotiated energy contracts. Any premiums paid on these contracts are deferred and amortized over the life of the contracts. The differential paid or received as interest rates or fuel prices change is recognized in income when realized. See the "Notes To Consolidated Financial Statements," Note 8, for further information on derivative financial instruments. Results of Operations The relative magnitude of the various expenditures incurred by the system's continuing operations in 1994 is illustrated in the chart on page 23. A majority of the changes in items affecting results of operations between 1992 and 1993 is due to the inclusion of PSNH and NAEC results for a full year in 1993 and only seven months in 1992. 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 $14 million in 1994 from 1993. Revenues related to regulatory decisions increased, primarily because of the effects of the July 1993 and 1994 retail rate increases for CL&P, the June 1993 and 1994 retail rate increases for 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 improving 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. Operating revenues increased approximately $412 million in 1993 from 1992, primarily due to the additional revenues of PSNH for a full year in 1993. Operating revenues, excluding PSNH, increased approximately $45 million in 1993 from 1992. Revenues related to regulatory decisions increased, primarily because of the effects of the June 1993 retail rate increase for CL&P and the July 1992 and 1993 retail rate increases for WMECO. Fuel, purchased power, and FPPAC cost recoveries decreased, primarily due to lower energy costs. Retail sales for CL&P and WMECO increased only 0.2 percent in 1993 from 1992 sales levels. Fuel, Purchased And Net Interchange Power Fuel, purchased and net interchange power decreased approximately $86 million in 1994, as compared to 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. Fuel, purchased and net interchange power increased approximately $145 million in 1993, as compared to 1992, primarily due to the additional PSNH and NAEC expenses (approximately $99 million), the timing in the recognition of fuel expenses under the provisions of CL&P's fuel adjustment cl auses, and disallowances of replacement- power costs as a result of regulatory reviews in Connecticut, partially offset by lower outside purchases due to better nuclear performance in 1993. Other Operation And Maintenance Expenses Other operation and maintenance expenses decreased approximately $20 million in 1994, as compared to 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. Other operation and maintenance expenses increased approximately $143 million in 1993, as compared to 1992, primarily due to the additional PSNH and NAEC expenses (approximately $105 million), the 1993 costs associated with an employee-reduction program (approximately $33 million), the 1992 reimbursement of previously expended costs associated with the PSNH acquisition, and 1993 postretirement benefit costs, partially offset by lower costs associated with the operation and maintenance activities of the nuclear units. Depreciation Expenses Depreciation expenses increased approximately $14 million in 1994, as compared to 1993, primarily as a result of higher depreciable plant balances, higher average depreciation rates, and higher decommissioning collections. Depreciation expenses increased $39 million in 1993, as compared to 1992, primarily as a result of the additional PSNH and NAEC depreciation expense ($27 million, including Seabrook), higher depreciation rates, and high er depreciable plant balances. Amortization Of Regulatory Assets, Net Amortization of regulatory assets, net decreased approximately $48 million in 1994, as compared to 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. Amortization of regulatory assets, net increased approximately $58 million in 1993, as compared to 1992, primarily because of the additional amortization of the PSNH regulatory asset as provided for in the rate agreement (approximately $38 million) and higher amortization of Millstone 3 and Seabrook phase-in costs. The increase in 1993 is also attributable to the gross-up of taxes due to a required change in the accounting for income taxes and the amortization in 1993 of costs paid by CL&P to the developers of two wood-to-energy plants as allowed in the 1993 rate decision, partially offset by the amortization of the PSNH regulatory liability recognized as a result of a 1993 global settlement. Federal And State Income Taxes Federal and state income taxes increased approximately $66 million in 1994, as compared to 1993, primarily because of higher taxable income. Taxes Other Than Income Taxes Taxes other than income taxes increased approximately $7 million in 1994, as compared to 1993, primarily due to higher Connecticut sales tax expense. Taxes other than income taxes increased approximately $19 million in 1993, as compared to 1992, primarily due to the additional PSNH and NAEC taxes ($20 million, including property taxes on Seabrook). Deferred Nuclear Plants Return Deferred nuclear plants return decreased approximately $25 million in 1994, as compared to 1993, primarily because additional Millstone 3 and Seabrook investments were phased into rates in 1994. Deferred nuclear plants return increased approximately $19 million in 1993, as compared to 1992, primarily because of deferred return associated with NAEC's ownership share of Seabrook (approximately $30 million), partially offset by a decrease in Millstone 3 deferred return because additional Millstone 3 investment was phased into rates. Other Income, Net Other income, net decreased approximately $11 million in 1993, as compared to 1992, primarily because of the allocation to customers of a portion of the property tax accounting change as ordered by the DPUC in the CL&P 1993 rate decision. Interest Charges Interest on long-term debt decreased approximately $19 million in 1994, as compared to 1993, primarily because of lower average interest rates as a result of refinancing activities and lower 1994 debt levels. Interest on long-term debt increased approximately $57 million in 1993, as compared to 1992, primarily because of higher debt levels from the addition of PSNH and NAEC (approximately $57 million), partially offset by lower average interest rates as a result of substantial refinancing activities. The increase in 1993 is also due to the absence of an interest expense offset in 1993 for Employee Stock Option Plan (ESOP) dividends due to a change in accounting for ESOPs. 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. Tax Benefit Of Employee Stock Ownership Plan Dividends The tax benefit of ESOP dividends of approximately $7 million in 1992 is the result of the company adopting an ESOP. In 1993, these benefits are reflected as a reduction to income tax expense. See the "Notes To Consolidated Financial Statements," Note 6, for further information regarding ESOP. A pie chart illustrates the magnitude of the various expenses incurred by the System's continuing operations in 1994. NORTHEAST UTILITIES 1994 DISTRIBUTION OF REVENUE Percent ------- Energy Costs 22.9% Other Operation and Maintenance Expenses 21.3 Taxes 14.5 Other Operating Expenses and Other Income, Net 13.0 Wages and Benefits 12.3 Interest Charges 8.8 Common and Preferred Dividends 7.2 ----- 100.0% 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, 1994 and 1993, 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, 1994. 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, 1994 and 1993, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1994, in conformity with generally accepted accounting principles. As explained in Notes 1B, 5B, and 6 to the financial statements, effective January 1, 1993, Northeast Utilities and subsidiaries changed their methods of accounting for property taxes, postretirement benefits other than pensions, and employee stock ownership plans. /s/Arthur Andersen LLP ARTHUR ANDERSEN LLP Hartford, Connecticut February 17, 1995 NORTHEAST UTILITIES AND SUBSIDIARIES Consolidated Statements of Income
For the Years Ended December 31, 1994 1993 1992 -------------------------------------------------------------------------------------------- (Thousands of Dollars, except share information) Operating Revenues................................ $ 3,642,742 $ 3,629,093 $ 3,216,874 ------------- ------------- ------------- Operating Expenses: Operation -- Fuel, purchased and net interchange power....... 832,420 917,957 772,804 Other........................................... 919,044 979,403 828,345 Maintenance...................................... 306,429 265,926 274,495 Depreciation..................................... 335,019 321,359 282,738 Amortization of regulatory assets, net........... 160,909 208,506 150,413 Federal and state income taxes(See Consolidated Statements Of Income Taxes)(Note 1I)...... 293,644 224,678 246,227 Taxes other than income taxes.................... 247,045 240,413 221,422 ------------- ------------- ------------- Total operating expenses.................. 3,094,510 3,158,242 2,776,444 ------------- ------------- ------------- Operating Income.................................. 548,232 470,851 440,430 ------------- ------------- ------------- Other Income: Deferred nuclear plants return--other funds (Note 1L).......................... 27,085 38,373 45,299 Equity in earnings of regional nuclear generating and transmission companies......... 14,426 12,980 15,357 Other, net...................................... 7,745 4,747 15,672 Income taxes--credit............................ 13,518 10,772 36,787 ------------- ------------- ------------- Other income, net......................... 62,774 66,872 113,115 ------------- ------------- ------------- Income before interest charges............ 611,006 537,723 553,545 ------------- ------------- ------------- Interest Charges: Interest on long-term debt...................... 314,191 333,163 275,819 Other interest.................................. 8,037 13,059 3,503 Deferred nuclear plants return--borrowed funds (Note 1L).......................... (41,138) (54,462) (28,838) ------------- ------------- ------------- Interest charges, net..................... 281,090 291,760 250,484 ------------- ------------- ------------- Income before cumulative effect of accounting change....................... 329,916 245,963 303,061 Cumulative effect of accounting change (Note 1B)........................... - 51,681 - ------------- ------------- ------------- Income before Preferred Dividends of Subsidiaries....................... 329,916 297,644 303,061 Preferred Dividends of Subsidiaries............... 43,042 47,691 47,007 ------------- ------------- ------------- Net Income 286,874 249,953 256,054 Tax benefit of Employee Stock Ownership Plan dividends (Note 6)................ - - 7,348 ------------- ------------- ------------- Earnings For Common Shares........................ $ 286,874 $ 249,953 $ 263,402 ============= ============= ============= Earnings Per Common Share: Before cumulative effect of accounting change......................................... $ 2.30 $ 1.60 $ 2.02 Cumulative effect of accounting change (Note 1B).......................... - 0.42 - ------------- ------------- ------------- Total Earnings Per Common Share................... $ 2.30 $ 2.02 $ 2.02 ============= ============= ============= Common Shares Outstanding (average) (Note 6).. 124,678,192 123,947,631 130,403,488 ============= ============= =============
The accompanying notes are an integral part of these financial statements. NORTHEAST UTILITIES AND SUBSIDIARIES Consolidated Statements of Cash Flows
------------------------------------------------------------------------------------------------- For the Years Ended December 31, 1994 1993 1992 ------------------------------------------------------------------------------------------------- (Thousands of Dollars) Cash Flows From Operating Activities: Income before preferred dividends of subsidiaries........ $ 329,916 $ 297,644 $ 303,061 Adjustments to reconcile to net cash from operating activities: Depreciation........................................... 335,019 321,359 282,738 Deferred income taxes and investment tax credits, net.. 146,560 63,506 103,089 Deferred nuclear plants return, net of amortization.... 49,994 18,189 (3,619) Recoverable energy costs, net of amortization.......... (85,573) 93,302 (109,013) Amortization of regulatory asset-PSNH, net............. 55,319 67,379 51,143 Deferred demand-side management, net of amortization... (4,691) (23,955) (31,989) Other sources of cash.................................. 42,375 136,346 127,519 Other uses of cash..................................... (52,260) (3,915) (53,711) Changes in working capital: Receivables and accrued utility revenues............... 8,133 2,797 3,162 Fuel, materials, and supplies.......................... 4,906 10,126 (9,686) Accounts payable....................................... 51,824 (678) (38,889) Accrued taxes.......................................... 17,031 (97,789) (8,627) Other working capital (excludes cash).................. 22,329 30,010 30,109 ----------- ------------ ------------ Net cash flows from operating activities................... 920,882 914,321 645,287 ----------- ------------ ------------ Cash Flows Used For Financing Activities: Issuance of common shares................................ 14,551 22,252 271,128 Issuance of long-term debt............................... 625,000 924,650 1,141,995 Issuance of preferred stock.............................. - 80,000 75,000 Net increase (decrease) in short-term debt............... 16,500 (179,240) 182,240 Reacquisitions and retirements of long-term debt......... (982,920) (1,051,501) (744,771) Reacquisitions and retirements of preferred stock........ (7,325) (116,496) (106,893) Cash dividends on preferred stock........................ (43,042) (47,691) (49,399) Cash dividends on common shares.......................... (219,317) (218,179) (229,074) ----------- ------------ ------------ Net cash flows (used for) from financing activities........ (596,553) (586,205) 540,226 ----------- ------------ ------------ Investment Activities: Investments in plant: Electric and other utility plant....................... (259,904) (275,741) (311,892) Nuclear fuel........................................... (28,308) (33,202) 3,498 ----------- ------------ ------------ Net cash flows used for investments in plant............. (288,212) (308,943) (308,394) Acquisition of the net assets of PSNH (Note 1A)..... - - (828,237) Other investment activities, net......................... (33,546) (32,811) (40,507) ----------- ------------ ------------ Net cash flows used for investments........................ (321,758) (341,754) (1,177,138) ----------- ------------ ------------ Net Increase (Decrease) In Cash for the Period............. 2,571 (13,638) 8,375 Cash - beginning of period................................. 32,008 45,646 37,271 ----------- ------------ ------------ Cash - end of period....................................... $ 34,579 $ 32,008 $ 45,646 =========== ============ ============ Supplemental Cash Flow Information: Cash paid during the year for: Interest, net of amount capitalized during construction.. $ 306,224 $ 325,552 $ 218,515 =========== ============ ============ Income taxes............................................. $ 134,727 $ 142,669 $ 96,821 =========== ============ ============ Increase in obligations: Niantic Bay Fuel Trust................................... $ 64,590 $ 49,509 $ 38,172 =========== ============ ============ Capital leases........................................... $ 1,342 $ 4,696 $ 2,985 =========== ============ ============
The accompanying notes are an integral part of these financial statements. NORTHEAST UTILITIES AND SUBSIDIARIES Consolidated Statements of Income Taxes
1994 1993 1992 For the Years Ended December 31, (Note 1I) ---------------------------------------------------------------------------------------- (Thousands of Dollars) The components of the federal and state income tax provisions charged to operations are: Current income taxes: Federal.......................................... $ 88,483 $ 99,591 $ 74,768 State............................................ 45,083 50,809 31,583 ---------- -------------- ---------- Total current.................................. 133,566 150,400 106,351 ---------- -------------- ---------- Deferred income taxes, net: Federal.......................................... 149,391 87,105 101,025 State............................................ 6,988 (10,058) 12,550 ---------- -------------- ---------- Total deferred................................. 156,379 77,047 113,575 ---------- -------------- ---------- Investment tax credits, net....................... (9,819) (13,541) (8,182) ---------- -------------- ---------- Total income tax expense........................... $ 280,126 $ 213,906 $ 211,744 ========== ============== ========== The components of total income tax expense are classified as follows: Income taxes charged to operating expenses........ $ 293,644 $ 224,678 $ 246,227 Income taxes associated with the amortization of deferred nuclear plants return--borrowed funds... - - (17,566) Income taxes associated with the allowance for funds used during construction and deferred nuclear plants return--borrowed funds............ - - 19,870 Other income taxes--credit........................ (13,518) (10,772) (36,787) ---------- -------------- ---------- Total income tax expense........................... $ 280,126 $ 213,906 $ 211,744 ========== ============== ========== Deferred income taxes are comprised of the tax effects of temporary differences as follows: Depreciation, leased nuclear fuel, settlement credits, and disposal costs..................... 72,078 79,288 66,683 Energy adjustment clauses........................ 49,017 (39,660) 22,484 Demand-side management........................... 217 8,117 13,635 Alternative minimum tax.......................... (601) 2,306 (13,462) Early retirement program......................... 1,169 (7,715) 220 Organization costs............................... - - 10,042 Deferred tax asset associated with net operating losses................................ 23,611 25,438 9,335 Other............................................ 10,888 9,273 4,638 ---------- -------------- ---------- Deferred income taxes, net......................... $ 156,379 $ 77,047 $ 113,575 ========== ============== ========== A reconciliation between income tax expense and the expected tax expense at the applicable statutory rates is as follows: Expected federal income tax at 35 percent of pretax income for 1994 and 1993 and at 34 percent for 1992.............................. $ 213,515 $ 179,043 $ 175,033 Tax effect of differences: Depreciation differences......................... 20,003 21,319 14,090 Deferred nuclear plants return--other funds...... (9,480) (13,486) (15,402) Amortization of deferred Millstone 3 return-- other funds..................................... 23,103 21,988 17,367 Amortization of regulatory asset--PSNH........... 20,007 23,764 17,624 Seabrook intercompany loss....................... (19,637) (19,176) (11,903) Investment tax credits amortization.............. (9,819) (13,541) (8,182) State income taxes, net of federal benefit....... 33,847 26,488 29,130 Property tax differences......................... 5,824 (13,514) (901) Other, net....................................... 2,763 1,021 (5,112) ---------- -------------- ---------- Total income tax expense........................... $ 280,126 $ 213,906 $ 211,744 ========== ============== ==========
The accompanying notes are an integral part of these financial statements. NORTHEAST UTILITIES AND SUBSIDIARIES Consolidated Balance Sheets
At December 31, 1994 1993 --------------------------------------------------------------------------------- (Thousands of Dollars) ASSETS ------ Utility Plant, at original cost: Electric............................................. $ 9,334,912 $ 9,119,285 Other................................................ 157,632 146,228 ------------ ------------ 9,492,544 9,265,513 Less: Accumulated provision for depreciation...... 3,293,660 3,021,987 ------------ ------------ 6,198,884 6,243,526 Construction work in progress........................ 179,724 208,084 Nuclear fuel, net.................................... 224,839 218,051 ------------ ------------ Total net utility plant.......................... 6,603,447 6,669,661 ------------ ------------ Other Property and Investments: Nuclear decommissioning trusts, at market in 1994 and at cost in 1993 (Note 9).................... 240,229 206,179 Investments in regional nuclear generating companies, at equity................................ 82,464 81,029 Investments in transmission companies, at equity..... 26,106 26,536 Other, at cost....................................... 40,896 36,882 ------------ ------------ 389,695 350,626 ------------ ------------ Current Assets: Cash................................................. 34,579 32,008 Receivables, less accumulated provision for uncollectible accounts of $16,826,000 in 1994 and $14,629,000 in 1993............................. 357,322 357,449 Accrued utility revenues............................. 142,788 150,794 Fuel, materials, and supplies, at average cost....... 190,062 194,968 Prepayments and other................................ 54,886 35,278 ------------ ------------ 779,637 770,497 ------------ ------------ Deferred Charges: Regulatory Assets (Note 1H)..................... 2,724,364 2,801,283 Unamortized debt expense............................. 33,517 37,444 Other................................................ 54,220 38,653 ------------ ------------ 2,812,101 2,877,380 ------------ ------------ Total Assets........................................... $10,584,880 $10,668,164 ============ ============
The accompanying notes are an integral part of these financial statements. NORTHEAST UTILITIES AND SUBSIDIARIES Consolidated Balance Sheets
At December 31, 1994 1993 --------------------------------------------------------------------------------- (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; 134,210,226 shares issued and 124,962,981 shares outstanding in 1994 and 134,207,025 shares issued and 124,326,836 shares outstanding in 1993................................ $ 671,051 $ 671,035 Capital surplus, paid in............................ 904,371 901,740 Deferred benefit plan--employee stock ownership plan (Note 6)........................ (213,324) (228,205) Retained earnings................................... 946,988 879,518 ------------ ------------ Total common shareholders' equity................. 2,309,086 2,224,088 Preferred stock not subject to mandatory redemption.. 234,700 239,700 Preferred stock subject to mandatory redemption...... 375,250 380,500 Long-term debt....................................... 3,942,005 4,045,468 ------------ ------------ Total capitalization.............................. 6,861,041 6,889,756 ------------ ------------ Obligations Under Capital Leases....................... 166,018 171,004 ------------ ------------ Current Liabilities: Notes payable to banks............................... 180,000 173,500 Commercial paper..................................... 10,000 - Long-term debt and preferred stock--current portion.. 174,948 420,142 Obligations under capital leases--current portion.... 73,103 72,756 Accounts payable..................................... 280,942 229,118 Accrued taxes........................................ 57,532 40,501 Accrued interest..................................... 70,639 69,682 Accrued pension benefits............................. 90,194 82,513 Other................................................ 98,296 83,853 ------------ ------------ 1,035,654 1,172,065 ------------ ------------ Deferred Credits: Accumulated deferred income taxes (Note 1I)..... 1,968,230 1,911,981 Accumulated deferred investment tax credits.......... 188,005 201,635 Deferred contract obligation--YAEC (Note 3)...... 157,147 132,826 Other................................................ 208,785 188,897 ------------ ------------ 2,522,167 2,435,339 ------------ ------------ Commitments and Contingencies (Note 7) Total Capitalization and Liabilities $10,584,880 $10,668,164 ============ ============
The accompanying notes are an integral part of these financial statements. NORTHEAST UTILITIES AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CAPITALIZATION
At December 31, 1994 1993 ---- ---- (Thousands of Dollars) COMMON SHAREHOLDERS' EQUITY (See Consolidated Balance Sheets)............. $2,309,086 $2,224,088 ---------- ---------- CUMULATIVE PREFERRED STOCK OF SUBSIDIARIES: $25 par value--authorized 36,600,000 shares at December 31, 1994 and 1993; 12,927,000 shares outstanding in 1994 and 13,220,000 shares in 1993 $50 par value--authorized 9,000,000 shares at December 31, 1994 and 1993; 5,424,000 shares outstanding in 1994 and 1993; $100 par value--authorized 1,000,000 shares at December 31, 1994 and 1993; 200,000 shares outstanding in 1994 and 1993 Current Redemption Current Shares Dividend Rates Prices (a) Outstanding -------------- ------------------ -------------- NOT SUBJECT TO MANDATORY REDEMPTION: $25 par value--Adjustable Rate $ 25.00 3,940,000..... 98,500 103,500 $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............... 234,700 239,700 ---------- ---------- SUBJECT TO MANDATORY REDEMPTION: (b) $25 par value--$1.90 to $2.65 $ 25.00 to $ 26.50 8,987,000..... 224,675 227,000 $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................... 379,675 382,000 Less: Preferred Stock to be redeemed within one year.................... 4,425 1,500 ---------- ---------- Preferred Stock Subject to Mandatory Redemption, Net.................... 375,250 380,500 ---------- ---------- LONG-TERM DEBT: (c) First Mortgage Bonds-- Maturity Interest Rate -------- ------------- 1994 4.25% to 4.50%......................................... - 182,000 1995 9.25%.................................................... 34,300 34,650 1996 8.875%................................................... 172,500 172,500 1997 5.625% to 7.625%........................................ 214,850 265,000 1998 6.50% to 9.17%......................................... 199,900 290,000 1999 5.50% to 7.25%......................................... 280,000 100,000 2000-2002 5.75% to 9.05%......................................... 700,000 875,000 2003-2004 6.125% to 7.75%......................................... 190,000 90,000 2016-2020 7.375% to 10.13%......................................... 20,000 303,569 2023-2025 7.375% to 8.50%.......................................... 480,000 225,000 ---------- ---------- Total First Mortgage Bonds .......................................... 2,291,550 2,537,719 ---------- ---------- Other Long-Term Debt--(d) Pollution Control Notes and Other Notes-- 1996 Adjustable Rate - Term Loan.............................. 141,000 235,000 2000 15.23% .................................................. 205,000 205,000 2005-2006 8.38% to 8.58%........................................... 236,000 245,000 2013-2016 Adjustable Rate.......................................... 23,400 23,400 2018-2020 7.17% and Adjustable Rate................................ 50,191 50,300 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........................ 1,577,376 1,680,485 Fees and interest due for spent fuel disposal costs (Note 1N)..... 174,934 168,055 Other.................................................................. 78,090 86,731 ---------- ---------- Total Other Long-Term Debt........................................... 1,830,400 1,935,271 ---------- ---------- Unamortized premium and discount, net ................................. (9,422) (8,880) ---------- ---------- Total Long-Term Debt.................................................. 4,112,528 4,464,110 Less amounts due within one year...................................... 170,523 418,642 ---------- ---------- Long-Term Debt, Net .................................................. 3,942,005 4,045,468 ---------- ---------- TOTAL CAPITALIZATION..................................................... $6,861,041 $6,889,756 ========== ========== 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 they were issued. Redemption prices reduce in future years. (b) Changes in Preferred Stock Subject to Mandatory Redemption: (Thousands of Dollars) Balance at January 1, 1992....... $ 170,394 Issues........................ 75,000 PSNH stock transferred........ 125,000 Reacquisitions and Retirements (16,894) ------- Balance at December 31, 1992..... 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 ======== The minimum sinking-fund provisions of the series subject to mandatory redemption aggregate approximately $5,300,000 in 1995 and 1996, $30,300,000 in 1997, $34,000,000 in 1998, and $50,000,000 in 1999. 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 would be prohibited from redemption or purchase of less than all of the preferred stock outstanding. (c) Long-term debt maturities and cash sinking-fund requirements, excluding fees and interest due for spent fuel disposal costs, on debt outstanding at December 31, 1994 for the years 1995 through 1999 are approximately $170,500,000, $265,200,000, $264,200,000, $239,600,000, and $371,900,000, respectively. In addition, there are annual 1 percent sinking- and improvement-fund requirements of approximately $16,000,000 for 1995, $15,600,000 for 1996 and 1997, $13,450,000 for 1998, and $13,150,000 for 1999. 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 their respective first mortgage bond indentures. In addition, CL&P and WMECO have secured $369,300,000 of pollution control notes with second mortgage liens on Millstone 1, junior to the liens of their respective first mortgage bond indentures. PSNH's two bank facilities, the Term Loan and the Revolving Credit Facility, have a second lien, junior to the lien of its first mortgage bond indenture, on all PSNH property located in New Hampshire. At December 31, 1994, the principal amount outstanding under the Term Loan was $141,000,000. At December 31, 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 Business Finance Authority (BFA) of the state of New Hampshire. Pursuant to these arrangements, the BFA issued five series of Pollution Control Revenue Bonds (PCRBs) and loaned the proceeds to PSNH. At December 31, 1994, $516,485,000 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 2.5 percent to 4.3 percent for 1994 and from 2.2 percent to 3.4 percent for 1993. The average effective interest rates for the PSNH Term Loan for 1994 and 1993 were approximately 5.2 percent and 4.3 percent, respectively. (e) On January 23, 1995, CL&P Capital, L.P., a subsidiary of CL&P, issued $100 million of 9.3 percent cumulative Monthly Income Preferred Securities to help finance the retirement of $125 million of CL&P preferred stock.
NORTHEAST UTILITIES AND SUBSIDIARIES Consolidated Statements Of Common Shareholders' Equity
-------------------------------------------------------------------------------------------- Deferred Benefit Capital Plan-- Common Surplus, ESOP Retained Shares(a) Paid In (Note 6) Earnings(b) Total -------------------------------------------------------------------------------------------- (Thousands of Dollars) Balance at January 1, 1992....... $596,271 $640,119 $ (175,000) $ 814,684 $1,876,074 Net income for 1992............ 256,054 256,054 Tax benefit of ESOP dividends.. 7,348 7,348 Cash dividends on common shares--$1.76 per share...... (229,074) (229,074) Loss on the retirement of preferred stock.............. (1,268) (1,268) Issuance of 11,417,305 common shares, $5 par value......... 57,087 204,440 261,527 Issuance of 3,191,489 common shares, $5 par value, to ESOP Trust................ 15,957 59,043 (75,000) - Allocation of benefits--ESOP... 9,601 9,601 Capital stock expenses, net.... (6,285) (6,285) --------- --------- ------------- ------------ ----------- Balance at December 31, 1992..... 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 ========= ========= ============= ============ =========== (a) As part of its acquistion of PSNH, NU issued 8,430,910 warrants to former PSNH Equity security holders. Each warrant, which will expire on June 5, 1997, entitles the holder to purchase one share of NU common at an exercise price of $24 per share. As of Decemer 31, 1994, 458,595 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, 1994, these restrictions totaled approximately $559.6 million.
The accompanying notes are an integral part of these financial statements. NORTHEAST UTILITIES AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES A. Principles of Consolidation Northeast Utilities (NU) is the parent company of the Northeast Utilities system (the system). The consolidated financial statements of the company include the accounts of all wholly owned subsidiaries. Significant intercompany transactions have been eliminated in consolidation. On June 5, 1992 (Acquisition Date), NU acquired PSNH. As part of this transaction, PSNH transferred its 35.6 percent ownership interest in the Seabrook nuclear power plant to NAEC. Effective with the Acquisition Date, the consolidated financial statements of the company include, on a prospective basis, the financial position, the results of operations, and the cash flows for PSNH and NAEC. For the 12 months ended December 31, 1994, 1993, and 1992, PSNH and NAEC increased NU's consolidated operating revenues by $869.8 million, $805.5 million, and $438.4 million, respectively. For the same periods, PSNH and NAEC increased NU's consolidated earnings for common shares by $94.7 million, $65.0 million, and $34.6 million, respectively. B. Change in Accounting for Property Taxes Certain subsidiaries of NU, including CL&P and WMECO, adopted a one-time change in the method of accounting for municipal property tax expense for their Connecticut properties. Most municipalities in Connecticut assess property values as of October 1. Before January 1, 1993, the system accrued Connecticut property tax expense over the period October 1 through September 30 based on the lien-date method. In the first quarter of 1993, these subsidiaries changed their method of accounting for Connecticut municipal property taxes to recognize the expense from July 1 through June 30, to match the payments and the services provided by the municipalities. This one-time change increased earnings for common shares and earnings per common share by approximately $51.7 million and $0.42, respectively, in 1993. C. Reclassifications Certain reclassifications of prior years' data have been made to conform with the current year's presentation. D. 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 to the participants substantially on the basis of their 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 7F, "Commitments and Contingencies- Purchased Power Arrangements." The YAEC 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, 1994 and 1993, plant-in-service included approximately $2.4 billion, and the accumulated provision for depreciation included approximately $525.9 million and $460.6 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: 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, 1994 and 1993, plant-in-service included approximately $881.0 million and $877.3 million, respectively, and the accumulated provision for depreciation included approximately $83.2 million and $66.4 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, approximating $26.1 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 7G, "Commitments and Contingencies-Hydro-Quebec," for additional information. E. 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. For nuclear production plants, the costs of removal, less salvage, that have been funded through external decommissioning trusts will be paid with funds from the trusts and charged to the accumulated reserve for decommissioning included in the accumulated provision for depreciation over the expected service life of the plants. See Note 3, "Nuclear Decommissioning," for additional information. The depreciation rates for the several classes of electric plant-in-service are equivalent to a composite rate of 3.7 percent in 1994, 3.6 percent in 1993, and 3.5 percent in 1992. F. 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. G. Revenues Other than 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. 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. H. Regulatory Accounting The operating companies of the system follow accounting policies that reflect the impact of the rate treatment of certain events or transactions that differ from generally accepted accounting principles for those events or transactions followed by nonregulated enterprises. Under regulatory accounting, assuming that future revenues are expected to be sufficient to provide recovery, regulators may permit incurred costs, normally treated as expenses, to be deferred and recovered in revenues at a later date. Regulatory accounting is unique in that the actions of a regulator can provide reasonable assurance of the existence of an asset. Regulators, through their actions, may also reduce or eliminate the value of an asset, or create a liability. If the economic entity no longer comes under the jurisdiction of a regulator or external forces, such as a move to a competitive environment, effectively limiting the influence of cost-of-service based rate regulation, the entity may be forced to abandon regulatory accounting, requiring a reexamination and potential write-off of net regulatory assets. The system operating companies continue to be subject to cost-of-service based rate regulation. Based on current regulation and recent regulatory decisions regarding competition in the system's markets, the company believes that its use of regulatory accounting is still appropriate. The components of regulatory assets are as follows: -------------------------------------------------------------------- At December 31, 1994 1993 -------------------------------------------------------------------- (Thousands of Dollars) Income taxes, net (Note 1I). . . $1,124,119 $1,183,716 Regulatory asset-PSNH (Note 1J). . . . . . . . . . . 678,974 769,498 Recoverable energy costs, net (Note 1K). . . . . . . . . . . 268,982 202,264 Deferred costs-nuclear plants (Note 1L). . . . . . . . . . . 233,145 271,337 Unrecovered contract obligation- YAEC (Note 3). . . . . . . . . 157,147 132,826 Deferred demand-side- management costs (Note 1M) . . 116,133 111,442 Other. . . . . . . . . . . . . . 145,864 130,200 ---------- ---------- $2,724,364 $2,801,283 ========== ========== 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 applicable regulatory commissions. See Consolidated Statements Of Income Taxes on page 27 for the components of income tax expense. In 1992, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes (SFAS 109). SFAS 109 supersedes previously issued income tax accounting standards. NU adopted SFAS 109, on a prospective basis, during the first quarter of 1993 and increased the net deferred tax obligation by $1.2 billion at that time. As it is probable that the increase in deferred tax liabilities will be recovered from customers through rates, NU also established a regulatory asset. The tax effect of temporary differences which give rise to the accumulated deferred tax obligation is as follows: ---------------------------------------------------------------------- At December 31, 1994 1993 ---------------------------------------------------------------------- (Thousands of Dollars) Accelerated depreciation and other plant-related differences . $1,495,323 $1,472,509 Net operating loss carryforwards. . (247,440) (270,612) Regulatory assets-income tax gross up. . . . . . . . . . . . . 393,117 424,997 Other . . . . . . . . . . . . . . . 327,230 285,087 ----------- ---------- $1,968,230 $1,911,981 =========== ========== At December 31, 1994, PSNH had a regular tax net operating loss (NOL) carryforward of approximately $726 million, and an Alternative Minimum Tax (AMT) NOL carryforward of $529 million, both to be used against PSNH's federal taxable income and expiring between the years 2000 and 2006. PSNH also had Investment Tax Credit (ITC) carryforwards of $54 million, which expire between the years 1995 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 $249 million of the NOL, $189 million of the AMT NOL, and $23 million of the ITC carryforwards are subject to this limitation. J. Regulatory Asset-PSNH The regulatory asset-PSNH represents the aggregate value placed by the 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 and the $700-million value assigned to Seabrook by the Rate Agreement. The regulatory asset-PSNH was valued at approximately $920.6 million on the Acquisition Date. The Rate Agreement provides for the recovery, through rates, of the amortization of the regulatory asset-PSNH with a return each year on the unamortized portion of the asset. The Rate Agreement provides that $425 million of the regulatory asset-PSNH 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. K. 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 have begun to recover these costs. 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 retroactive review and appropriate adjustment. 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. In the past two GUAC proceedings before the Connecticut Department of Public Utility Control (DPUC), the DPUC determined that CL&P overrecovered its fuel costs and offset the amount of the overrecovery against the GUAC balance. This has resulted in disallowances of GUAC recovery of $7.9 million for the 1992-1993 GUAC period and $7.8 million for the 1993-1994 GUAC period. CL&P has appealed the first decision and will appeal the second decision. At December 31, 1994, CL&P's recoverable energy costs were $61.0 million, including the D&D assessments of $37.4 million. 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 purchase power costs assumed in the Rate Agreement and PSNH's actual costs, which include the costs under the Seabrook Power Contract. 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 attempting to negotiate the rate orders mandating the purchase of high-cost NUG power. In September 1994, the NHPUC approved an amendment to the Rate Agreement allowing settlement agreements to be implemented with two NUGs. The two NUGs have given up their right to sell their output to PSNH in exchange for lump-sum cash payments of 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 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. At December 31, 1994, PSNH's recoverable energy costs included fuel and purchase power deferrals ($154.9 million), the deferred buyout ($39.8 million), and the D&D assessments ($0.3 million). For additional information, see Note 7B, "Commitments and Contingencies - Nuclear Performance." L. Deferred Costs-Nuclear Plants The system's operating companies are phasing into rates the recoverable portions of their investments in Millstone 3 and Seabrook 1 and are deferring costs as part of these phase-in plans. All plans are in compliance with SFAS No. 92, Regulated Enterprises-Accounting for Phase-in Plans. CL&P: As allowed by the DPUC, effective January 1, 1995, CL&P has placed into rate base its allowed investments in Millstone 3 and Seabrook 1 and is recovering deferrals and carrying charges on these units. As of December 31, 1994, $448.5 million of the deferred return, including carrying charges, has been recovered, and $101.6 million of the deferred return to date, plus carrying charges, remains to be recovered. Recovery will be completed by December 31, 1995 and August 31, 1996 for Millstone 3 and Seabrook 1, respectively. NAEC: As prescribed by the Rate Agreement, NAEC is phasing in its investment in Seabrook 1. As of December 31, 1994, the portion of the investment on which NAEC is entitled to earn a cash return was 70 percent and will increase by 15 percent in each of the next two years beginning May 1, 1995. From the Acquisition Date through December 31, 1994, NAEC recorded $131.5 million of deferred return on the excluded portion of its investment in Seabrook 1, which has been recorded in "Regulatory assets" on the Consolidated Balance Sheets. 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. M. Demand-side Management (DSM) CL&P's DSM costs are recovered in base rates through a Conservation Adjustment Mechanism (CAM). These costs are being recovered over periods ranging from four to eight years. On October 31, 1994, CL&P filed its 1995 CAM for 1995 DSM costs and programs. The filing proposes expenditures of $36.7 million with recovery over four years and a zero CAM rate. 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, 1994, fees due to the DOE for the disposal of prior-period fuel were approximately $174.9 million, including interest costs of $92.8 million. As of December 31, 1994, all fees had been collected through rates. O. 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 as a reduction of 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 or interest-rate caps will be deferred until realized. For further information on derivatives, see Note 8, "Derivative Financial Instruments." 2. LEASES CL&P and WMECO have entered into the Niantic Bay Fuel Trust (NBFT) capital lease agreement to finance up to $530 million of nuclear fuel for Millstone 1 and 2 and their shares of the nuclear fuel for Millstone 3. 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 $81,952,000 in 1994, $100,911,000 in 1993, and $81,376,000 in 1992. Interest included in capital lease rental payments was $14,881,000 in 1994, $16,525,000 in 1993, and $20,581,000 in 1992. Operating lease rental payments charged to operating expense were $20,118,000 in 1994, $22,630,000 in 1993, and $27,451,000 in 1992. 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, 1994, are provided on the next page. Capital Operating Year Leases Leases -------- --------- (Thousands of Dollars) 1995. . . . . . . . . . . . . $ 9,600 $ 23,300 1996. . . . . . . . . . . . . 8,700 20,600 1997. . . . . . . . . . . . . 8,000 18,000 1998. . . . . . . . . . . . . 7,900 10,400 1999. . . . . . . . . . . . . 7,500 7,900 After 1999. . . . . . . . . . 49,400 36,500 -------- -------- Future minimum lease payments . . . . . . . . . 91,100 $116,700 ======== Less amount representing interest . . . . . . . . . 44,800 -------- Present value of future minimum lease payments for other than nuclear fuel 46,300 Present value of future nuclear fuel lease payments. . . . 192,800 -------- Total. . . . . . . $239,100 ======== 3. NUCLEAR DECOMMISSIONING 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, which is currently under review by the New Hampshire Decommissioning Finance Committee, 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, technology, and inflation. The estimated cost of decommissioning Millstone 1 and 2, in year-end 1994 dollars, is $410.9 million and $330.0 million, respectively. The system's ownership share of the estimated cost of decommissioning Millstone 3 and Seabrook 1 (utilizing the currently approved decommissioning study), in year-end 1994 dollars, is $305.2 million and $152.8 million, respectively. These estimated costs have been levelized and assume after-tax earnings on the Millstone and Seabrook decommissioning funds of 6.5 percent and 6.1 percent, respectively. Future escalation rates in decommissioning costs for the Millstone units and for Seabrook 1 are assumed. 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 $33.5 million in 1994, $29.4 million in 1993, and $28.1 million in 1992. Nuclear decommissioning, as a cost of removal, is included in the accumulated provision for depreciation on the Consolidated Balance Sheets. At December 31, 1994, the balance in the accumulated reserve for decommissioning amounted to $278.0 million. See "Nuclear Decommissioning" in the Management's Discussion And Analysis for a discussion of changes being considered by the FASB related to accounting for decommissioning costs. CL&P and WMECO have established independent decommissioning trusts 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, 1994, CL&P, PSNH, and WMECO have collected, through rates, $173.4 million, $1.5 million, and $42.4 million, respectively, toward the future decommissioning costs of their share of the Millstone units, of which $179.7 million has been transferred to external decommissioning trusts. As of December 31, 1994, CL&P and NAEC (including pre-Acquisition Date payments made by PSNH) have paid approximately $1.2 million and $10.1 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. Due to NU's adoption, effective January 1, 1994, of SFAS 115, Accounting for Certain Investments in Debt and Equity Securities, 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. 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. Because allowances for decommissioning have increased significantly in recent years, customers in future years may need to increase their payments to offset the effects of any insufficient rate recoveries in previous years. 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. The system's ownership share of estimated costs, in year-end 1994 dollars, of decommissioning CY, MY, and VY are $177.4 million, $67.6 million, and $52.7 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 by CL&P, PSNH, and WMECO. YAEC has begun component removal activities related to the decommissioning of its nuclear facility. In June 1992, YAEC filed a rate filing to obtain FERC authorization to collect the closing and decommissioning costs and to recover the remaining investment in the YAEC nuclear power plant over the remaining period of the plant's Nuclear Regulatory Commission (NRC) operating license. The bulk of these costs has been agreed to by the YAEC joint owners and approved as a settlement by FERC. In October 1994, YAEC submitted a revised decommissioning cost estimate as part of its decommissioning plan with the NRC. Following the receipt of NRC approval, this estimate will be filed with the FERC. The revised estimate increased the system's ownership share of decommissioning YAEC's nuclear facility by approximately $36 million in January 1, 1994 dollars. At December 31, 1994, the estimated remaining costs, including decommissioning, amounted to $408.2 million, of which the system's share was approximately $157.1 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 $485 million. NU, CL&P, WMECO, Holyoke Water Power Company (HWP), Northeast Nuclear Energy Company (NNECO), and The Rocky River Realty Company (RRR) have established a revolving-credit facility with a group of 16 banks. Under this facility, the participating companies may borrow up to an aggregate of $360 million. Individual borrowing limits as of January 1, 1995 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 0.20 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 0.135 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, 1994 and 1993, there were $30.0 million and $22.5 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, 1994 and 1993, there were no borrowings under the agreement. The weighted average interest rates on notes payable to banks and commercial paper outstanding on December 31, 1994 were 6.2 percent and 6.4 percent, respectively. The weighted average interest rate on notes payable to banks outstanding on December 31, 1993 was 3.3 percent. 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 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, NU, CL&P, PSNH, WMECO, and NAEC were authorized, as of January 1, 1995, to incur short-term borrowings up to a maximum of $150 million, $325 million, $175 million, $60 million, and $50 million, respectively. 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 $7.7 million in 1994, $29.2 million in 1993, and $9.7 million in 1992. Pension costs for 1994 and 1993 included approximately $9.2 million and $27.7 million, respectively, related to work force-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, 1994 1993 1992 ---------------------------------------------------------------------- (Thousands of Dollars) Service cost . . . . . . . . $ 39,317 $ 59,068 $ 32,662 Interest cost. . . . . . . . 84,284 81,456 78,092 Return on plan assets. . . . 2,268 (176,798) (83,371) Net amortization . . . . . . (118,188) 65,447 (17,702) --------- --------- --------- Net pension cost.. . . . . . $ 7,681 $ 29,173 $ 9,681 ========= ========= ========= For calculating pension cost, the following assumptions were used: ---------------------------------------------------------------------- For the Years Ended December 31, 1994 1993 1992 ---------------------------------------------------------------------- Discount rate . . . . . . . . . . 7.75% 8.00% 8.41% Expected long-term rate of return. . . . . . . . . . . 8.50 8.50 9.00 Compensation/progression rate . . . . . . . . . . . . . 4.75 5.00 6.56 The following table represents the plan's funded status reconciled to the Consolidated Balance Sheets: ---------------------------------------------------------------------- At December 31, 1994 1993 ---------------------------------------------------------------------- (Thousands of Dollars) Accumulated benefit obligation, including vested benefits at December 31,1994 and 1993 of $815,646,000 and $817,421,000, respectively .. $ 893,653 $ 898,788 ========== ========== Projected benefit obligation. . . . $1,112,993 $1,141,271 Market value of plan assets . . . . 1,266,239 1,340,249 ---------- ---------- Market value in excess of projected benefit obligation. . . . . . . 153,246 198,978 Unrecognized transition amount. . . (15,191) (16,735) Unrecognized prior service costs. . 10,373 10,287 Unrecognized net gain . . . . . . . (238,622) (275,043) ---------- ---------- Accrued pension liability. . . . $ (90,194) $ (82,513) ========== ========== The following actuarial assumptions were used in calculating the plan's year-end funded status: ---------------------------------------------------------------------- At December 31, 1994 1993 ---------------------------------------------------------------------- Discount rate . . . . . . . . . . . 8.25% 7.75% Compensation/progression rate . . . 5.00 4.75 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. These benefits are available for employees leaving the system who are otherwise eligible to retire and have met specified service requirements. Effective January 1, 1993, the system adopted SFAS 106, Employer's Accounting for Postretirement Benefits Other Than Pensions on a prospective basis. Total health care and life insurance costs, part of which were deferred or charged to utility plant, approximated $47.6 million in 1994, $50.1 million in 1993, and $15.6 million in 1992. On January 1, 1993, the accumulated postretirement benefit obligation represented the system's transition obligation upon the adoption of SFAS 106. As allowed by SFAS 106, the system is amortizing its transition obligation of approximately $306 million over a 20-year period. 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. Certain subsidiaries of NU are funding SFAS 106 postretirement costs through external trusts. The subsidiaries are funding annually 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 following table represents the plan's funded status reconciled to the Consolidated Balance Sheets: ---------------------------------------------------------------------- At December 31, 1994 1993 ---------------------------------------------------------------------- (Thousands of Dollars) Accumulated postretirement benefit obligation of: Retirees. . . . . . . . . . . . . $ 251,448 $ 242,889 Fully eligible active employees 416 540 Active employees not eligible to retire. . . . . . . . . . . . 69,556 67,955 ---------- ---------- Total accumulated postretirement benefit obligation . . . . . . . . . 321,420 311,384 Market value of plan assets. . . . . . 26,406 12,642 ---------- ---------- Accumulated postretirement benefit obligation in excess of plan assets. . . . . . . . . . . . . (295,014) (298,742) Unrecognized transition amount. . . . . . . . . . . . . . . 272,417 287,551 Unrecognized net gain . . . . . . . . (4,772) (5,150) ---------- ---------- Accrued postretirement benefit liability . . . . . . . . . $(27,369) $ (16,341) ========== ========== The components of health care and life insurance costs are: ---------------------------------------------------------------------- For the Years Ended December 31, 1994 1993 ---------------------------------------------------------------------- (Thousands of Dollars) Service cost . . . . . . . . . . . . $ 7,418 $ 9,175 Interest cost. . . . . . . . . . . . 25,319 25,330 Return on plan assets. . . . . . . . 236 (220) Net amortization . . . . . . . . . . 14,581 15,855 ------- ------- Net health care and life insurance costs. . . . . . . . . . $47,554 $50,140 ======= ======= The following actuarial assumptions were used in calculating the plan's year-end funded status: ---------------------------------------------------------------------- At December 31, 1994 1993 ---------------------------------------------------------------------- Discount rate . . . . . . . . . . . . . . 8.00% 7.75% Long-term rate of return-health assets, net of tax. . . . . . . . . . . . . . . 5.00 5.00 Long-term rate of return-life assets. . . 8.50 8.50 Health care cost trend rate (a). . . . . 10.20 11.10 (a) The annual growth in per capita cost of covered health care benefits was assumed to decrease to 5.4 percent by 2002. 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, 1994 by $17.2 million and the aggregate of the service and interest cost components of net periodic postretirement benefit cost for the year then ended by $1.7 million. The trust holding the plan assets is subject to federal income taxes at a 35-percent tax rate. PSNH and WMECO are currently recovering SFAS 106 costs, including previously deferred costs. CL&P has received regulatory approval to defer SFAS 106 costs in excess of costs incurred on a pay-as-you-go basis. Deferral of such costs is permitted since it is expected that the period of recovery of deferred costs will be within the time frame established by the applicable accounting requirements. C. 401(k) Savings Plan The company also maintains a 401(k) Savings Plan for substantially all employees. This savings plan provides for employee contributions up to specified limits. The company's savings plan provides up to 3 percent of matching contributions. The matching contributions for the company for 1994, 1993, and 1992 were $12.1 million, $12.2 million, and $8.6 million,respectively. For further information on the 401(k) Savings Plan, see Note 6, "Employee Stock Ownership Plan." 6. 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 in 1991 and 1992 a total of $250 million principal amount of unsecured and amortizing notes, the proceeds of which were lent to the ESOP trust for purchase of approximately 10.8 million newly issued NU common shares from the company. NU makes principal and interest payments on the ESOP notes at the same rate that ESOP shares are allocated to employees. In 1994 and 1993, the ESOP trust issued approximately 664,000 and 530,000, respectively, of NU common shares, with costs of approximately $15.5 million and $14.0 million, respectively, to the 401(k) plan. As of December 31, 1994 and 1993, the total allocated ESOP shares were 1,547,219 and 899,284, respectively, and total unallocated ESOP shares were 9,215,904 and 9,880,189, respectively. The fair market value of unallocated ESOP shares as of December 31, 1994 and 1993 was approximately $199.3 million and $234.7 million, respectively. During 1994, the ESOP trust used approximately $23.3 million in dividends paid on NU common shares and $13.1 million in contributions from NU to meet principal and interest payments on ESOP notes. During the 12-month periods ending December 31, 1994 and 1993, the ESOP trust incurred approximately $20.0 million and $20.9 million, respectively, in interest expense. NU adopted the American Institute of Certified Public Accountant's Statement of Position 93-6, Employers' Accounting for Employee Stock Ownership Plans (SOP 93-6) in 1993. This new standard requires: (1) offsetting of ESOP tax benefits against income tax expense, (2) charging allocated ESOP dividends directly to retained earnings, (3) exclusion of unallocated ESOP dividends for financial reporting purposes, and (4) exclusion of unallocated ESOP shares from earnings-per-common share (EPS) calculations. The adoption of SOP 93-6 did not have a material impact on 1993 EPS; however, 1993 earnings for common shares decreased by approximately $19.9 million. Had the provisions of SOP 93-6 been applied to 1992 results of operations, the impact on EPS would not have been material; however, earnings for common shares would have decreased by $16.0 million. 7. COMMITMENTS AND CONTINGENCIES A. Construction Program The construction program is subject to periodic review and revision. Actual construction expenditures may vary from estimates due to factors such as revised load estimates, inflation, revised nuclear safety regulations, delays, difficulties in the licensing process, the availability and cost of capital, and the granting of timely and adequate rate relief by regulatory commissions, as well as actions by other regulatory bodies. The system companies currently forecast construction expenditures (including the allowance for funds used during construction) of approximately $1.2 billion for the years 1995-1999, including $253.7 million for 1995. In addition, the system companies estimate that nuclear fuel requirements, including nuclear fuel financed through the NBFT, will be $366.7 million for the years 1995-1999, including $67.9 million for 1995. 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. The Office of Consumer Counsel (OCC) appealed decisions favorable to the company in two dockets. For the one appeal decided, which related to a procedural issue, the OCC prevailed and the case has been remanded to the DPUC for further proceedings. The exposure under these two dockets is approximately $66 million. The DPUC has suspended a third docket, pending the outcome of one of the appeals. The exposure under this remaining docket is $26 million. Management believes that its actions with respect to these outages have been prudent, and it does not expect the outcome of the appeals to result in material disallowances. In October 1994, Millstone 2 began a planned refueling and maintenance outage that was originally scheduled for 63 days. The outage has encountered several unexpected difficulties which have lengthened the duration of the outage. The magnitude of the schedule impact is currently under review, but the unit is not expected to return to service before April 1995. CL&P and WMECO expect that replacement power costs in the range of $7 million and $1 million per month, respectively, will be attributable to the extension of the outage. Recovery of the costs related to this outage is subject to scrutiny by the DPUC and the Massachusetts Department of Public Utilities (DPU). C. PSNH Rate Agreement The Rate Agreement provided the financial basis for PSNH's Plan of Reorganization (the Plan). The Rate Agreement calls for seven successive 5.5 percent annual increases in PSNH's base rates for its charges to retail customers (the Fixed-Rate Period). The first increase was put into effect on January 1, 1990 and the remaining two increases are scheduled to be put into effect annually beginning on June 1, 1995. As discussed in Note 1K, "Summary of Significant Accounting Policies-Recoverable Energy Costs-PSNH," the FPPAC protects PSNH from changes in fuel and purchased power costs. Although the Rate Agreement provides an unusually high degree of certainty as to PSNH's retail rates for the next two years, it also entails a risk when sales are lower than anticipated or if PSNH should experience unexpected increases in its costs other than those for fuel and purchased power, since PSNH has agreed that it will not seek additional rate relief during the Fixed-Rate Period, except in limited circumstances. However, in order to provide protection from significant variations from the costs assumed in base rates over the Fixed-Rate Period, the Rate Agreement establishes a return on equity (ROE) collar to prevent PSNH from earning a ROE in excess of an upper limit or below a lower limit. To date, PSNH's ROE has been within the limits of the ROE collar. D. 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. Changing environmental requirements could hinder the construction of new generating units, transmission and distribution lines, substations, and other facilities. The cumulative long-term, economic 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 for which the system's subsidiaries expect to bear legal liability. In most cases, the extent of additional future environmental cleanup costs is 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, 1994, the liability recorded by the system for its estimated environmental remediation costs, excluding any possible insurance recoveries or recoveries from third parties, amounted to approximately $11 million. However, in the event that it becomes necessary to effect environmental remedies that are currently not considered probable, it is reasonably possible that the upper limit of the system's environmental liability range could increase to approximately $16 million. The system cannot estimate the potential liability for future claims 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. E. Nuclear Insurance Contingencies The Price-Anderson Act currently limits public liability from a single incident at a nuclear power plant to $8.9 billion. The first $200 million of liability would be provided by purchasing the maximum amount of commercially available insurance. Additional coverage of up to a total of $8.3 billion would be provided by an assessment of $75.5 million per incident, levied on each of the 110 nuclear units that are currently subject to the Secondary Financial Protection Program in the United States, subject to a maximum assessment of $10 million per incident per nuclear unit in any year. In addition, if the sum of all public liability claims and legal costs arising from any nuclear incident exceeds the maximum amount of financial protection, each reactor operator can be assessed an additional 5 percent, up to $3.8 million, or $415.3 million in total, for all 110 nuclear units. The maximum assessment is to be adjusted at least every five years to reflect inflationary changes. Based on the ownership interests in Millstone 1, 2, and 3 and in Seabrook 1, the system's maximum liability 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. Effective January 1, 1995, insurance was purchased from Nuclear Mutual Limited (NML) to cover the primary cost of repair, replacement, or decontamination of utility property resulting from insured occurrences with respect to the system's ownership interest in Millstone 1, 2, and 3 and in CY. All companies insured with NML are subject to retroactive assessments if losses exceed the accumulated funds available to NML. The maximum potential assessment against the system with respect to losses arising during the current policy year is approximately $16.6 million under the NML primary property insurance program. Insurance has been purchased from Nuclear Electric Insurance Limited (NEIL) to cover: (1) certain extra costs incurred in obtaining replacement power during prolonged accidental outages with respect to the system's ownership interests in Millstone 1, 2, and 3, Seabrook 1, and CY, and PSNH's Seabrook Power Contract with NAEC; and (2) the excess cost of repair, replacement, or decontamination or premature decommissioning of utility property resulting from insured occurrences with respect to the system's ownership interests in Millstone 1, 2, and 3, Seabrook 1, CY, MY, and VY. All companies insured with NEIL are subject to retroactive assessments if losses exceed the accumulated funds available to NEIL. The maximum potential assessments against the system with respect to losses arising during current policy years are approximately $10.8 million under the replacement power policies and $51.7 million under the excess property damage, decontamination, and decommissioning policies. Although the system 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 from American Nuclear Insurers/Mutual Atomic Energy Liability Underwriters, 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 $3.1 million per reactor. The maximum potential assessments against the system with respect to losses arising during the current policy period are approximately $13.3 million. F. Purchased Power Arrangements CL&P, PSNH, and WMECO purchase approximately 10 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 shares (or entitlement shares) of generating costs, which include depreciation, operation and maintenance 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 $154.3 million in 1994, $169.0 million in 1993, and $145.4 million in 1992. See Note 1D, "Summary of Significant Accounting Policies-Investments and Jointly Owned Electric Utility Plant," and Note 3, "Nuclear Decommissioning," for more information on the Yankee companies. CL&P, PSNH, and WMECO have entered into various arrangements for the purchase of capacity and energy from nonutility generators. Some of these arrangements have terms from 10 to 30 years and require the companies to purchase the energy at specified prices or formula rates. For the 12 months ended December 31, 1994, approximately 14 percent of system electricity requirements was met by nonutility generators. The total cost of purchases under these arrangements amounted to $435.0 million in 1994, $426.8 million in 1993, and $323.8 million in 1992. These costs are eventually recovered through the companies' rates. For additional information, see Note 1K, "Summary of Significant Accounting Policies-Recoverable Energy Costs-PSNH." PSNH entered into a buy-back agreement to purchase the capacity and energy of the New Hampshire Electric Cooperative, Inc.'s (NHEC) Seabrook share and to pay all of NHEC's Seabrook costs for a ten-year period, which began July 1, 1990. The total cost of purchases under this agreement was $15.7 million in 1994, $14.4 million in 1993, and $13.8 million in 1992. Part of these costs is collected currently though the FPPAC and part is 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. The estimated annual costs of the system's significant purchase power arrangements are as follows: ---------------------------------------------------------------------- 1995 1996 1997 1998 1999 ---------------------------------------------------------------------- (Millions of Dollars) Yankee Companies . . . . . . $168.5 $177.1 $158.4 $188.0 $180.5 Nonutility Generators . . . . . . $447.1 468.4 478.9 489.3 493.1 NHEC . . . . . . . . . $ 16.5 16.5 25.1 33.2 32.8 G. 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, their proportionate shares of the annual operation, maintenance, and capital costs of these facilities, which are currently forecast to be $171.9 million for the years 1995-1999, including $38.4 million for 1995. 8. 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, as well as a portion of the PSNH Variable-Rate Term Loan. During 1994, there were five outstanding contracts held by CL&P, PSNH, and WMECO covering $617 million of variable-rate debt, with terms ranging from one to three years. Two of the five contracts expired in 1994. The contracts entitle 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, and the PSNH Variable-Rate Term Loan exceed the three-month LIBOR rate. These contracts are settled on a quarterly basis. As of December 31, 1994, CL&P, PSNH, and WMECO had a total of $467 million in caps with maturities of one year, with a positive mark-to-market position of approximately $5.0 million. 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, 1994, CL&P had five outstanding agreements with a total notional value of approximately $126 million, and a positive mark-to-market position of approximately $3.1 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 both the interest-rate caps and fuel 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. 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 trusts: The carrying amounts approximate fair value. SFAS 115 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. As a result of the adoption of SFAS 115, the investments held in the company's nuclear decommissioning trusts decreased by approximately $5.5 million as of December 31, 1994, with a corresponding offset to the accumulated provision for depreciation. The $5.5 million decrease 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, 1994 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 2,151,744 Other long-term debt. . . . . . 1,830,400 1,811,627 ---------------------------------------------------------------------- Carrying Fair At December 31, 1993 Amount Value ---------------------------------------------------------------------- (Thousands of Dollars) Preferred stock not subject to mandatory redemption . . . . . $ 239,700 $ 202,826 Preferred stock subject to mandatory redemption . . . . . 382,000 407,990 Long-term debt - First Mortgage Bonds . . . . . 2,537,719 2,632,983 Other long-term debt . . . . . 1,935,271 2,055,433 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. NORTHEAST UTILITIES AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF QUARTERLY FINANCIAL DATA (UNAUDITED)
QUARTER ENDED 1994 March 31 June 30 September 30 December 31 -------- ------- ------------ ----------- (Thousands of Dollars, except per share data) Operating Revenues .............. $966,174 $854,627 $923,708 $898,233 ======== ======== ======== ======== Operating Income................. $159,559 $123,688 $135,882 $129,103 ======== ======== ======== ======== Net Income ...................... $ 95,888 $ 61,145 $ 65,029 $ 64,812 ======== ======== ======== ======== Earnings Per Common Share........ $ 0.77 $ 0.49 $ 0.52 $ 0.52 ======== ======== ======== ======== 1993 Operating Revenues .............. $958,192 $853,769 $915,239 $901,893 ======== ======== ======== ======== Operating Income................. $129,745 $ 94,059 $l07,772 $139,275 ======== ======== ======== ======== Net Income....................... $112,447 $ 14,759 $ 46,421 $ 76,326 ======== ======== ======== ======== Earnings Per Common Share ....... $ 0.91 $ 0.12 $ 0.37 $ 0.62 ======== ======== ======== ========
NORTHEAST UTILITIES AND SUBSIDIARIES CONSOLIDATED GENERAL OPERATING STATISTICS
1994 1993 1992(a) 1991 1990 ---- ---- ----------- ---- ---- System Capability-MW (b)... 8,494.8 7,795.3 7,823.2 5,916.2 5,909.6 System Peak Demand-MW.......... 6,338.5 6,191.0 5,781.0 4,999.8 4,753.9 Nuclear Capacity-MW(b)..... 3,272.6 3,110.0 2,981.1 2,380.0 2,459.5 Nuclear Capacity Factor(c)................ 67.5 80.8 63.7 50.6 69.4 Nuclear Contribution to Total Energy Requirements (%) (b) 54.0 62.1 48.5 43.5 57.5 (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 the system's entitlements in regional nuclear generating companies, net of capacity sales and purchases. (c) Represents the average capacity factor for the nuclear units operated by the NU system.
NORTHEAST UTILITIES AND SUBSIDIARIES SELECTED CONSOLIDATED FINANCIAL DATA
1994 1993 1992(a) 1991 ---- ---- ------------ ---- (Thousands of Dollars, except percentages and share data) BALANCE SHEET DATA: Net Utility Plant- Continuing Operations ............... $ 6,603,447 $ 6,669,661 $ 6,719,652 $ 5,257,567 Discontinued Gas Plant............... -- -- -- -- Total Assets ......................... 10,584,880 10,668,164 9,724,340 6,781,746 Total Capitalization (b).......... 7,035,989 7,309,898 7,421,592 5,138,426 Obligations Under Capital Leases (b) 239,121 243,760 266,100 279,729 INCOME DATA: Continuing Operations: Operating Revenues................... $ 3,642,742 $ 3,629,093 $ 3,216,874 $ 2,753,803 Net Income....................... 286,874 249,953(c) 256,054 236,709 Earnings per Common Share........ $2.30 $2.02(c) $2.02 $2.12 Discontinued Gas Operations: Operating Revenues................... $ -- $ -- $ -- $ -- Net Income........................... -- -- -- -- Earnings per Common Share ........... $ -- $ -- $ -- $ -- COMMON SHARE DATA: Earnings per Share............... $2.30 $2.02(c) $2.02 $2.12 Dividends per Share ................. $1.76 $1.76 $1.76 $1.76 Payout Ratio (%)..................... 76.5 87.1 87.1 83.0 Number of Shares Outstanding--Average............ 124,678,192 123,947,631(d)130,403,488 111,453,550 Market Price--High................... $25 3/4 $28 7/8 $26 3/4 $24 3/8 Market Price--Low.................... $20 3/8 $22 $22 1/2 $19 Market Price--Closing Price (end of year) ..................... $21 5/8 $23 3/4 $26 l/2 $23 5/8 Book Value per Share(end of year).... $18.47 $17.89 $16.24 $15.73 Rate of Return Earned on Average Common Equity (%) ................. 12.7 11.4 12.7 13.0 Dividend Yield (end of year) (%) .... 8.1 7.4 6.6 7.4 Market-to-Book Ratio (end of year)... 1.2 1.3 1.6 1.5 Price-Earnings Ratio (end of year)... 9.4 11.8 13.1 11.1 CAPITALIZATION: (b) Common Shareholders' Equity......... $ 2,309,086 2,224,088 $ 2,173,977 $ 1,876,074 Preferred Stock Not Subject to Mandatory Redemption........... 234,700 239,700 304,696 394,695 Preferred Stock Subject to Mandatory Redemption ............. 379,675 382,000 353,500 170,394 Long-Term Debt...................... 4,112,528 4,464,110 4,589,419 2,697,263 ----------- ---------- ----------- ----------- Total Capitalization ............... $ 7,035,989 $7,309,898 $ 7,421,592 $ 5,138,426 =========== ========== =========== =========== (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 portions due within one year. (c) 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. (d) Decrease in the number of shares results from a change in accounting for Employee Stock Ownership Plan shares.
1990 1989 1988 1987 ---- ---- ---- ---- (Thousands of Dollars, except percentages and share data) BALANCE SHEET DATA: Net Utility Plant-- Continuing Operations................ $ 5,265,168 $ 5,237,805 $ 5,267,629 $ 5,229,242 Discontinued Gas Plant .............. -- -- 254,587 237,903 Total Assets ........................ 6,601,371 6,523,202 6,764,608 6,663,794 Total Capitalization (b).......... 4,965,859 4,954,083 5,123,504 4,956,080 Obligations Under Capital Leases (b) 319,548 341,246 410,352 432,714 INCOME DATA: Continuing Operations: Operating Revenues................... $ 2,616,319 $ 2,473,571 $ 2,268,607 $ 2,038,554 Net Income........................... 211,007 203,225 224,844 214,529 Earnings per Common Share............ $1.94 $1.87 $2.07 $1.97 Discontinued Gas Operations: Operating Revenues................... $ -- $ 124,229 $ 200,243 $ 202,816 Net Income........................... -- 5,858 9,078 14,616 Earnings per Common Share ........... $ -- $0.05 $0.08 $0.14 COMMON SHARE DATA: Earnings per Share................... $1.94 $1.92 $2.15 $2.11 Dividends per Share ................. $1.76 $1.76 $1.76 $1.76 Payout Ratio (%)..................... 90.7 91.7 81.9 83.4 Number of Shares Outstanding--Average................ 109,003,818 108,669,106 108,669,106 108,669,106 Market Price--High................... $22 5/8 $23 $23 1/8 $28 Market Price--Low.................... $17 7/8 $18 1/2 $18 1/4 $18 Market Price--Closing Price (end of year) ..................... $20 $22 1/2 $19 7/8 $20 1/4 Book Value per Share(end of year).... $16.34 $16.13 $16.90 $16.53 Rate of Return Earned on Average Common Equity (%) ................. 12.0 11.8 13.0 12.8 Dividend Yield (end of year) (%) .... 8.8 7.8 8.9 8.7 Market-to-Book Ratio (end of year)... 1.2 1.4 1.2 1.2 Price-Earnings Ratio (end of year)... 10.3 11.7 9.2 9.6 CAPITALIZATION: (b) Common Shareholders' Equity......... $ 1,790,758 $ 1,752,395 $ 1,837,034 $ 1,796,293 Preferred Stock Not Subject to Mandatory Redemption........... 394,695 394,695 344,695 291,195 Preferred Stock Subject to Mandatory Redemption ............. 176,892 181,892 111,832 205,832 Long-Term Debt...................... 2,603,514 2,625,101 2,829,943 2,662,760 ----------- ----------- ------------ ------------ Total Capitalization ............... $ 4,965,859 $ 4,954,083 $ 5,123,504 $ 4,956,080 =========== =========== ============ ============
1986 1985 ---- ---- (Thousands of Dollars, except percentages and share data) BALANCE SHEET DATA: Net Utility Plant-- Continuing Operations................ $ 5,120,812 $ 5,204,687 Discontinued Gas Plant .............. 224,581 214,115 Total Assets ......................... 6,299,755 6,147,720 Total Capitalization ................. 4,743,914 4,681,995 Obligations Under Capital Leases(b) 441,183 440,587 INCOME DATA: Continuing Operations: Operating Revenues................... $ 2,006,842 $ 1,969,225 Net Income........................... 171,234 277,768 Earnings per Common Share............ $1.58 $2.62 Discontinued Gas Operations: Operating Revenues................... $ 203,814 $ 220,010 Net Income........................... 10,705 10,773 Earnings per Common Share ........... $0.10 $0.10 COMMON SHARE DATA: Earnings per Share................... $1.68 $2.72 Dividends per Share ................. $1.68 $1.58 Payout Ratio (%)..................... 100.0 58.1 Number of Shares Outstanding--Average............... 108,352,517 106,221,131 Market Price--High.................. $28 1/4 $18 3/4 Market Price--Low.................... $17 3/8 $13 3/4 Market Price--Closing Price (end of year) ..................... $24 1/4 $17 3/4 Book Value per Share(end of year).... $16.24 $16.21 Rate of Return Earned on Average Common Equity (%) ................. 10.4 17.4 Dividend Yield (end of year) (%) .... 6.9 8.9 Market-to-Book Ratio (end of year)... 1.5 1.1 Price-Earnings Ratio (end of year)... 14.4 6.5 CAPITALIZATION: (b) Common Shareholders' Equity......... $ 1,765,090 $ 1,738,871 Preferred Stock Not Subject to Mandatory Redemption........... 291,195 291,195 Preferred Stock Subject to Mandatory Redemption ............. 166,832 185,833 Long-Term Debt...................... 2,520,797 2,466,096 ------------ ----------- Total Capitalization ............... $ 4,743,914 $ 4,681,995 ============ ===========
CONSOLIDATED ELECTRIC OPERATING STATISTICS
1994 1993 1992(a) 1991 ---- ---- ----------- ---- SOURCE OF ELECTRIC ENERGY: (kWh-millions) (b) Nuclear--Steam........................ 19,444 22,965 15,520 11,062 Fossil--Steam......................... 8,292 7,676 6,784 6,179 Hydro--Conventional................... 1,239 1,140 1,076 994 Hydro--Pumped Storage................. 1,195 1,269 1,221 1,173 Internal Combustion................... 13 8 9 25 Energy Used for Pumping .............. (1,629) (1,749) (1,671) (1,605) ------ ------ ------ ------ Net Generation..................... 28,554 31,309 22,939 17,828 Purchased and Net Interchange......... 14,027 10,499 14,165 13,430 Company Use and Unaccounted for ...... (2,422) (2,591) (2,028) (1,958) ------ ------ ------ ------ Net Energy Sold.................... 40,159 39,217 35,076 29,300 ====== ====== ====== ====== REVENUE: (thousands) Residential........................... $1,437,764 $1,385,818 $1,213,140 $ 995,098 Commercial........................ 1,174,658(c) 1,043,125 943,832 828,117 Industrial........................ 560,086(c) 649,876 554,587 419,003 Other Utilities ...................... 330,511 383,129 346,791 366,231 Streetlighting and Railroads.......... 45,579 45,480 43,296 38,656 Miscellaneous......................... 36,134 60,008 59,465 49,539 ---------- ---------- ---------- ---------- Total Electric ................... 3,584,732 3,567,436 3,161,111 2,696,644 Other............................. 58,010 61,657 55,763 57,159 ---------- ---------- ---------- ---------- Total............................. $3,642,742 $3,629,093 $3,216,874 $2,753,803 ========== ========== ========== ========== SALES: (kWh-millions) Residential.......................... 12,322 11,988 10,839 9,518 Commercial....................... 11,666(c) 10,304 9,608 8,900 Industrial....................... 6,738(c) 7,572 6,593 5,208 Other Utilities ..................... 9,121 9,046 7,733 5,388 Streetlighting and Railroads......... 312 307 303 286 ------ ------ ------ ------ Total............................ 40,159 39,217 35,076 29,300 ====== ====== ====== ====== CUSTOMERS: (average) Residential......................... 1,513,987 1,503,182 1,351,019 1,150,357 Commercial...................... 154,703(c) 155,487 132,680 102,867 Industrial...................... 7,813(c) 6,272 5,774 5,067 Other............................... 3,818 3,793 3,581 3,305 --------- --------- --------- --------- Total............................ 1,680,321 1,668,734 1,493,054 1,261,596 ========= ========= ========= ========= AVERAGE ANNUAL USE PER RESIDENTIAL CUSTOMER (kWh)...................... 8,152 7,987 8,129 8,285 AVERAGE ANNUAL BILL PER RESIDENTIAL CUSTOMER............................ $951.19 $923.32 $909.80 $866.20 AVERAGE REVENUE PER kWh: Residential......................... 11.67 cents 11.56 cents 11.19 cents 10.45 cents Commercial.......................... 10.07 10.12 9.82 9.30 Industrial.......................... 8.31 8.58 8.41 8.05 (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) Generated in system and regional nuclear generating plants. (c) Effective January 1, 1994, approximately 1,300 former commercial customers were reclassified as industrial customers.
1990 ---- SOURCE OF ELECTRIC ENERGY: (kWh-millions) (b) Nuclear--Steam........................ 17,724 Fossil--Steam......................... 6,829 Hydro--Conventional................... 1,174 Hydro--Pumped Storage................. 1,250 Internal Combustion................... 11 Energy Used for Pumping .............. (1,688) ------ Net Generation..................... 25,300 Purchased and Net Interchange......... 6,249 Company Use and Unaccounted for ...... (1,938) ------ Net Energy Sold.................... 29,611 ====== REVENUE: (thousands) Residential........................... $ 938,032 Commercial............................ 788,478 Industrial............................ 410,125 Other Utilities ...................... 346,087 Streetlighting and Railroads.......... 37,195 Miscellaneous......................... 42,882 ---------- Total Electric ................... 2,562,799 Other................................. 53,520 ---------- Total............................. $2,616,319 ========== SALES: (kWh-millions) Residential.......................... 9,500 Commercial........................... 8,981 Industrial........................... 5,448 Other Utilities ..................... 5,394 Streetlighting and Railroads......... 288 ------ Total............................ 29,611 ====== CUSTOMERS: (average) Residential......................... 1,145,142 Commercial.......................... 102,900 Industrial.......................... 5,114 Other............................... 3,283 --------- Total............................ 1,256,439 ========= AVERAGE ANNUAL USE PER RESIDENTIAL CUSTOMER (kWh)...................... 8,304 AVERAGE ANNUAL BILL PER RESIDENTIAL CUSTOMER............................ $819.94 AVERAGE REVENUE PER kWh: Residential......................... 9.87 cents Commercial.......................... 8.78 Industrial.......................... 7.53
EX-13.2 17 Exhibit 13.2 1994 ANNUAL REPORT THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES -------------------------------------------------------- 1994 Annual Report The Connecticut Light and Power Company and Subsidiaries Index Contents Page -------- ---- Consolidated Balance Sheets.......................... 1-2 Consolidated Statements of Income.................... 3 Consolidated Statements of Cash Flows................ 4 Consolidated Statements of Common Stockholder's Equity 5 Notes to Consolidated Financial Statements........... 6-30 Report of Independent Public Accountants............. 31 Management's Discussion and Analysis of Financial Condition and Results of Operations................ 32-39 Selected Financial Data.............................. 40 Statements of Quarterly Financial Data............... 40 Statistics........................................... 41 Preferred Stockholder and Bondholder Information..... Back Cover THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS
------------------------------------------------------------------------------------ At December 31, 1994 1993 ------------------------------------------------------------------------------------ (Thousands of Dollars) ASSETS ------ Utility Plant, at original cost: Electric................................................ $6,063,179 $5,936,346 Less: Accumulated provision for depreciation......... 2,194,314 2,010,962 ----------- ----------- 3,868,865 3,925,384 Construction work in progress........................... 99,993 121,177 Nuclear fuel, net....................................... 164,795 156,878 ----------- ----------- Total net utility plant............................. 4,133,653 4,203,439 ----------- ----------- Other Property and Investments: Nuclear decommissioning trusts, at market in 1994 and at cost in 1993 (Note 12)......................... 171,950 147,657 Investments in regional nuclear generating companies, at equity................................... 54,952 53,910 Other, at cost.......................................... 14,742 14,191 ----------- ----------- 241,644 215,758 ----------- ----------- Current Assets: Cash.................................................... 2,017 2,340 Receivables, less accumulated provision for uncollectible accounts of $12,778,000 in 1994 and $10,816,000 in 1993................................ 192,926 210,805 Accounts receivable from affiliated companies........... 9,367 29,687 Accrued utility revenues................................ 90,475 97,662 Fuel, materials, and supplies, at average cost.......... 64,003 60,247 Prepayments and other................................... 54,215 43,682 ----------- ----------- 413,003 444,423 ----------- ----------- Deferred Charges: Regulatory assets (Note 1H)........................ 1,410,334 1,517,943 Unamortized debt expense................................ 8,396 8,971 Other................................................... 10,427 6,871 ----------- ----------- 1,429,157 1,533,785 ----------- ----------- Total Assets........................................ $6,217,457 $6,397,405 =========== ===========
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, 1994 1993 ---------------------------------------------------------------------------------- (Thousands of Dollars) CAPITALIZATION AND LIABILITIES ------------------------------ Capitalization: Common stock--$10 par value. Authorized 24,500,000 shares; outstanding 12,222,930 shares in 1994 and 1993.............................. $ 122,229 $ 122,229 Capital surplus, paid in.............................. 632,117 630,271 Retained earnings..................................... 765,724 750,719 ----------- ----------- Total common stockholder's equity............ 1,520,070 1,503,219 Cumulative preferred stock-- $50 par value - authorized 9,000,000 shares; outstanding 5,424,000 shares in 1994 and in 1993 $25 par value - authorized 8,000,000 shares; outstanding 5,000,000 shares in 1994 and in 1993 Not subject to mandatory redemption (Note 5).... 166,200 166,200 Subject to mandatory redemption (Note 6)........ 226,250 230,000 Long-term debt (Note 7)........................... 1,815,579 1,743,260 ----------- ----------- Total capitalization......................... 3,728,099 3,642,679 ----------- ----------- Obligations Under Capital Leases........................ 120,268 121,892 ----------- ----------- Current Liabilities: Notes payable to banks................................ 76,000 95,000 Notes payable to affiliated company................... 92,750 1,250 Commercial paper...................................... 10,000 - Long-term debt and preferred stock--current portion.............................................. 11,861 314,020 Obligations under capital leases--current portion.............................................. 55,701 55,526 Accounts payable...................................... 102,837 117,858 Accounts payable to affiliated companies.............. 43,033 52,179 Accrued taxes......................................... 26,413 36,139 Accrued interest...................................... 30,682 29,669 Other................................................. 22,828 32,287 ----------- ----------- 472,105 733,928 ----------- ----------- Deferred Credits: Accumulated deferred income taxes (Note 1I)...... 1,544,021 1,575,965 Accumulated deferred investment tax credits........... 150,087 154,701 Deferred contract obligation--YAEC (Note 3)....... 100,003 84,526 Other................................................. 102,874 83,714 ----------- ----------- 1,896,985 1,898,906 ----------- ----------- Commitments and Contingencies (Note 10) Total Capitalization and Liabilities......... $6,217,457 $6,397,405 =========== ===========
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, 1994 1993 1992 -------------------------------------------------------------------------------------- (Thousands of Dollars) Operating Revenues................................ $2,328,052 $2,366,050 $2,316,451 ----------- ----------- ----------- Operating Expenses: Operation -- Fuel, purchased and net interchange power.... 568,394 657,121 598,287 Other........................................ 593,851 641,402 605,675 Maintenance..................................... 207,003 180,403 197,460 Depreciation.................................... 231,155 219,776 209,884 Amortization of regulatory assets, net.......... 77,384 112,353 73,456 Federal and state income taxes (Note 8)..... 195,038 144,547 172,236 Taxes other than income taxes................... 173,068 170,353 171,642 ----------- ----------- ----------- Total operating expenses.................. 2,045,893 2,125,955 2,028,640 ----------- ----------- ----------- Operating Income.................................. 282,159 240,095 287,811 ----------- ----------- ----------- Other Income: Deferred nuclear plants return--other funds (Note 1K).......................... 13,373 23,537 35,396 Equity in earnings of regional nuclear generating companies.......................... 7,453 6,193 8,014 Other, net...................................... 5,136 (1,044) 6,964 Income taxes--credit............................ 9,037 4,859 11,171 ----------- ----------- ----------- Other income, net......................... 34,999 33,545 61,545 ----------- ----------- ----------- Income before interest charges............ 317,158 273,640 349,356 ----------- ----------- ----------- Interest Charges: Interest on long-term debt...................... 119,927 134,263 151,314 Other interest.................................. 6,378 9,654 4,205 Deferred nuclear plants return--borrowed funds (Note 1K).......................... (7,435) (13,979) (12,877) ----------- ----------- ----------- Interest charges, net..................... 118,870 129,938 142,642 ----------- ----------- ----------- Income before cumulative effect of accounting change............................... 198,288 143,702 206,714 Cumulative effect of accounting change (Note 1B).................................. - 47,747 - ----------- ----------- ----------- Net Income........................................ $ 198,288 $ 191,449 $ 206,714 =========== =========== ===========
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, 1994 1993 1992 ------------------------------------------------------------------------------------------------- (Thousands of Dollars) Cash Flows From Operating Activities: Net Income................................................ $ 198,288 $ 191,449 $ 206,714 Adjustments to reconcile to net cash from operating activities: Depreciation............................................ 231,155 219,776 209,884 Deferred income taxes and investment tax credits, net... 37,664 (20,188) 72,138 Deferred nuclear plants return, net of amortization..... 82,651 58,740 10,071 Recoverable energy costs, net of amortization........... 3,975 125,579 (64,138) Deferred demand-side management, net of amortization.... (4,691) (23,955) (31,989) Other sources of cash................................... 35,464 80,831 26,430 Other uses of cash...................................... (41,518) (23,544) (34,589) Changes in working capital: Receivables and accrued utility revenues................ 45,386 (9,370) 245 Fuel, materials, and supplies........................... (3,756) 11,951 1,296 Accounts payable........................................ (24,167) 5,433 (18,067) Accrued taxes........................................... (9,726) (82,018) 15,344 Other working capital (excludes cash)................... (18,403) 9,754 7,154 ----------- ----------- ----------- Net cash flows from operating activities.................... 532,322 544,438 400,493 ----------- ----------- ----------- Cash Flows From Financing Activities: Issuance of long-term debt................................ 535,000 740,500 491,000 Issuance of preferred stock............................... - 80,000 75,000 Net increase (decrease) in short-term debt................ 82,500 (109,490) 15,240 Reacquisitions and retirements of long-term debt.......... (774,020) (771,973) (431,232) Reacquisitions and retirements of preferred stock......... - (114,996) (91,891) Cash dividends on preferred stock......................... (23,895) (29,182) (31,977) Cash dividends on common stock............................ (159,388) (160,365) (164,277) ----------- ----------- ----------- Net cash flows used for financing activities................ (339,803) (365,506) (138,137) ----------- ----------- ----------- Investment Activities: Investment in plant: Electric utility plant.................................. (149,889) (149,308) (225,901) Nuclear fuel............................................ (20,905) (13,658) 3,139 ----------- ----------- ----------- Net cash flows used for investments in plant.............. (170,794) (162,966) (222,762) Other investment activities, net.......................... (22,048) (25,787) (32,181) ----------- ----------- ----------- Net cash flows used for investments......................... (192,842) (188,753) (254,943) ----------- ----------- ----------- Net (Decrease) Increase In Cash For The Period.............. (323) (9,821) 7,413 Cash - beginning of period.................................. 2,340 12,161 4,748 ----------- ----------- ----------- Cash - end of period........................................ $ 2,017 $ 2,340 $ 12,161 =========== =========== =========== Supplemental Cash Flow Information: Cash paid during the year for: Interest, net of amounts capitalized during construction.. $ 115,120 $ 130,592 $ 143,957 =========== =========== =========== Income taxes.............................................. $ 161,513 $ 149,056 $ 95,199 =========== =========== =========== Increase in obligations: Niantic Bay Fuel Trust.................................... $ 52,353 $ 40,140 $ 30,948 =========== =========== ===========
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, 1992.......... $122,229 $637,202 $ 738,993 $1,498,424 Net income for 1992............. 206,714 206,714 Cash dividends on preferred stock......................... (31,977) (31,977) Cash dividends on common stock.. (164,277) (164,277) Loss on the retirement of preferred stock............... (636) (636) Capital stock expenses, net..... (2,351) (2,351) --------- --------- ---------- ----------- Balance at December 31, 1992........ 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 ========= ========= ========== ===========
(a) The company has dividend restrictions imposed by its long-term debt agreements. At December 31, 1994, these restrictions totaled approximately $540 million. The accompanying notes are an integral part of these financial statements. THE CONNECTICUT LIGHT AND POWER COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES A. PRINCIPLES OF CONSOLIDATION 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). 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. Commencing June 29, 1992, North Atlantic Energy Service Corporation (NAESCO) began acting 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. B. CHANGE IN ACCOUNTING FOR PROPERTY TAXES CL&P adopted a one-time change in the method of accounting for municipal property tax expense for its Connecticut properties. Most municipalities in Connecticut assess property values as of October 1. Before January 1, 1993, CL&P accrued Connecticut property tax expense over the period October 1 through September 30 based on the lien-date method. In the first quarter of 1993, CL&P changed its method of accounting for Connecticut municipal property taxes to recognize the expense from July 1 through June 30, to match the payments and the services provided by the municipalities. This one-time change increased earnings for common shares by approximately $47.7 million in 1993. C. RECLASSIFICATIONS Certain reclassifications of prior years' data have been made to conform with the current year's presentation. D. 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 to the participants substantially on the basis of their 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 - Purchased Power Arrangements." The YAEC 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 percent joint-ownership interest in Millstone 1, a 660-megawatt (MW) nuclear generating unit. As of December 31, 1994 and 1993, plant-in-service included approximately $370.9 million and $332 million, respectively, and the accumulated provision for depreciation included approximately $135.0 million and $130.8 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 percent joint-ownership interest in Millstone 2, an 870-MW nuclear generating unit. As of December 31, 1994 and 1993, plant-in-service included approximately $680.5 million and $676 million, respectively, and the accumulated provision for depreciation included approximately $175.2 million and $151.5 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, 1994 and 1993, plant-in-service included approximately $1.9 billion and the accumulated provision for depreciation included approximately $418.5 million and $366.6 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: CL&P has a 4.06 percent joint-ownership interest in Seabrook 1, a 1,148-MW nuclear generating unit. As of December 31, 1994 and 1993, plant-in-service included approximately $173.2 million and $173.4 million, respectively, and the accumulated provision for depreciation included approximately $20.1 million and $17.7 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. E. 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. For nuclear production plants, the costs of removal, less salvage, that have been funded through external decommissioning trusts will be paid with funds from the trusts and charged to the accumulated reserve for decommissioning included in the accumulated provision for depreciation over the expected service life of the plants. See Note 3, "Nuclear Decommissioning," for additional information. The depreciation rates for the several classes of electric plant-in-service are equivalent to a composite rate of 3.9 percent in 1994, 3.8 percent in 1993, and 3.7 percent in 1992. F. 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). G. REVENUES Other than 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. 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. H. REGULATORY ACCOUNTING CL&P follows accounting policies that reflect the impact of the rate treatment of certain events or transactions that differ from generally accepted accounting principles for those events or transactions followed by nonregulated enterprises. Under regulatory accounting, assuming that future revenues are expected to be sufficient to provide recovery, regulators may permit incurred costs, normally treated as expenses, to be deferred and recovered in revenues at a later date. Regulatory accounting is unique in that the actions of a regulator can provide reasonable assurance of the existence of an asset. Regulators, through their actions, may also reduce or eliminate the value of an asset, or create a liability. If the economic entity no longer comes under the jurisdiction of a regulator or external forces, such as a move to a competitive environment, effectively limiting the influence of cost-of-service based rate regulation, the entity may be forced to abandon regulatory accounting, requiring a reexamination and potential write-off of net regulatory assets. CL&P continues to be subject to cost-of-service based rate regulation. Based on current regulation, and recent regulatory decisions regarding competition in the company's market, CL&P believes that its use of regulatory accounting is still appropriate. The components of regulatory assets are as follows: At December 31, 1994 1993 ---------------------------------------------------------------------------- (Thousands of Dollars) Income taxes, net (Note 1I) $ 949,134 $1,026,046 Deferred demand-side-management costs (Note 1J) 116,133 111,442 Deferred costs-nuclear plants (Note 1K) 101,632 185,909 Unrecovered contract obligation-YAEC (Note 3) 100,003 84,526 Recoverable energy costs, net (Note 1L) 61,040 65,591 Cogeneration costs (Note 1N) 36,821 - Other 45,571 44,429 -------- -------- $1,410,334 $1,517,943 ========== ========== 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 applicable regulatory commissions. See Note 8, "Income Tax Expense," for the components of income tax expenses. In 1992, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes (SFAS 109). SFAS 109 supersedes previously issued income tax accounting standards. The company adopted SFAS 109, on a prospective basis, during the first quarter of 1993, and increased the net deferred tax obligation by $1.0 billion at that time. As it is probable that the increase in deferred tax liabilities will be recovered from customers through rates, CL&P also established a regulatory asset. The tax effect of temporary differences which give rise to the accumulated deferred tax obligation are as follows: At December 31, 1994 1993 ---------------------------------------------------------------- (Thousands of Dollars) Accelerated depreciation and other plant-related differences ........ $1,063,823 $1,049,849 Regulatory assets - income tax gross up 402,685 434,894 Other ................................ 77,513 91,222 ---------- ---------- $1,544,021 $1,575,965 ========== ========== J. DEMAND-SIDE-MANAGEMENT COSTS (DSM) CL&P's DSM costs are recovered in base rates through a Conservation Adjustment Mechanism (CAM). These costs are being recovered over periods ranging from four to eight years. On October 31, 1994, CL&P filed its 1995 CAM for 1995 DSM costs and programs. The filing proposes expenditures of $36.7 million with recovery over four years and a zero CAM rate. K. DEFERRED COSTS - NUCLEAR PLANTS CL&P is phasing into rates the recoverable portions of its investments in Millstone 3 and Seabrook 1. CL&P is deferring costs as part of its phase-in plans. Both plans are in compliance with SFAS No. 92, Regulated Enterprises - Accounting for Phase-in Plans. As allowed by the DPUC, effective January 1, 1995, CL&P placed into rate base its allowed investments in Millstone 3 and Seabrook 1 and is recovering deferrals and carrying charges on these units. As of December 31, 1994, $448.5 million of the deferred return, including carrying charges, has been recovered, and $101.6 million of the deferred return to date, plus carrying charges, remains to be recovered. Recovery will be completed by December 31, 1995 and August 31, 1996 for Millstone 3 and Seabrook 1, respectively. L. 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 has begun to recover these costs. 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 retroactive review and appropriate adjustment. 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. In the past two GUAC proceedings before the DPUC, the DPUC determined that CL&P overrecovered its fuel costs and offset the amount of the overrecovery against the GUAC balance. This has resulted in disallowances of GUAC recovery of $7.9 million for the 1992-1993 GUAC period and $7.8 million for the 1993-1994 GUAC period. CL&P has appealed the first decision and will appeal the second decision. At December 31, 1994, CL&P's recoverable energy costs were $61.0 million, including D&D assessments of $37.4 million. For additional information see Note 10B, "Commitments and Contingencies-Nuclear Performance." M. 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, 1994, fees due to the DOE for the disposal of prior-period fuel were approximately $141.7 million, including interest costs of $75.2 million. As of December 31, 1994, all fees had been collected through rates. N. COGENERATION COSTS CL&P, with the approval of the DPUC, began deferring certain cogeneration costs for future recovery beginning in 1994. At December 31, 1994, CL&P had deferred approximately $36.8 million in cogeneration costs. CL&P will begin recovery of these deferrals over five years beginning July 1, 1996. O. 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 as a reduction of 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 or interest-rate caps will be deferred until realized. For further information on derivatives, see Note 11, "Derivative Financial Instruments." 2. LEASES CL&P and WMECO have entered into the Niantic Bay Fuel Trust (NBFT) capital lease agreement to finance up to $530 million of nuclear fuel for Millstone 1 and 2 and their shares of the nuclear fuel for Millstone 3. 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: Capital Operating Year Leases Leases ---- ------------ ---------- 1994 ............ $60,975,000 $24,192,000 1993 ............ 76,606,000 24,355,000 1992 ............ 61,795,000 26,919,000 Interest included in capital lease rental payments was $10,228,000 in 1994, $11,298,000 in 1993, and $14,782,000 in 1992. 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, 1994, are as follows: Capital Operating Year Leases Leases ---- ------------ ---------- (Thousands of Dollars) 1995 $ 2,700 .....$ 19,500 1996 2,700 ........18,000 1997 2,700 ........16,500 1998 2,700 ........12,100 1999 2,700 ........10,400 After 1999 42,100 .... 61,900 ---------- --------- Future minimum lease payments 55,600 ......$138,400 ======== Less amount representing interest 35,900 -------- Present value of future minimum lease payments for other than nuclear fuel................. 19,700 Present value of future nuclear fuel lease payments.......... 156,300 --------- Total .............. $176,000 ======== 3. NUCLEAR DECOMMISSIONING 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, which is currently under review by the New Hampshire Decommissioning Finance Committee, 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, technology, and inflation. The estimated cost of decommissioning CL&P's ownership share of Millstone 1 and 2, in year-end 1994 dollars, is $332.8 million and $267.3 million, respectively. CL&P's ownership share of the estimated cost of decommissioning Millstone 3 and Seabrook 1 (utilizing the currently approved decommissioning study), in year-end 1994 dollars, is $237.5 million and $15.5 million, respectively. These estimated costs have been levelized and assume after-tax earnings on the Millstone and Seabrook 1 decommissioning funds of 6.5 percent and 6.1 percent, respectively. Future escalation rates in decommissioning costs for the Millstone units and for Seabrook 1 are assumed. 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 $25.6 million in 1994 and $21.9 million in 1993 and 1992. Nuclear decommissioning, as a cost of removal, is included in the accumulated provision for depreciation on the Consolidated Balance Sheets. At December 31, 1994, the balance in the accumulated reserve for decommissioning amounted to $209.7 million. See "Nuclear Decommissioning" in Management's Discussion and Analysis for a discussion of changes being considered by the FASB related to accounting for decommissioning costs. CL&P has established independent decommissioning trusts 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, 1994, CL&P has collected, through rates, $173.4 million, toward the future decommissioning costs of its share of the Millstone units, of which $135.9 million has been transferred to external decommissioning trusts. As of December 31, 1994, CL&P has paid approximately $1.2 million into Seabrook 1's decommissioning trust. Earnings on the decommissioning trusts increase the decommissioning trust balance and the accumulated reserve for decommissioning. Due to CL&P's adoption, effective January 1, 1994, of SFAS 115, Accounting for Certain Investments in Debt and Equity Securities, 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. 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. Because allowances for decommissioning have increased significantly in recent years, customers in future years may need to increase their payments to offset the effects of any insufficient rate recoveries in previous years. 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. The estimated costs, in year-end 1994 dollars, of decommissioning CL&P's ownership share of CY, MY, and VY are $124.9 million, $40.6 million, and $31.3 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 CL&P's cost of power. YAEC has begun component removal activities related to the decommissioning of its nuclear facility. In June 1992, YAEC filed a rate filing to obtain FERC authorization to collect the closing and decommissioning costs and to recover the remaining investment in the YAEC nuclear power plant, over the remaining period of the plant's Nuclear Regulatory Commission (NRC) operating license. The bulk of these costs has been agreed to by the YAEC joint owners and approved as a settlement, by FERC. In October 1994, YAEC submitted a revised decommissioning cost estimate as part of its decommissioning plan with the NRC. Following the receipt of NRC approval, this estimate will be filed with the FERC. The revised estimate increased CL&P's ownership share of decommissioning YAEC's nuclear facility by approximately $23.1 million in January 1, 1994 dollars. At December 31, 1994, the estimated remaining costs including decommissioning, amounted to $408.2 million, of which CL&P's share was approximately $100 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 a corresponding obligation, on its Consolidated Balance Sheets. 4. SHORT-TERM DEBT The system companies have various revolving credit lines, totalling $485 million. NU, CL&P, WMECO, HWP, NNECO, and The Rocky River Realty Company (RRR) have established a revolving-credit facility with a group of 16 banks. Under this facility, the participating companies may borrow up to an aggregate of $360 million. Individual borrowing limits as of January 1, 1995 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 0.20 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 0.135 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, 1994 and 1993, there were $30.0 million and $22.5 million of borrowings, respectively, under the facility, all of which had been borrowed by other system companies. At December 31, 1993, CL&P had $5 million in borrowings outstanding under this facility. The weighted average interest rates on notes payable to banks and commercial paper outstanding on December 31, 1994 were 6.2 percent and 6.4 percent, respectively. The weighted average interest rate on notes payable to banks outstanding on December 31, 1993 was 3.3 percent. 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. 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. Investing and borrowing subsidiaries receive or pay interest based on the average daily Federal Funds rate. At December 31, 1994 and 1993, CL&P had $92.8 million and $1.3 million, respectively, of borrowings outstanding from the Pool. The interest rate on borrowings from the Pool on December 31, 1994 and 1993 were 4.9 percent and 2.9 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 the company 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 1994 Outstanding Redemption December 31, December 31, ----------------------------- Description Price 1994 1994 1993 1992 ------------------------------------------------------------------------------------- (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 $3.80 Series J of 1971 - - - - 20,000 $4.48 Series H of 1970 - - - - 15,000 $4.48 Series I of 1970 - - - - 20,000 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 7.60% Series of 1971 - - - - 9,996 1989 Adjustable Rate DARTS $25.00 2,000,000 50,000 50,000 50,000 ------ ------ ------ Total preferred stock not subject to mandatory redemption $166,200 $166,200 $231,196 ======== ======== ========
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 dividends to the date of redemption. As of January 23, 1995, CL&P Capital, L.P., a subsidiary of CL&P, issued $100 million of 9.3 percent cumulative Monthly Income Preferred Securities to help finance the expected retirement of $125 million of CL&P preferred stock. 6. PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION Details of preferred stock subject to mandatory redemption are:
December 31, Shares 1994 Outstanding December 31, Redemption December 31, ---------------------------- Description Price* 1994 1994 1993 1992 ------------------------------------------------------------------------------------- (Thousands of Dollars) 9.10% Series of 1987 - - $ - $ - $ 50,000 9.00% Series of 1989 $26.50 3,000,000 75,000 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 - -------- -------- -------- 230,000 230,000 200,000 Less preferred stock to be redeemed within one year 3,750 - 2,500 -------- -------- -------- Total preferred stock subject to mandatory redemption $226,250 $230,000 $197,500 ======== ======== ========
*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 Shares Reacquired Sinking-Fund ------------------------------ Series Requirement 1994 1993 1992 ------------------------------------------------------------------------------------ (Thousands of Dollars) $5.52 Series L of 1975 $ - - - 38,524 11.52% Series of 1975 - - - 19,318 10.48% Series of 1980 - - - 280,000 9.10% Series of 1987 - - 2,000,000 - 9.00% Series of 1989 (1) 3,750 - - - 7.23% Series of 1992 (2) 3,750 - - - 5.30% Series of 1993 (3) 16,000 - - -
(1)Sinking fund requirements commence October 1, 1995. (2)Sinking fund requirements commence September 1, 1998. (3)Sinking fund requirements commence October 1, 1999. The minimum sinking-fund provisions of the series subject to mandatory redemption, for the years 1995 through 1999, aggregate approximately $3,750,000 in 1995, 1996, and 1997, $7,500,000 in 1998, and $23,500,000 in 1999. 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, ------------------------ 1994 1993 --------------------------------------------------------------------- (Thousands of Dollars) First Mortgage Bonds: Series 1964 due 1994 $ - 12,000 Series WW due 1994 - 170,000 Series 1967 due 1997 - 20,000 Series S due 1997 - 30,000 Series UU due 1997 200,000 200,000 Series U due 1998 - 40,000 Series 1968 due 1998 - 25,000 Series T due 1998 20,000 20,000 Series 1968 due 1998 - 10,000 Series VV due 1999 100,000 100,000 Series A due 1999 140,000 - Series XX due 2000 200,000 200,000 Series X due 2001 - 30,000 Series 1971 due 2001 - 30,000 Series 1972 due 2002 - 35,000 Series Y due 2002 - 50,000 Series Z due 2003 - 50,000 Series 1973 due 2003 - 40,000 Series B due 2004 140,000 - Series QQ due 2018 - 75,000 Series RR due 2019 - 75,000 Series SS due 2019 - 75,000 Series TT due 2019 20,000 20,000 Series YY due 2023 100,000 100,000 Series C due 2024 115,000 - Series D due 2024 140,000 - Series ZZ due 2025 125,000 125,000 ---------- ---------- Total First Mortgage Bonds 1,300,000 1,532,000 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 1M) 141,694 136,125 Other 28,398 35,417 Less amounts due within one year 8,111 314,020 Unamortized premium and discount, net (8,302) (8,162) ---------- ---------- Long-term debt, net $1,815,579 $1,743,260 ========== ========== Long-term debt maturities and cash sinking-fund requirements on debt outstanding at December 31, 1994 for the years 1995 through 1999 are approximately: $8,111,000, $9,372,000, $210,828,000, $20,011,000, and $240,005,000, respectively. In addition, there are annual one-percent sinking-and improvement-fund requirements, currently amounting to $13,000,000 for 1995, 1996 and 1997, $11,000,000 for 1998, and $10,800,000 for 1999. 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, 1994 and 1993, the company has secured $315.5 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 rates on the variable-rate pollution control notes ranged from 2.7 percent to 3.3 percent for 1994 and 2.4 percent to 2.7 percent for 1993. 8. INCOME TAX EXPENSE The components of the federal and state income tax provisions are:
For the Years Ended December 31, 1994 1993 (Note 1I) 1992 ----------------------------------------------------------------------------------------------- (Thousands of Dollars) Current income taxes: Federal $108,371 $115,403 $ 61,773 State 39,966 44,473 27,153 -------- -------- -------- Total current 148,337 159,876 88,926 -------- -------- -------- Deferred income taxes, net: Federal 44,180 3,808 60,788 State 842 (12,987) 11,833 -------- -------- -------- Total deferred 45,022 (9,179) 72,621 -------- -------- -------- Investment tax credits, net (7,358) (11,009) (6,230) -------- -------- -------- Total income tax expense $186,001 $139,688 $155,317 ======== ======== ======== The components of total income tax expense are classified as follows: Income taxes charged to operating expenses $195,038 $144,547 $172,236 Income taxes associated with the amortization of deferred nuclear plants return - borrowed funds - - (15,157) Income taxes associated with allowance for funds used during construction (AFUDC) and deferred nuclear plants return - borrowed funds - - 9,409 Other income taxes - credit (9,037) (4,859) (11,171) -------- -------- -------- Total income tax expense $186,001 $139,688 $155,317 ======== ======== ======== Deferred income taxes are comprised of the tax effects of temporary differences as follows: For the Years Ended December 31, 1994 1993 (Note 1I) 1992 ----------------------------------------------------------------------------------------------- (Thousands of Dollars) Depreciation, leased nuclear fuel, settlement credits, and disposal costs $38,874 $42,663 $43,715 Demand-side management 203 9,156 13,506 Postretirement benefits accrual (1,019) (2,579) - Energy adjustment clauses 14,465 (52,189) 12,627 AFUDC and deferred nuclear plants return, net (18,483) (13,741) (5,748) Early retirement program 671 (3,355) 3,988 Pension accrual 742 3,553 885 Settlement, canceled independent power plants - - 7,251 Loss on bond redemption 9,183 8,145 10 Other 386 (832) (3,613) ------- ------- -------- Deferred income taxes, net $45,022 ($9,179) $72,621 ======= ======== ======== 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, 1994 1993 (Note 1I) 1992 ------------------------------------------------------------------------------------------------ (Thousands of Dollars) Expected federal income tax at 35 percent of pretax income for 1994 and 1993 and at 34 percent for 1992 $134,501 $115,898 $123,091 Tax effect of differences: Depreciation differences 18,602 19,264 15,826 Deferred nuclear plants return - other funds (4,681) (8,294) (12,035) Amortization of deferred nuclear plants return - other funds 19,755 18,648 14,511 Property tax differences 5,286 (12,320) (732) Investment tax credit amortization (7,358) (11,009) (6,230) State income taxes, net of federal benefit 26,526 20,466 25,730 Adjustment for prior years taxes (2,706) (2,330) (3,500) Other, net (3,924) (635) (1,344) -------- -------- -------- Total income tax expense $186,001 $139,688 $155,317 ======== ======== ========
9. EMPLOYMENT 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 $(2.3) million in 1994, $7.6 million in 1993, and ($1.7) million in 1992. The company's pension costs for 1994 and 1993 include approximately $4.8 million and $13.1 million, respectively, related to work-force reduction programs. Currently, the company funds annually an amount at least equal to that which will satisfy the requirements of the Employment 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, 1994 1993 1992 -------------------------------------------------------------------------- (Thousands of Dollars) Service cost $13,072 $21,907 $10,614 Interest cost 36,103 35,055 36,308 Return on plan assets 1,020 (80,615) (40,377) Net amortization (52,536) 31,254 (8,206) ------- -------- -------- Net pension (income)/cos ($2,341) $7,601 ($1,661) ======= ======= ======= For calculating pension cost, the following assumptions were used: For the Years Ended December 31, 1994 1993 1992 -------------------------------------------------------------------------- (Thousands of Dollars) Discount rate 7.75% 8.00% 8.50% Expected long term rate of return 8.50 8.50 9.00 Compensation/progression rate 4.75 5.00 6.75 The following table represents the plan's funded status reconciled to the Consolidated Balance Sheets: At December 31, 1994 1993 ----------------------------------------------------------------- (Thousands of Dollars) Accumulated benefit obligation, including $374,109,000 of vested benefits at December 31, 1994 and $380,238,000 of vested benefits at December 31, 1993 $401,889 $409,136 ======== ======== Projected benefit obligation $471,079 $484,396 Market value of plan assets 568,294 604,320 -------- -------- Market value in excess of projected benefit obligation 97,215 119,924 Unrecognized transition amount (9,204) (10,125) Unrecognized prior service costs 1,420 1,547 Unrecognized net (gain) (88,845) (113,100) --------- --------- Prepaid/(Accrued) pension liability $586 ($1,754) ========= ========= The following actuarial assumptions were used in calculating the Plan's year-end funded status: At December 31, 1994 1993 ------------------------------------------------------------ (Thousands of Dollars) Discount rate ............ 8.25% 7.75% Compensation/progression rate 5.00 4.75 >F9B>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. These benefits are available for employees leaving the company who are otherwise eligible to retire and have met specified service requirements. Effective January 1, 1993, the company adopted SFAS 106, Employer's Accounting for Postretirement Benefits Other Than Pensions on a prospective basis. CL&P's direct portion of health care and life insurance costs, part of which were deferred or charged to utility plant, approximated $22.3 million in 1994, $23.2 million in 1993, and $8.8 million in 1992. On January 1, 1993, the accumulated postretirement benefit obligation represented the company's transition obligation upon the adoption of SFAS 106. As allowed by SFAS 106, the company is amortizing its transition obligation of approximately $148 million over a 20-year period. 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. During 1994, the company funded through external trusts an amount equivalent to total SFAS 106 benefits paid for 1994. During 1993, the company did not fund SFAS 106 postretirement costs through external trusts. The company expects to fund, annually, total SFAS 106 costs, including benefits paid amounts, once they 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 following table represents the plan's funded status reconciled to the Consolidated Balance Sheet: At December 31, 1994 1993 -------------------------------------------------------------------- (Thousands of Dollars) Accumulated postretirement benefit obligation of: Retirees .......................... $129,111 $119,520 Fully eligible active employees ... 241 288 Active employees not eligible to retire 25,203 29,270 --------- --------- Total accumulated postretirement benefit obligation 154,555 149,078 Market value of plan assets ....... 167 - --------- --------- Accumulated postretirement benefit obligation in excess of plan assets ......... (154,388) (149,078) Unrecognized transition amount ..... 132,194 139,539 Unrecognized net loss (gain) ...... 192 (2,591) ---------- --------- Accrued postretirement benefit liability $(22,002) $(12,130) ======== ======== ------------------------------------------------------------- The components of health care and life insurance costs are: For the Years Ended December 31, 1994 1993 ------------------------------------------------------------ (Thousands of Dollars) Service cost ....................... $ 2,371 $ 3,397 Interest cost ...................... 12,157 12,091 Return on plan assets ............. 2 - Net amortization ................... 7,774 7,682 ------- ------- Net health care and life insurance costs $22,304 $23,170 ======= ======= The following actuarial assumptions were used in calculating the plan's year end funded status: At December 31, 1994 1993 ------------------------------------------------------------ Discount rate ...................... 8.00% 7.75% Long-term rate of return - health assets, net of tax................ 5.00 5.00 Long-term rate of return - life assets 8.50 8.50 Health care cost trend rate (a) .... 10.20 11.10 (a) The annual growth in per capita cost of covered health care benefits was assumed to decrease to 5.4 percent by 2002. 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, 1994 by $8.6 million and the aggregate of the service and interest cost components of net periodic postretirement benefit cost for the year then ended by $763,000. The trust holding the plan assets is subject to federal income taxes at a 35-percent tax rate. CL&P has received regulatory approval to defer SFAS 106 costs in excess of costs incurred on a pay-as-you-go basis. Deferral of such costs is permitted since it is expected that the period of recovery of deferred costs will be within the time frame established by the applicable accounting requirements. 10. COMMITMENTS AND CONTINGENCIES A.CONSTRUCTION PROGRAM The construction program is subject to periodic review and revision. Actual construction expenditures may vary from estimates due to factors such as revised load estimates, inflation, revised nuclear safety regulations, delays, difficulties in the licensing process, the availability and cost of capital, and the granting of timely and adequate rate relief by regulatory commissions, as well as actions by other regulatory bodies. CL&P currently forecasts construction expenditures (including AFUDC) of approximately $716.9 million for the years 1995-1999, including $147.7 million for 1995. In addition, the company estimates that nuclear fuel requirements, including nuclear fuel financed through the NBFT, will be approximately $257.4 million for the years 1995-1999, including $46.8 million for 1995. 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. The Office of Consumer Counsel (OCC) appealed decisions favorable to the company in two dockets. For the one appeal decided, which related to a procedural issue, the OCC prevailed and the case has been remanded to the DPUC for further proceedings. The exposure under these two dockets is approximately $66 million. The DPUC has suspended a third docket, pending the outcome of one of the appeals. The exposure under this remaining docket is $26 million. Management believes that its actions with respect to these outages have been prudent, and it does not expect the outcome of the appeals to result in material disallowances. In October 1994, Millstone 2 began a planned refueling and maintenance outage that was originally scheduled for 63 days. The outage has encountered several unexpected difficulties which have lengthened the duration of the outage. The magnitude of the schedule impact is currently under review, but the unit is not expected to return to service before April 1995. CL&P expects that replacement power costs in the range of $7 million per month will be attributable to the extension of the outage. Recovery of the costs related to this outage is subject to scrutiny by the DPUC. 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. Changing environmental requirements could hinder the construction of new generating units, transmission and distribution lines, substations, and other facilities. The cumulative long-term, economic 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 is, based upon information currently available, its estimated environmental remediation costs for waste disposal sites for which it's expected to bear legal liability. In most cases, the extent of additional future environmental cleanup costs is 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, 1994, the 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 million. However, in the event that it becomes necessary to effect environmental remedies that are currently not considered probable, it is reasonably possible that the upper limit of CL&P's environmental liability range could increase to approximately $10 million. CL&P cannot estimate the potential liability for future claims 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 The Price-Anderson Act currently limits public liability from a single incident at a nuclear power plant to $8.9 billion. The first $200 million of liability would be provided by purchasing the maximum amount of commercially available insurance. Additional coverage of up to a total of $8.3 billion would be provided by an assessment of $75.5 million per incident, levied on each of the 110 nuclear units that are currently subject to the Secondary Financial Protection Program in the United States, subject to a maximum assessment of $10 million per incident per nuclear unit in any year. In addition, if the sum of all public liability claims and legal costs arising from any nuclear incident exceeds the maximum amount of financial protection, each reactor operator can be assessed an additional 5 percent, up to $3.8 million, or $415.3 million in total, for all 110 nuclear units. The maximum assessment is to be adjusted at least every five years to reflect inflationary changes. Based on CL&P's ownership interests in Millstone 1, 2, and 3, and Seabrook 1, CL&P's maximum liability would be $173.6 million per incident. In addition, through CL&P's 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. Effective January 1, 1995, insurance was purchased from Nuclear Mutual Limited (NML) to cover the primary cost of repair, replacement, or decontamination of utility property resulting from insured occurrences with respect to CL&P's ownership interest in Millstone 1, 2, 3, and CY. All companies insured with NML are subject to retroactive assessments if losses exceed the accumulated funds available to NML. The maximum potential assessment against CL&P with respect to losses arising during the current policy year is approximately $13 million under the NML primary property insurance program. Insurance has been purchased from Nuclear Electric Insurance Limited (NEIL) to cover: (1) certain extra costs incurred in obtaining replacement power during prolonged accidental outages with respect to CL&P's ownership interests in Millstone 1, 2, and 3, Seabrook 1, and CY; and (2) the excess cost of repair, replacement, or decontamination or premature decommissioning of utility property resulting from insured occurrences with respect to CL&P's ownership interests in Millstone 1, 2, and 3, Seabrook 1, CY, MY, and VY. All companies insured with NEIL are subject to retroactive assessments if losses exceed the accumulated funds available to NEIL. The maximum potential assessments against CL&P, with respect to losses arising during current policy years are approximately $7.5 million under the replacement power policies and $32.2 million under the excess property damage, decontamination, and decommissioning policies. Although CL&P 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 from American Nuclear Insurers/Mutual Atomic Energy Liability Underwriters, 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 $3.1 million per reactor. The maximum potential assessments against CL&P with respect to losses arising during the current policy period are approximately $9.2 million. E.PURCHASED POWER ARRANGEMENTS CL&P along with PSNH and WMECO purchase approximately 10 percent of their electricity requirements pursuant to long-term contracts with the Yankee companies. Under the terms of its agreements, CL&P pays its ownership share (or entitlement share) of generating costs, which include depreciation, operation and maintenance expenses, taxes, the estimated cost of decommissioning, and a return on invested capital. These costs are recorded as purchased power expense, and are recovered through the company's rates. CL&P's total cost of purchases under these contracts for the units that are operating amounted to $102.1 million in 1994, $112.3 million in 1993, and $103.2 million in 1992. See Note 1D, "Summary Of Significant Accounting Policies - Investments and Jointly Owned Electric Utility Plant" and Note 3, "Nuclear Decommissioning" for more information on the Yankee companies. CL&P has entered into various arrangements for the purchase of capacity and energy from nonutility generators. These arrangements generally have terms from 10 to 30 years, and require the company to purchase the energy at specified prices or formula rates. For the 12 months ended December 31, 1994, approximately 14 percent of system electricity requirements was met by nonutility generators. The total cost of the company's purchases under these arrangements amounted to $277.4 million in 1994, $279.8 million in 1993, and $267.3 million in 1992. These costs are eventually recovered through the company's rates. The estimated annual costs of CL&P's significant purchase power arrangements are as follows: 1995 1996 1997 1998 1999 ------------------------------------------------------------- (Millions of Dollars) Yankee companies ...... $110.2 $116.0 $103.7 $123.6 $118.1 Nonutility generators . 301.1 315.9 322.5 329.3 329.2 F.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, its proportionate share of the annual operation, maintenance, and capital costs of these facilities, which are currently forecast to be $97.7 million for the years 1995- 1999, including $21.8 million for 1995. 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 1994, there was one outstanding contract held by CL&P covering $340 million of variable-rate debt, with a term of three years. The contract entitles 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. This contract is settled on a quarterly basis. As of December 31, 1994, CL&P had a total of $340 million in caps outstanding, with a positive mark-to-market position of approximately $3.7 million. 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, 1994, CL&P had five outstanding agreements with a total notional value of approximately $126 million, and a positive mark-to-market position of approximately $3.1 million. These swap agreements have been made with various financial institutions, each of which are rated "A" or better by Standard and Poor's rating group. CL&P is exposed to credit risk on both the interest-rate caps and 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 and nuclear decommissioning trusts: The carrying amounts approximate fair value. SFAS 115 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. As a result of the adoption of SFAS 115, the investments held in the company's nuclear decommissioning trusts decreased by approximately $3.8 million as of December 31, 1994, with a corresponding offset to the accumulated provision for depreciation. The $3.8 million decrease 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, 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 ----------------------------------------------------------------- Carrying Fair At December 31, 1993 Amount Value ---------------------------------------------------------------- (Thousands of Dollars) Preferred stock not subject to mandatory redemption ........ $ 166,200 $ 128,826 Preferred stock subject to mandatory redemption ........ 230,000 240,400 Long-term debt - First Mortgage Bonds ....... 1,532,000 1,580,396 Other long-term debt ....... 533,442 539,518 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. 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: 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, 1994 and 1993, 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, 1994. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of The Connecticut Light and Power Company and Subsidiaries as of December 31, 1994 and 1993, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1994, in conformity with generally accepted accounting principles. As explained in Note 1B and 9B to the financial statements, effective January 1, 1993, The Connecticut Light and Power Company and Subsidiaries changed its methods of accounting for property taxes and postretirement benefits other than pensions. /s/Arthur Andersen LLP ARTHUR ANDERSEN LLP Hartford, Connecticut February 17, 1995 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 $198 million in 1994, as compared to approximately $191 million in 1993. The 1994 net income is higher as a result of higher retail kilowatt-hour sales, retail rate increases in 1993 and 1994, the deferral of cogeneration expenses, and reduced operation and interest costs. These increases were partially offset by lower revenues from wholesale sales. The 1993 net income was impacted by a number of one-time items, including the cumulative effect of a one-time change in the accounting for municipal property taxes, which resulted in an increase in 1993 net income of approximately $48 million. In addition, 1993 net income reflected a decrease of approximately $10 million for the costs of the company's employee-reduction program and a decrease of approximately $15 million for disallowances in 1993 ordered in the company's retail rate case. Net income before the effects of the change in accounting for property taxes and other one-time items was approximately $169 million in 1993. In 1994, the company experienced its most significant retail kilowatt-hour sales growth in six years, due in large part to the beginning of an economic recovery in New England. Employment levels have risen, unemployment rates have fallen, and personal income has increased. The company's 1994 retail sales rose by 3.4 percent over 1993. Overall, weather had little effect on sales volume, with mild weather after mid-August offsetting unusually cold weather in January and hot weather in late June and July. In 1995, the company expects little retail sales growth over 1994, primarily because of the effects of higher interest rates on the regional economy and further cutbacks in defense-related industries in Connecticut. The company estimates compounded annual sales growth of 1.4 percent from 1994 through 1999. Competitive forces within the electric utility industry are continuing to increase due to a variety of influences, including legislative and regulatory actions, technological advances, and changes in consumer demand. The company has developed, and is continuing to develop, a number of initiatives to retain and continue to serve its existing customers and to expand its retail and wholesale customer base. The company believes the steps it is taking including a companywide process reengineering effort, will have significant, positive effects, including reduced operating costs and improved customer service, in the next few years. The company also benefits from a diverse retail base with no significant dependence on any one retail customer or industry. CL&P continues to operate predominantly in a state-approved franchise territory under traditional cost-of-service regulation. Retail wheeling, under which a retail customer would be permitted to select an electricity supplier and require the local electric utility to transmit the power to the customer's site, is not required in Connecticut. In 1994, Connecticut regulators reviewed the desirability of retail wheeling and determined that it was not in the best interest of the state until new generating capacity is needed, which the NU system projects to be in the year 2009. Connecticut regulators are presently studying the potential restructuring of the electric utility industry. To date, this regulatory proceeding has not progressed to the point where management can assess the impact of any potential outcome on the company. While retail competition is not required in the company's retail service territory, competitive forces are nonetheless influencing retail pricing. These forces include competition from alternate fuels such as natural gas, competition from customer-owned generation, and regional competition for business retention and expansion. The company's retail business group continues to work with customers to address their concerns. The company has reached long-term rate agreements with many new and existing customers to gain or retain their business. In general, these rate agreements have terms of about five years. Negotiated retail rate reductions for customers under rate agreements in effect for 1994 amounted to approximately $11 million. Management believes that the aggregate amount of negotiated retail rate reductions will increase in 1995 but that the related agreements will continue to provide significant benefits to the system, including the preservation of approximately 3 percent of retail revenues. The company is also working with its regulators to address the needs of customers more widely. The company has a three-year rate agreement in effect through June 1996. Management will continue to evaluate the use of agreements of this type to keep retail rates competitive. The company acts as both a buyer and a seller of electricity in the highly competitive wholesale electricity market in the Northeastern United States (Northeast). Many of the contracts signed in the late 1980s have or will expire in the mid-1990s. Much of the revenue produced by such contracts has not been replaced through new wholesale power arrangements. As a result, wholesale power revenues fell to approximately $215 million in 1994 from approximately $268 mil- lion in 1993. Unless prices on the wholesale market improve, revenues are expected to fall still further in 1995 before stabilizing in late 1996 and 1997. Wholesale sales are made primarily to investor-owned utilities and municipal or cooperative electric systems in the Northeast. The company will be increasing its efforts to increase wholesale sales through intensified marketing efforts. The company's wholesale power marketing efforts benefit from the interconnection of the NU system's transmission system with all of the major utilities in New England, as well as with the three largest electric utilities in New York state. RATE MATTERS The company follows accounting principles that allow the rate treatment for certain events or transactions to be reflected. These principles may differ from the accounting principles followed by nonregulated enterprises. Regulators may permit incurred costs, which would normally be treated as expenses by nonregulated enterprises, to be deferred as regulatory assets and recovered in revenues at a later date. Regulatory assets at December 31, 1994 were approximately $1.4 billion. Based on current regulation, the company believes that its use of regulatory accounting is still appropriate. See the "Notes to Consolidated Financial Statements," Note 1H, for further details on regulatory accounting. CL&P's retail rates increased by approximately $47 million, or 2.04 percent, in July 1994, representing the second step of a three-year rate plan approved by the Department of Public Utility Control (DPUC) in 1993. The third step of an approximately $48 million, or 2.06 percent, increase will become effective in July 1995. CL&P's 1993 rate decision has been appealed by the Connecticut Office of Consumer Counsel and the city of Hartford. If this appeal prevails there may be revenues subject to refund, however, management believes that the possibility of the appeal prevailing is unlikely. CL&P recovers from or refunds to customers certain fuel costs if the nuclear units do not operate at a predetermined capacity factor (currently 72 percent) through a Generation Utilization Adjustment Clause (GUAC). For the GUAC year ended July 31, 1994, the DPUC found that CL&P overrecovered its fuel costs and reduced by approximately $8 million CL&P's overall request to recover approximately $24 million of deferred GUAC costs. The company plans to appeal the decision in court as it did for a similar DPUC decision on the 1992-1993 GUAC period, which also disallowed approximately $8 million of GUAC costs. For the GUAC year ended July 31, 1995, CL&P expects to defer in excess of $50 million of GUAC fuel costs for projected nuclear performance below 72 percent. As of December 31, 1994, CL&P has reserved approximately $13 million against this amount based on the methodology applied by the DPUC in the previous GUAC decisions. NUCLEAR PERFORMANCE The composite capacity factor of the five nuclear generating units that the NU system operates - including the Connecticut Yankee (CY) nuclear unit was 67.5 percent for 1994, compared with 80.8 percent for 1993 and a 1994 national average of 73.2 percent. The lower 1994 capacity factor was primarily the result of extended refueling and maintenance outages for Millstone 1, Millstone 2, and Seabrook. CY, Seabrook, and Millstone 2 were also out of service for varying lengths of time in 1994 because of unexpected technical and operating difficulties. These difficulties included a manual shutdown of CY when both service water headers were declared inoperable, an automatic trip from 100 percent power for Seabrook when a main steam isolation valve closed during quarterly surveillance testing, and a Millstone 2 shutdown to replace a degraded lower seal on a reactor coolant pump. On October 1, 1994, Millstone 2 was shut down for a planned 63-day refueling and maintenance outage. The outage has encountered several unexpected difficulties, which will lengthen the duration of the outage. The outage extensions were caused by a significant scope increase in service water system repairs as identified through a comprehensive inspection plan and by a need for management to exercise a deliberate approach to the conduct of work during the early portions of the outage. The outage schedule is currently under review, but the unit is not expected to return to service before April 1995. Replacement-power costs attributable to the extension of the outage for CL&P are expected to be in the range of approximately $7 million per month. These costs are deferred for future recovery through the GUAC. (See rate matters above for further discussion of the GUAC.) In addition, CL&P's operation and maintenance costs to be incurred during the outage are estimated to be $42 million, an increase of $15 million as a result of the extension. The recovery of these costs is subject to prudence review in Connecticut. The Nuclear Regulatory Commission's (NRC's) latest report for the Millstone Station noted significant weaknesses in Millstone 2's operations and maintenance. In a recent public statement in late 1994, a senior NRC official expressed disappointment with the continued weaknesses in Millstone 2's performance. The primary cause of the NRC's disappointment with Millstone 2's performance appears to be that, despite significant management attention and action over a period of years, the NRC does not believe it has seen enough objective evidence of improvement in reducing procedural noncompliance and other human errors. Management has acknowledged the basis for the NRC's concern with Millstone 2 and has been devoting increased attention to resolving these issues. Management and the NRC expect to continue to monitor closely the developments at Millstone 2. ENVIRONMENTAL MATTERS NU devotes substantial resources to identify and then to meet the multitude of environmental requirements it faces. NU has active auditing programs addressing a variety of different regulatory requirements, including an environmental auditing program to detect and remedy noncompliance with environmental laws or regulations. The company 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 the company. At December 31, 1994, the liability recorded by the company, amounted to approximately $7 million. These costs could rise to as much as $10 million if alternate remedies become necessary. The company expects that the implementation of the Clean Air Act Amendments of 1990 (CAAA) as they relate to sulfur dioxide emissions will require only modest emissions reductions for the company. CL&P's exposure is minimal because of the company's investment in nuclear energy in the 1970s and 1980s and the burning of low-sulfur fuels. The CAAA requirements for emission limits for nitrogen oxides will initially be met by capital expenditures of approximately $10 million. NUCLEAR DECOMMISSIONING The company's estimated cost to decommission its shares of Millstone units 1, 2, and 3 and Seabrook is approximately $853 million in year-end 1994 dollars. In addition, the company's estimated cost to decommission its shares of the regional nuclear generating units is approximately $197 million. These costs are being recognized over the lives of the respective units and a portion of the costs is being recovered through rates. Yankee Atomic Electric Company (YAEC) has begun component removal activities related to the decommissioning of its nuclear facility. The company's estimated obligation to YAEC has been recorded on its Consolidated Balance Sheets. Management expects that the company will continue to be allowed to recover these costs. The staff of the Securities and Exchange Commission has questioned certain of the current accounting practices of the electric utility industry, including this company, regarding the recognition, measurement, and classification of decommissioning costs for nuclear generating stations in the financial statements of electric utilities. The Financial Accounting Standards Board is currently reviewing the accounting for removal costs, including decommissioning. If current electric utility industry accounting practices for such decom- missioning costs are changed: (1) annual provisions for decommissioning could increase, (2) the estimated costs for decommissioning could be recorded as a liability rather than as accumulated depreciation, and (3) trust fund income from the external decommissioning trust could be reported as investment income rather than as a reduction to decommissioning expense. See the "Notes to The Consolidated Financial Statements, " Note 3, for further information on nuclear decommissioning. PROPERTY TAXES CY has a significant court appeal for municipal property tax assessments in the town of Haddam, Connecticut. The central issue in this case is the fair market value of utility property. CY 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, towns such Haddam advocate a method that approximates reproduction costs. CY's appeal is still pending. The company estimates that, for assessments in towns such as Haddam, the change to the reproduction cost methodology could result in property valuations approximately three times greater than values approximating net book cost. If other towns in Connecticut adopt this methodology, there could be a significant adverse impact on the company's future results of operations and financial condition. However, the extent to which other towns successfully adopt this methodology and any subsequent increase in the company's property tax liability cannot be determined at this time. LIQUIDITY AND CAPITAL RESOURCES Cash provided from operations decreased approximately $12 million in 1994, as compared with 1993, primarily due to lower recovery of replacement-power costs under the GUAC in 1994, partially offset by higher revenues from rate increases and sales combined with lower cash operating expenses. Cash used for financing activities was approximately $26 million lower in 1994, as compared with 1993, primarily due to an increase in short-term debt, partially offset by higher net reacquisitions and retirements of long-term debt. Cash used for investments increased $4 million in 1994, as compared with 1993. In 1994, the company refinanced approximately $535 million of debt. With interest rates rising in mid-1994, much refinancing completed, and construction needs remaining modest, the focus of CL&P's financing activities will shift toward using the significant amount of cash generated by the company to retire debt and to prepare the company for an increasingly competitive business environment. The company is obligated to meet approximately $531 million of long-term debt and preferred stock maturities and cash sinking-fund requirements during the 1995 through 1999 period, including approximately $12 million for 1995. The company's construction program expenditures, including allowance for funds used during construction, for the period 1995 through 1999 are estimated to be approximately $717 million, including approximately $148 million for 1995. The construction program's main focus is maintaining and upgrading the existing transmission and distribution system, as well as nuclear and fossil-generating facilities. NU does not foresee the need for new major generating facilities, at least until the year 2009. Construction expenditures and debt sinking fund requirements will continue to be met through internal cash generation. CL&P entered into interest rate cap contracts to reduce a portion of the interest rate risk on certain variable-rate tax-exempt pollution control revenue bonds. CL&P also uses fossil fuel-swap agreements to hedge against fuel-price risk on certain long-term, negotiated energy contracts. Any premiums paid on these contracts are deferred and amortized over the life of the contracts. The differential paid or received as interest rates or fuel prices change is recognized in income when realized. See the "Notes To Consolidated Financial Statements," Note 8, for further information on derivative financial instruments. 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) 1994 VS. 1993 1993 VS. 1992 -------------------------------------------------------------------- (MILLIONS OF DOLLARS) Regulatory decisions $ 38 $34 Fuel and purchased power cost recoveries (45) 2 Sales volume 40 3 Wholesale revenues (63) 7 Other revenues (8) 4 ----- ---- Total revenue change $(38) $50 ==== === Operating revenues decreased approximately $38 million in 1994 from 1993. Reve- nues related to regulatory decisions increased, primarily because of 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 improving economy. Retail sales increased 3.4 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. Operating revenues increased approximately $50 million in 1993 from 1992. Revenues related to regulatory decisions increased, primarily because of the effects of the June 1993 retail rate increase for CL&P and higher recoveries for demand-side-management costs. Retail sales were essentially flat in 1993. FUEL, PURCHASED AND NET INTERCHANGE POWER Fuel, purchased and net interchange power decreased approximately $89 million in 1994, as compared with 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. Fuel, purchased and net interchange power increased approximately $59 million in 1993, as compared with 1992, primarily due to the timing in the recognition of fuel expenses under the provisions of CL&P's fuel adjustment clauses, and 1993 disallowances of replacement-power costs as a result of regulatory reviews in Connecticut, partially offset by lower outside purchases due to better nuclear performance in 1993. OTHER OPERATION AND MAINTENANCE EXPENSES Other operation and maintenance expenses decreased approximately $21 million in 1994, as compared with 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. Other operation and maintenance expenses increased approximately $19 million in 1993, as compared with 1992, primarily due to the 1993 costs associated with an employee-reduction program ($24 million) and higher 1993 postretirement benefit costs, partially offset by lower costs associated with the operation and maintenance activities of the nuclear units. DEPRECIATION EXPENSES Depreciation expenses increased approximately $11 million in 1994, as compared to 1993, primarily as a result of higher depreciable plant balances, higher average depreciation rates, and higher decommissioning collections. Depreciation expenses increased $10 million in 1993, as compared to 1992, primarily as a result of higher depreciation rates and higher depreciable plant balances. AMORTIZATION OF REGULATORY ASSETS, NET Amortization of regulatory assets, net decreased approximately $35 million in 1994, as compared with 1993, primarily because of 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 phase-in costs. Amortization of regulatory assets, net increased approximately $39 million in 1993, as compared to 1992, primarily because of higher amortization of Millstone 3 and Seabrook phase-in costs, the gross-up of taxes due to a required change in the accounting for income taxes, and the amortization of costs paid to the developers of two wood-to-energy plants as allowed in the 1993 rate decision. FEDERAL AND STATE INCOME TAXES Federal and state income taxes increased approximately $46 million in 1994, as compared with 1993, primarily because of higher taxable income. Federal and state income taxes decreased approximately $21 million in 1993, as compared with 1992, primarily because of lower taxable income and higher investment tax credits, partially offset by an increase in flow-through depreciation. DEFERRED NUCLEAR PLANTS RETURN Deferred nuclear plants return decreased approximately $17 million in 1994, as compared with 1993, primarily because additional Millstone 3 investment was phased into rates in 1994. Deferred nuclear plants return decreased approximately $11 million in 1993, as compared with 1992, primarily because additional Millstone 3 investment was phased into rates in 1993. OTHER INCOME, NET Other income, net increased approximately $6 million in 1994, as compared with 1993, and decreased approximately $8 million in 1993, as compared with 1992, primarily because of the 1993 allocation to customers of a portion of the property tax accounting change as ordered in the 1993 CL&P rate decision. INTEREST CHARGES Interest on long-term debt decreased approximately $14 million in 1994, as compared with 1993, primarily because of lower average interest rates as a result of refinancing activities and lower 1994 debt levels. Interest on long-term debt decreased approximately $17 million in 1993, as compared with 1992, primarily because of lower average interest rates as a result of substantial refinancing activities. 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 municipal property tax expense recognized in the first quarter of 1993. THE CONNECTICUT LIGHT AND POWER COMPANY ------------------------------------------------------------------------------ SELECTED FINANCIAL DATA ------------------------------------------------------------------------------ 1994 1993 1992 1991 1990 ------------------------------------------------------------------------------ (Thousands of Dollars) Operating Revenues $2,328,052 $2,366,050 $2,316,451 $2,275,737 $2,170,087 Operating Income.... 282,159 240,095 287,811 323,835 320,641 Net Income.......... 198,288 191,449(a) 206,714 240,818 224,783 Cash Dividends on Common Stock...... 159,388 160,365 164,277 172,587 179,921 Total Assets........ 6,217,457 6,397,405 5,582,831 5,338,466 5,176,809 Long-Term Debt*..... 1,823,690 2,057,280 2,087,936 2,023,268 2,101,334 Preferred Stock Not Subject to Mandatory Redemption......... 166,200 166,200 231,196 306,195 306,195 Preferred Stock Subject to Mandatory Redemption*........ 230,000 230,000 200,000 141,892 146,892 Obligations Under Capital Leases*.... 175,969 177,418 197,404 208,924 233,919 * Includes portions due within one year. (a) Includes the cumulative effect of a change in accounting for municipal property tax expense, which increased earnings for common shares by $47.7 million. ------------------------------------------------------------------------ STATEMENTS OF QUARTERLY FINANCIAL DATA (UNAUDITED) ------------------------------------------------------------------------ Quarter Ended ------------------------------------------------- 1994 March 31 June 30 September 30December 31 --------------------------------------------------------------------- (Thousands of Dollars) Operating Revenues.. $619,815 $551,135 $598,706 $558,396 ======== ======== ======== ======== Operating Income.... $ 88,796 $ 58,190 $ 73,640 $ 61,533 ========= ========= ========= ========= Net Income.......... $ 68,590 $ 39,162 $ 50,191 $ 40,345 ========= ========= ========= ========= 1993 ------------------------------------------------------------------------ Operating Revenues.. $627,134 $559,894 $604,343 $574,679 ======== ======== ======== ======== Operating Income.... $ 67,201 $ 47,775 $ 58,321 $ 66,798 ========= ========= ========= ========= Net Income.......... $ 91,596 $ 13,775 $ 39,068 $ 47,010 ========= ========= ========= ========= 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,) -------------------------------------------------------------------------- 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 1990 5,881,500 25,039 8,434 1,064,695 3,517 EX-13.3 18 Exhibit 13.3 1994 ANNUAL REPORT TO STOCKHOLDERS WESTERN MASSACHUSETTS ELECTRIC COMPANY -------------------------------------- 1994 Annual Report Western Massachusetts Electric Company Index Contents Page -------- ---- Balance Sheets..................................... 1-2 Statements of Income............................... 3 Statements of Cash Flows........................... 4 Statements of Common Stockholder's Equity.......... 5 Notes to Financial Statements...................... 6-25 Report of Independent Public Accountants........... 26 Management's Discussion and Analysis of Financial Condition and Results of Operations............... 27-32 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, 1994 1993 ------------------------------------------------------------------------------------ (Thousands of Dollars) ASSETS ------ Utility Plant, at original cost: Electric................................................ $1,214,326 $1,183,410 Less: Accumulated provision for depreciation......... 425,019 395,190 ----------- ----------- 789,307 788,220 Construction work in progress........................... 19,187 23,790 Nuclear fuel, net....................................... 38,000 35,727 ----------- ----------- Total net utility plant............................. 846,494 847,737 ----------- ----------- Other Property and Investments: Nuclear decommissioning trusts, at market in 1994 and at cost in 1993 (Note 12)......................... 56,123 49,155 Investments in regional nuclear generating companies, at equity................................... 14,927 14,633 Other, at cost.......................................... 3,941 3,840 ----------- ----------- 74,991 67,628 ----------- ----------- Current Assets: Cash.................................................... 105 185 Notes receivable from affiliated companies.............. 8,750 - Receivables, less accumulated provision for uncollectible accounts of $2,032,000 in 1994 and $1,997,000 in 1993................................ 35,427 36,437 Accounts receivable from affiliated companies........... 1,108 4,972 Accrued utility revenues................................ 15,766 17,362 Fuel, materials, and supplies, at average cost.......... 4,829 7,057 Prepayments and other................................... 9,215 9,613 ----------- ----------- 75,200 75,626 ----------- ----------- Deferred Charges: Regulatory assets (Note 1H)........................ 184,226 210,647 Unamortized debt expense................................ 1,733 1,842 Other................................................... 974 1,162 ----------- ----------- 186,933 213,651 ----------- ----------- Total Assets........................................ $1,183,618 $1,204,642 =========== ===========
The accompanying notes are an integral part of these financial statements. WESTERN MASSACHUSETTS ELECTRIC COMPANY BALANCE SHEETS
------------------------------------------------------------------------------------ At December 31, 1994 1993 ------------------------------------------------------------------------------------ (Thousands of Dollars) CAPITALIZATION AND LIABILITIES ------------------------------ Capitalization: Common stock--$25 par value. Authorized and outstanding 1,072,471 shares in 1994 and 1993........ $ 26,812 $ 26,812 Capital surplus, paid in................................ 149,683 149,319 Retained earnings....................................... 111,586 97,627 ----------- ----------- Total common stockholder's equity.............. 288,081 273,758 Cumulative preferred stock-- $100 par value--authorized 1,000,000 shares; outstanding 200,000 shares in 1994 and 1993; $25 par value--authorized 3,600,000 shares; outstanding 2,927,000 shares in 1994 3,220,000 shares in 1993 Not subject to mandatory redemption (Note 5)...... 68,500 73,500 Subject to mandatory redemption (Note 6).......... 24,000 25,500 Long-term debt (Note 7)............................. 345,669 393,232 ----------- ----------- Total capitalization........................... 726,250 765,990 ----------- ----------- Obligations Under Capital Leases.......................... 23,852 24,014 ----------- ----------- Current Liabilities: Notes payable to banks.................................. - 6,000 Long-term debt and preferred stock--current portion................................................ 34,975 1,500 Obligations under capital leases--current portion................................................ 12,945 12,888 Accounts payable........................................ 20,396 17,493 Accounts payable to affiliated companies................ 17,352 12,016 Accrued taxes........................................... 5,160 7,022 Accrued interest........................................ 6,702 6,478 Refundable energy costs................................. - 8,676 Other................................................... 7,584 11,727 ----------- ----------- 105,114 83,800 ----------- ----------- Deferred Credits: Accumulated deferred income taxes (Note 1I)........ 253,821 253,547 Accumulated deferred investment tax credits............. 27,822 36,083 Deferred contract obligation--YAEC (Note 3)......... 28,572 24,150 Other................................................... 18,187 17,058 ----------- ----------- 328,402 330,838 ----------- ----------- Commitments and Contingencies (Note 10) Total Capitalization and Liabilities........... $1,183,618 $1,204,642 =========== ===========
The accompanying notes are an integral part of these financial statements. WESTERN MASSACHUSETTS ELECTRIC COMPANY STATEMENTS OF INCOME
------------------------------------------------------------------------------ For the Years Ended December 31, 1994 1993 1992 ------------------------------------------------------------------------------ (Thousands of Dollars) Operating Revenues.............................. $421,477 $415,055 $410,720 --------- --------- --------- Operating Expenses: Operation -- Fuel, purchased and net interchange power.. 67,365 67,781 86,356 Other...................................... 130,683 142,273 126,060 Maintenance................................... 35,430 34,259 39,303 Depreciation.................................. 36,885 35,751 34,257 Amortization of regulatory assets............. 29,118 29,700 26,321 Federal and state income taxes (Note 8)... 33,540 28,173 20,926 Taxes other than income taxes................. 18,403 17,051 16,984 --------- --------- --------- Total operating expenses................ 351,424 354,988 350,207 --------- --------- --------- Operating Income................................ 70,053 60,067 60,513 --------- --------- --------- Other Income: Deferred Millstone 3 return--other funds (Note 1K)........................ 761 1,439 2,119 Equity in earnings of regional nuclear generating companies........................ 2,031 1,680 2,170 Other, net.................................... 2,926 2,966 2,628 Income taxes--credit.......................... 816 304 810 --------- --------- --------- Other income, net....................... 6,534 6,389 7,727 --------- --------- --------- Income before interest charges.......... 76,587 66,456 68,240 --------- --------- --------- Interest Charges: Interest on long-term debt.................... 27,678 29,979 31,694 Other interest................................ 21 881 469 Deferred Millstone 3 return--borrowed funds (Note 1K)........................ (569) (1,076) (945) --------- --------- --------- Interest charges, net................... 27,130 29,784 31,218 --------- --------- --------- Income before cumulative effect of accounting change............................. 49,457 36,672 37,022 Cumulative effect of accounting change (Note 1B)................................ - 3,922 - --------- --------- --------- Net Income...................................... $ 49,457 $ 40,594 $ 37,022 ========= ========= =========
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, 1994 1993 1992 ------------------------------------------------------------------------------------------------- (Thousands of Dollars) Cash Flows From Operating Activities: Net Income................................................ $ 49,457 $ 40,594 $ 37,022 Adjustments to reconcile to net cash from operating activities: Depreciation............................................ 36,885 35,751 34,257 Deferred income taxes and investment tax credits, net... 10,256 918 (785) Deferred return - Millstone 3, net of amortization...... 13,427 12,252 9,110 Recoverable energy costs, net of amortization........... (8,622) 7,316 2,999 Other sources of cash................................... 25,967 26,765 26,591 Other uses of cash...................................... (23,701) (2,698) (1,654) Changes in working capital: Receivables and accrued utility revenues................ 6,470 (3,728) 12,288 Fuel, materials, and supplies........................... 2,228 1,944 490 Accounts payable........................................ 8,239 (2,078) (5,355) Accrued taxes........................................... (1,862) (3,248) (295) Other working capital (excludes cash)................... (2,991) 2,433 1,932 ----------- ----------- ----------- Net cash flows from operating activities.................... 115,753 116,221 116,600 ----------- ----------- ----------- Cash Flows From Financing Activities: Issuance of long-term debt................................ 90,000 113,800 85,000 Net decrease in short-term debt........................... (6,000) (35,500) (3,250) Reacquisitions and retirements of long-term debt.......... (104,169) (114,270) (94,167) Reacquisitions and retirements of preferred stock......... (7,325) (1,500) (15,002) Cash dividends on preferred stock......................... (5,897) (5,259) (7,485) Cash dividends on common stock............................ (29,514) (28,785) (29,536) ----------- ----------- ----------- Net cash flows used for financing activities................ (62,905) (71,514) (64,440) ----------- ----------- ----------- Investment Activities: Investment in plant: Electric utility plant.................................. (32,680) (34,592) (46,061) Nuclear fuel............................................ (4,928) (2,926) 1,003 ----------- ----------- ----------- Net cash flows used for investments in plant.............. (37,608) (37,518) (45,058) NU System Money Pool...................................... (8,750) - - Other investment activities, net.......................... (6,570) (7,169) (7,101) ----------- ----------- ----------- Net cash flows used for investments......................... (52,928) (44,687) (52,159) ----------- ----------- ----------- Net (Decrease) Increase In Cash For The Period.............. (80) 20 1 Cash - beginning of period.................................. 185 165 164 ----------- ----------- ----------- Cash - end of period........................................ $ 105 $ 185 $ 165 =========== =========== =========== Supplemental Cash Flow Information: Cash paid during the year for: Interest, net of amounts capitalized during construction.. $ 25,174 $ 27,277 $ 30,758 =========== =========== =========== Income taxes.............................................. $ 30,040 $ 21,200 $ 17,711 =========== =========== =========== Increase in obligations: Niantic Bay Fuel Trust.................................... $ 12,237 $ 9,369 $ 7,224 =========== =========== ===========
TThe 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, 1992............... $26,812 $148,696 $ 91,708 $267,216 Net income for 1992.................. 37,022 37,022 Cash dividends on preferred stock.............................. (7,485) (7,485) Cash dividends on common stock....... (29,536) (29,536) Loss on the retirement of preferred stock.............................. (632) (632) Capital stock expenses, net.......... 330 330 -------- --------- --------- --------- Balance at December 31, 1992............. 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 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 ======== ========= ========= =========
(a) The company has dividend restrictions imposed by its long-term debt agreements. At December 31, 1994, 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. GENERAL 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). 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. B. CHANGE IN ACCOUNTING FOR PROPERTY TAXES WMECO adopted a one-time change in the method of accounting for municipal property tax expense for its Connecticut properties. Most municipalities in Connecticut assess property values as of October 1. Before January 1, 1993, WMECO accrued Connecticut property tax expense over the period October 1 through September 30 based on the lien-date method. In the first quarter of 1993, WMECO changed its method of accounting for Connecticut municipal property taxes to recognize the expense from July 1 through June 30, to match the payments and the services provided by the municipalities. This one-time change increased earnings for common shares by approximately $3.9 million. C. RECLASSIFICATIONS Certain classifications of prior years' data have been made to conform with the current year's presentation. D. 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 is committed to the participants substantially on the basis of their 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 - Purchased Power Arrangements." The YAEC 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, 1994 and 1993, plant-in-service included approximately $87.0 million and $77.6 million, respectively, and the accumulated provision for depreciation included approximately $31.4 million and $30.5 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, 1994 and 1993, plant-in-service included approximately $159.2 million and $158.1 million, respectively, and the accumulated provision for depreciation included approximately $40.4 million and $34.8 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, an 1,154-MW nuclear generating unit. As of December 31, 1994 and 1993, plant-in-service included approximately $376.1 million and $375.5 million, respectively, and the accumulated provision for depreciation included approximately $83.2 million and $72.9 million, respectively, for WMECO's proportionate share of Millstone 3. WMECO's share of Millstone 3 expenses is included in the corresponding operating expenses on the accompanying Statements Of Income. E. 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. For nuclear production plants, the costs of removal, less salvage, that have been funded through external decommissioning trusts will be paid with funds from the trusts and charged to the accumulated reserve for decommissioning included in the accumulated provision for depreciation over the expected service life of the plants. See Note 3, "Nuclear Decommissioning," for additional information. The depreciation rates for the several classes of electric plant-in-service are equivalent to a composite rate of 3.1 percent in 1994 and 1993, and 3.0 percent in 1992. F. 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 the Massachusetts Department of Public Utilities (DPU). G. REVENUES Other than 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. 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. H. REGULATORY ACCOUNTING WMECO follows accounting policies that reflect the impact of the rate treatment of certain events or transactions that differ from generally accepted accounting principles for those events or transactions followed by nonregulated enterprises. Under regulatory accounting, assuming that future revenues are expected to be sufficient to provide recovery, regulators may permit incurred costs, normally treated as expenses, to be deferred and recovered in revenues at a later date. Regulatory accounting is unique in that the actions of a regulator can provide reasonable assurance of the existence of an asset. Regulators, through their actions, may also reduce or eliminate the value of an asset, or create a liability. If the economic entity no longer comes under the jurisdiction of a regulator or external forces, such as a move to a competitive environment, effectively limiting the influence of cost-of-service based rate regulation, the entity may be forced to abandon regulatory accounting, requiring a reexamination and potential write-off of net regulatory assets. WMECO continues to be subject to cost-of-service based rate regulation. Based on current regulation, WMECO believes that its use of regulatory accounting is still appropriate. The components of regulatory assets are as follows: At December 31, 1994 1993 -------------------------------------------------------------- (Thousands of Dollars) Income taxes, net (Note 1I) .......... $ 86,357 $ 94,414 Unrecovered contract obligation - YAEC (Note 3) ...................... 28,572 24,150 Amortizable property investment - Milstone 3( Note 1K) ............... 16,800 28,001 Recoverable energy costs (Note 1J) ... 8,324 8,908 Deferred costs - Millstone 3 (Note 1K) 7,836 22,667 Other ................................ 36,337 32,507 -------- -------- $184,226 $210,647 ======== ======== 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 applicable regulatory commissions. See Note 8, "Income Tax Expense," for the components of income tax expense. In 1992, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes (SFAS 109). SFAS 109 supersedes previously issued income tax accounting standards. WMECO adopted SFAS 109, on a prospective basis during the first quarter of 1993, and increased the net deferred tax obligation by $249.3 million at that time. As it is probable that the increase in deferred tax liabilities will be recovered from customers through rates, WMECO also established a regulatory asset. The tax effect of temporary differences which give rise to the accumulated deferred tax obligation are as follows: At December 31, 1994 1993 ------------------------------------------------------------- (Thousands of Dollars) Accelerated depreciation and other plant-related differences ........ $214,485 $205,030 Regulatory assets - income tax gross up 34,084 37,258 Other .............................. 5,252 11,259 -------- -------- $253,821 $253,547 ======== ======== J. RECOVERABLE ENERGY COSTS In Massachusetts, all retail fuel costs are collected on a current basis by means of a separate fuel-charge billing rate. As permitted by the DPU, WMECO defers the difference between forecasted and actual fuel cost recoveries until it is recovered or refunded quarterly under a retail fuel adjustment clause. Massachusetts law requires the establishment of an annual performance program related to fuel procurement and use. The program establishes performance standards for plants owned and operated by WMECO or plants in which WMECO has a life- of-unit contract. Therefore, revenues collected under WMECO's retail fuel adjustment clause are subject to refund pending review by the DPU. To date, there have been no significant adjustments as a result of this program. Under the Energy Policy Act of 1992 (Energy Act), WMECO 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. WMECO has begun to recover these costs. At December 31, 1994, WMECO's D&D assessment was $8.3 million. K. MILLSTONE 3 As of December 31, 1991, all of WMECO's recoverable investment in Millstone 3 was in rate base. Beginning in 1986, the DPU has permitted WMECO to recover the portion of its Millstone 3 investment representing the amount currently determined to be "unuseful" by the DPU ($16.8 million at December 31, 1994), over a ten-year period, without earning a return. On June 30, 1987, WMECO also began recovering the deferred return, including carrying charges, on the recoverable but not yet phased-in portion of its investment in Millstone 3. This recovery is taking place over a nine-year period. As of December 31, 1994, $77.6 million of the deferred return, including carrying charges, has been recovered, and $7.8 million of the deferred return, including carrying charges, remains to be recovered over the period ending June 30, 1995. L. DERIVATIVE FINANCIAL INSTRUMENTS The company utilizes interest-rate caps to manage well-defined interest-rate 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 as a reduction of 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." M. 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, 1994, fees due to the DOE for the disposal of prior-period fuel were approximately $33.2 million, including interest costs of $17.6 million. As of December 31, 1994, all fees had been collected through rates. 2. LEASES WMECO and CL&P have entered into the Niantic Bay Fuel Trust (NBFT) capital lease agreement to finance up to $530 million of nuclear fuel for Millstone 1 and 2 and their share's of the nuclear fuel for Millstone 3. 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, 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 rental payments that have been charged to operating expense are provided on the next page: Capital Operating Year Leases Leases ---- ------------ ---------- 1994 ........... $13,594,000 $6,485,000 1993 ........... 17,280,000 6,367,000 1992 ........... 13,799,000 7,263,000 Interest included in capital lease rental payments was $1,845,000 in 1994, $2,090,000 in 1993, and $2,895,000 in 1992. 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, 1994, are as follows: Year Operating Leases ---- ---------------- (Thousands of Dollars) 1995 ..................... $ 4,800 1996 ..................... 4,400 1997 ..................... 4,100 1998 ..................... 3,200 1999 ..................... 3,000 After 1999 ............... 32,000 -------- Future minimum lease payments $51,500 ======= 3. NUCLEAR DECOMMISSIONING 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, technology, and inflation. The estimated cost of decommissioning WMECO's ownership share of Millstone 1, 2, and 3, in year-end 1994 dollars, is $78.1 million, $62.7 million, and $54.9 million, respectively. These estimated costs have been levelized and assumed after-tax earnings on the Millstone decommissioning fund of 6.5 percent. Future escalation rates in decommissioning costs for the Millstone units are assumed. 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 $4.8 million in 1994, $4.6 million in 1993 and 1992. Nuclear decommissioning, as a cost of removal, is included in the accumulated provision for depreciation on the Balance Sheets. At December 31, 1994, the balance in the accumulated reserve for decommissioning amounted to $56.1 million. See "Nuclear Decommissioning" in the Management's Discussion and Analysis for a discussion of changes being considered by the FASB relating to accounting for decommissioning costs. WMECO has established independent decommissioning trusts for its portion of the costs of decommissioning Millstone 1, 2, and 3. As of December 31, 1994, WMECO has collected, through rates, $42.4 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. Due to WMECO's adoption, effective January 1, 1994, of SFAS 115, Accounting for Certain Investments in Debt and Equity Securities, 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. WMECO attempts to recover sufficient amounts through its 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 company. Because allowances for decommissioning have increased significantly in recent years, customers in future years may need to increase their payments to offset the effects of any insufficient rate recoveries in previous years. WMECO, along with other New England utilities, has equity investments in the four Yankee companies. Each Yankee company owns a single nuclear generating unit. WMECO's ownership share of estimated costs, in year-end 1994 dollars, of decommissioning CY, MY, and VY are $34.4 million, $10.1 million, and $8.2 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 by WMECO. YAEC has begun component-removal activities related to decommissioning of its nuclear facility. In June 1992, YAEC filed a rate filing to obtain FERC authorization to collect the closing and decommissioning costs and to recover the remaining investment in the YAEC nuclear power plant over the remaining period of the plant's Nuclear Regulatory Commission (NRC) operating license. The bulk of these costs has been agreed to by the YAEC joint owners and approved, as a settlement, by FERC. In October 1994, YAEC submitted a revised decommissioning cost estimate as part of its decommissioning plan with the NRC. Following the receipt of NRC approval, this estimate will be filed with the FERC. The revised estimate increased WMECO's ownership share of decommissioning YAEC's nuclear facility by approximately $6.6 million in January 1, 1994 dollars. At December 31, 1994, the estimated remaining costs including decommissioning amounted to $408.2 million, of which WMECO's share was approximately $28.6 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 a regulatory asset, with a corresponding obligation, on its Balance Sheets. 4. SHORT-TERM DEBT The system companies have various revolving credit lines totaling $485 million. NU, CL&P, WMECO, HWP, NNECO, and The Rocky River Realty Company (RRR) have established a revolving-credit facility with a group of 16 banks. Under this facility, the participating companies may borrow up to an aggregate of $360 million. Individual borrowing limits as of January 1, 1995 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 0.20 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 0.135 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, 1994, there were $30.0 million of borrowings under the facility, all of which had been borrowed by other system companies. The weighted average interest rate on notes payable to banks outstanding on December 31, 1993 was 3.3 percent. 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. 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's parent's original borrowing. Investing and borrowing subsidiaries receive or pay interest based on the average daily Federal Funds rate. At December 31, 1994 and 1993, WMECO had no outstanding borrowings from the Pool. 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 the company 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 redemption are: December 31, Shares 1994 Outstanding RedemptionDecember 31, December 31, ----------------------- Description Price 1994 1994 1993 1992 -------------------------------------------------------------------- (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 1,940,000 48,500 53,500 53,500 ------- ------ ------ Total preferred stock not subject to mandatory redemption ........ $68,500 $73,500 $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 December 31, 1994 Outstanding ------------------------ Redemption December 31, Description Price* 1994 1994 1993 1992 -------------------------------------------------------------------- (Thousands of Dollars) 7.60% Series of 1987 $26.02 987,000 $24,675 $27,000 $28,500 Less preferred stock to be redeemed within one year, net of reacquired stock 27,000 675 1,500 1,500 ------- ------- ------- Total preferred stock subject to mandatory redemption $24,000 $25,500 $27,000 ======= ======= ======= *Redemption price reduces in future years. The minimum sinking-fund provisions of the 1987 Series subject to mandatory redemption at December 31, 1994, for the years 1995 through 1999, 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. 7. LONG-TERM DEBT Details of long-term debt outstanding are: December 31, 1994 1993 ---------------------------------------------------------------- (Thousands of Dollars) First Mortgage Bonds: 9 1/4% Series U, .......due 1995 $ 34,300 $ 34,650 5 3/4% Series F, .......due 1997 14,850 15,000 7 3/8% Series H, .......due 1998 - 15,000 6 3/4% Series G, .......due 1998 9,900 10,000 6 1/4% Series X, .......due 1999 40,000 - 6 7/8% Series W, .......due 2000 60,000 60,000 7 3/4% Series J, .......due 2002 - 30,000 7 3/4% Series V, .......due 2002 85,000 85,000 7 3/4% Series Y, .......due 2024 50,000 - 9 3/4% Series R, .......due 2016 - 24,750 10 1/8% Series T, .......due 2018 - 33,819 --------- -------- Total First Mortgage Bonds .... 294,050 308,219 Pollution Control Notes: Tax Exempt Series A, due 2028 53,800 53,800 Fees and interest due for spent fuel disposal costs (Note 1M) ........... 33,239 31,930 Less: Amounts due within one year ... 34,300 - Unamortized premium and discount, net (1,120 (717) ------- -------- Long-term debt, net .................. $345,669 $393,232 ======== ======== Long-term debt maturities and cash sinking-fund requirements on debt outstanding at December 31, 1994 for the years 1995 through 1999 are approximately: $34,300,000 in 1995, $0 in 1996, $14,850,000 in 1997, $9,900,000 in 1998, and $40,000,000 in 1999. In addition, there are annual 1-percent sinking- and improvement-fund requirements, currently amounting to $2,950,000 in 1995, $2,600,000 in 1996 and 1997, $2,450,000 in 1998, and $2,350,000 in 1999. 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 liens of its first mortgage bond indenture. As of December 31, 1994 and 1993 , 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 indentures. The average effective interest rates on the variable-rate pollution control notes was 2.7 percent for 1994 and 2.5 percent for 1993. 8. INCOME TAX EXPENSE The components of the federal and state income tax provisions are: For the Years Ended December 31, 1994 1993 (Note 1I) 1992 ---------------------------------------------------------------- (Thousands of Dollars) Current income taxes: Federal ..................... $18,358 $22,239 $16,736 State ....................... 4,110 4,712 4,165 -------- -------- --------- Total current ............. 22,468 26,951 20,901 -------- -------- -------- Deferred income taxes, net: Federal ..................... 9,697 1,683 (1,466) State ....................... 2,267 664 117 ------- -------- -------- Total deferred ............ 11,964 2,347 (1,349) ------- -------- -------- Investment tax credits, net (1,708) (1,429) (1,251) ------ ------- ------- Total income tax expense ...... $32,724 $27,869 $18,301 ======= ======= ======= The components of total income tax expense are classified as follows: Income taxes charged to operating expenses ...................... $33,540 $28,173 $20,926 Income taxes associated with the amortization of deferred Millstone 3 return - borrowed funds ....... - - (2,410) Income taxes associated with allowance for funds used during construction (AFUDC) and deferred Millstone 3 return - borrowed funds - - 595 Other income taxes - credit .... (816) (304) (810) ------- ------- ------- Total income tax expense ......... $32,724 $27,869 $18,301 ======= ======= ======= Deferred income taxes are comprised of the tax effects of temporary differences as follows: For the Years Ended December 31, 1994 1993 (Note 1I)1992 ---------------------------------------------------------------- (Thousands of Dollars) Depreciation, leased nuclear fuel, settlement credits,and disposal costs ...................... $ 7,016 $6,852 $ 4,070 Energy adjustment clause ...... 3,598 (2,627) (4,663) AFUDC and deferred Millstone 3 return, net................. (2,203) (2,191) (1,815) Deferred refueling cost ....... 401 413 666 Early retirement program ...... 133 (544) (775) Loss on bond redemption ....... 2,064 1,561 18 Demand-side management ........ 466 (712) 394 Other ......................... 489 (405) (794) ------- ------ ------- Deferred income taxes, net .... $11,964 $2,347 $(1,349) ======= ====== ======= A reconciliation between income tax expense and the expected tax expense at the applicable statutory rates is as follows: For the Years Ended December 31, 1994 1993 (Note 1I) 1992 ------------------------------------------------------------------- (Thousands of Dollars) Expected federal income tax at 35 percent of pretax income for 1994 and 1993 and 34 percent for 1992 .. $28,763 $23,962 $18,810 Tax effect of differences: Depreciation differences .... 1,740 1,784 (1,584) Deferred Millstone 3 return - other funds ................ (266) (504) (721) Amortization of deferred Millstone 3 return - other funds ....... 3,347 3,341 2,856 Investment tax credit amortization (1,708) (1,429) (1,251) State income taxes, net of federal benefit ........... 4,144 3,494 2,829 Adjustment for prior years taxes (825) - (1,500) Other, net .................. (2,471) (2,779) (1,138) ------- ------- ------- Total income tax expense ...... $32,724 $27,869 $18,301 ======= ======= ======= 9. EMPLOYMENT 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 $(1.0) million in 1994, $1.2 million in 1993, and $(0.5) million in 1992. The company's pension costs for 1994 and 1993 included approximately $0.8 million and $2.7 million, respectively, related to a work force reduction program. 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, 1994 1993 1992 ---------------------------------------------------------------- (Thousands of Dollars) Service cost .............. $ 2,720 $4,702 $2,403 Interest cost ............. 7,655 7,527 7,875 Return on plan assets ..... 221 (17,272) (8,820) Net amortization .......... (11,635) 6,246 (1,962) ------- ------- ------ Net pension (income)/cost . $(1,039) $1,203 $ (504) ======= ====== ====== ------------------------------------------------------------- For calculating pension cost, the following assumptions were used: For the Years Ended December 31, 1994 1993 1992 -------------------------------------------------------------- Discount rate ............. 7.75% 8.00% 8.50% Expected long-term rate of return ................ 8.50 8.50 9.00 Compensation/progression rate 4.75 5.00 6.75 The following table represents the Plan's funded status reconciled to the Balance Sheets: At December 31, 1994 1993 -------------------------------------------------------------- (Thousands of Dollars) Accumulated benefit obligation, including $89,159,000 of vested benefits at December 31, 1994 and $82,601,000 of vested benefits at December 31, 1993 ............ $ 85,193 $ 88,554 ========= ========= Projected benefit obligation .. $ 99,667 $104,288 Market value of plan assets ... 122,813 130,803 -------- -------- Market value in excess of projected benefit obligation ........... 23,146 26,515 Unrecognized transition amount (2,433) (2,668) Unrecognized prior service costs (560) (581) Unrecognized net gain ......... (22,068) (26,220) ---------- ---------- Accrued pension liability ..... $ (1,915) $ (2,954) ========== ========== ------------------------------------------------------------ The following actuarial assumptions were used in calculating the Plan's year-end funded status: At December 31, 1994 1993 ------------------------------------------------------------- Discount rate ................. 8.25% 7.75% Compensation/progression rate . 5.00 4.75 ------------------------------------------------------------- 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. These benefits are available for employees leaving the company who are otherwise eligible to retire and have met specified service requirements. Effective January 1, 1993, the company adopted SFAS 106, Employer's Accounting for Postretirement Benefits Other Than Pensions, on a prospective basis. WMECO's direct portion of health care and life insurance costs, part of which were deferred or charged to utility plant, approximated $5.0 million in 1994 and 1993, and $2.2 million in 1992. On January 1, 1993, the accumulated postretirement benefit obligation represented the company's transition obligation upon the adoption of SFAS 106. As allowed by SFAS 106, the company is amortizing its transition obligation of approximately $33 million over a 20-year period. 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. Effective July 1994, the company funded SFAS 106 postretirement costs through external trusts. The company will fund annually amounts once they 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. During 1993, the company did not fund SFAS 106 costs. The following table represents the plan's funded status reconciled to the Balance Sheets: At December 31, 1994 1993 -------------------------------------------------------------- (Thousands of Dollars) Accumulated postretirement benefit obligation of: Retirees $29,619 $27,685 Fully eligible active employees .. 28 38 Active employees not eligible to retire 4,823 5,488 --------- --------- Total accumulated postretirement benefit obligation ............... 34,470 33,211 Market value of plan assets ........ 2,026 - --------- --------- Accumulated postretirement benefit obligation in excess of plan assets (32,444) (33,211) Unrecognized transition amount ..... 29,542 31,183 Unrecognized net gain .............. (477) (587) --------- --------- Accrued postretirement benefit liability $ (3,379) $ (2,615) ======== ======== ------------------------------------------------------------- The components of health care and life insurance costs are: For the Years Ended December 31, 1994 1993 -------------------------------------------------------------- (Thousands of Dollars) Service cost ....................... $ 519 $ 659 Interest cost ...................... 2,703 2,676 Return on plan assets .............. 19 - Net amortization ................... 1,717 1,703 ------- ------- Net health care and life insurance costs $4,958 $5,038 ====== ====== ------------------------------------------------------------- The following actuarial assumptions were used in calculating the plan's year-end funded status: At December 31, 1994 1993 ------------------------------------------------------------ Discount rate ...................... 8.00% 7.75% Long-term rate of return - health assets, net of tax ....................... 5.00 5.00 Long-term rate of return - life assets 8.50 8.50 Health care cost trend rate (a) .... 10.20 11.10 (a) The annual growth in per capita cost of covered health care benefits was assumed to decrease to 5.4 percent by 2002. 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, 1994 by $2.1 million and the aggregate of the service and interest cost components of net periodic postretirement benefit cost for the year then ended by $185,000. 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 previously deferred costs. Deferral of such costs is permitted since it is expected that the period of recovery of deferred costs will be within the time frame established by the applicable accounting requirements. 10. COMMITMENTS AND CONTINGENCIES A.CONSTRUCTION PROGRAM The construction program is subject to periodic review and revision. Actual construction expenditures may vary from estimates due to factors such as revised load estimates, inflation, revised nuclear safety regulations, delays, difficulties in the licensing process, the availability and cost of capital, and the granting of timely and adequate rate relief by regulatory commissions, as well as actions by other regulatory bodies. The company currently forecasts construction expenditures (including AFUDC) of $170.4 million for the years 1995-1999, including $36.3 million for 1995. In addition, the company estimates that nuclear fuel requirements, including nuclear fuel financed through the NBFT, will be $58.9 million for the years 1995-1999, including $10.7 million for 1995. 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 has encountered several unexpected difficulties which have lengthened the duration of the outage. The magnitude of the schedule impact is currently under review, but the unit is not expected to return to service before April 1995. WMECO expects that replacement power costs in the range of $1 million per month will be attributable to the extension of the outage. Recovery of the costs related to this outage is subject to scrutiny by the DPU. 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. Changing environmental requirements could hinder the construction of new generating units, transmission and distribution lines, substations, and other facilities. The cumulative long-term, economic 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 is, based upon information currently available, its estimated environmental remediation costs for waste disposal sites for which it expects to bear legal liability. In most cases, the extent of additional future environmental cleanup costs is 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, 1994, the liability recorded by WMECO for its estimated environmental remediation costs, excluding any possible insurance recoveries or recoveries from third parties, amounted to approximately $700,000. However, in the event that it becomes necessary to effect environmental remedies that are currently not considered probable, it is reasonably possible that the upper limit of the system's environmental liability range could increase to approximately $2.3 million. WMECO cannot estimate the potential liability for future claims 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 The Price-Anderson Act currently limits public liability from a single incident at a nuclear power plant to $8.9 billion. The first $200 million of liability would be provided by purchasing the maximum amount of commercially available insurance. Additional coverage of up to a total of $8.3 billion would be provided by an assessment of $75.5 million per incident, levied on each of the 110 nuclear units that are currently subject to the Secondary Financial Protection Program in the United States, subject to a maximum assessment of $10 million per incident per nuclear unit in any year. In addition, if the sum of all public liability claims and legal costs arising from any nuclear incident exceeds the maximum amount of financial protection, each reactor operator can be assessed an additional 5 percent, up to $3.8 million, or $415.3 million in total, for all 110 nuclear units. The maximum assessment is to be adjusted at least every five years to reflect inflationary changes. Based on WMECO's ownership interests in Millstone 1, 2, and 3, WMECO's maximum liability would be $39.8 million per incident. In addition, through WMECO's 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. Effective January 1, 1995, insurance was purchased from Nuclear Mutual Limited (NML) to cover the primary cost of repair, replacement, or decontamination of utility property resulting from insured occurrences with respect to WMECO's ownership interest in Millstone 1, 2, 3, and CY. All companies insured with NML are subject to retroactive assessments if losses exceed the accumulated funds available to NML. The maximum potential assessment against WMECO with respect to losses arising during the current policy year is approximately $3.1 million under the NML primary property insurance program. Insurance has been purchased from Nuclear Electric Insurance Limited (NEIL) to cover: (1) certain extra costs incurred in obtaining replacement power during prolonged accidental outages with respect to WMECO's ownership interests in Millstone 1, 2, and 3, and CY, and (2) the excess cost of repair, replacement, or decontamination or premature decommissioning of utility property resulting from insured occurrences with respect to WMECO's ownership interests in Millstone 1, 2, and 3, CY, MY, and VY. All companies insured with NEIL are subject to retroactive assessments if losses exceed the accumulated funds available to NEIL. The maximum potential assessments against WMECO with respect to losses arising during current policy years are approximately $1.7 million under the replacement power policies and $7.7 million under the excess property damage, decontamination, and decommissioning policies. Although WMECO 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 from American Nuclear Insurers/Mutual Atomic Energy Liability Underwriters, 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 $3.1 million per reactor. The maximum potential assessments against WMECO with respect to losses arising during the current policy period are approximately $2.2 million. E.PURCHASED POWER ARRANGEMENTS WMECO, along with CL&P and PSNH, purchase approximately ten percent of their electricity requirements pursuant to long-term contracts with the Yankee companies. Under the terms of its agreement, the company pays its ownership share (or entitlement share) of generating costs, which include depreciation, operation and maintenance expenses, taxes, the estimated cost of decommissioning, and a return on invested capital. These costs are recorded as purchased power expense, and are recovered through the company's rates. WMECO's total cost of purchases under these contracts for the units that are operating amounted to $28.8 million in 1994, $30.2 million in 1993, and $29.2 million in 1992. See Note 1D, "Summary Of Significant Accounting Policies - Investments and Jointly Owned Electric Utility Plant" and Note 3, "Nuclear Decommissioning" for more information on the Yankee companies. 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, and require the company to purchase the energy at specified prices or formula rates. For the 12 months ended December 31, 1994, approximately 14 percent of system electricity requirements was met by nonutility generators. The total cost of the company's purchases under these arrangements amounted to $27.5 million in 1994, $13.6 million in 1993, and $4.8 million in 1992. These costs are recovered through the company's rates. The estimated annual costs of the significant purchase power arrangements are as follows: 1995 1996 1997 1998 1999 ------------------------------------------------------------- (Millions of Dollars) Yankee companies ...... $31.0 $32.6 $29.2 $34.0 $32.3 Nonutility generators . 29.7 30.9 32.5 34.1 35.8 ------------------------------------------------------------- F.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, its proportionate share of the annual operation, maintenance, and capital costs of these facilities. WMECO's share of Hydro-Quebec costs are currently forecast to be $19.9 million for the years 1995-1999, including $4.4 million for 1995. 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. 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 bonds. During 1994, there was one outstanding contract held by WMECO, covering $52 million of its pollution control bond, with a term of three years. The contract entitles WMECO to receive from its counterparty 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. This contract is settled on a quarterly basis. As of December 31, 1994, WMECO had a total notional amount of $52 million in caps outstanding, with a positive mark-to-market position of approximately $0.6 million. WMECO is exposed to credit risk on the interest-rate caps if the counterparty fails to perform its obligation. However, WMECO anticipates that the counterparty will be able to fully satisfy its obligations under the contract. 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 amount approximates fair value. SFAS 115 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. As a result of the adoption of SFAS 115, the investments held in the company's nuclear decommissioning trusts decreased by approximately $800,000 as of December 31, 1994, with a corresponding offset to the accumulated provision for depreciation. The $800,000 decrease represents cumulative gross unrealized holding gains of $300,000, 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, 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 ----------------------------------------------------------------- Carrying Fair At December 31, 1993 Amount Value ----------------------------------------------------------------- (Thousands of Dollars) Preferred stock not subject to mandatory redemption ......... $ 73,500 $ 74,000 Preferred stock subject to mandatory redemption ......... 27,000 28,215 Long-term debt - First Mortgage Bonds ....... 308,219 319,213 Other long-term debt ....... 85,730 85,730 ----------------------------------------------------------------- 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. WESTERN MASSACHUSETTS ELECTRIC COMPANY ------------------------------------------------------------ Report of Independent Public Accountants ------------------------------------------------------------- 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, 1994 and 1993, 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, 1994. 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, 1994 and 1993, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1994, in conformity with generally accepted accounting principles. As discussed in Notes 1B and 9B to the Financial Statements, effective January 1, 1993, Western Massachusetts Electric Company changed its methods of accounting for property taxes, and postretirement benefits other than pensions. /s/Arthur Andersen LLP ARTHUR ANDERSEN LLP Hartford, Connecticut February 17, 1995 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 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 increased to approximately $49 million in 1994 from approximately $41 million in 1993. The 1994 increase in net income is due primarily to reduced operation and interest costs. The 1993 net income includes the impact of a change in the method of accounting for Connecticut municipal property taxes which resulted in an increase to net income of approximately $4 million. In addition, 1993 net income reflected a decrease of approximately $2 million for the costs of an employee reduction program. Net income before these one-time items was approximately $39 million in 1993. In 1994, the company experienced modest retail kilowatt-hour sales growth, due in large part to the beginning of an economic recovery in New England. Employment levels have risen, unemployment rates have fallen, and personal income has increased. The company's 1994 retail kilowatt-hour sales rose by 1.4 percent over 1993. Overall, weather had little effect on sales volume, with mild weather after mid-August offsetting unusually cold weather in January and hot weather in late June and July. In 1995, the company expects little retail sales growth over 1994, primarily because of the effects of higher interest rates on the regional economy. The company estimates compounded annual sales growth of 0.9 percent from 1994 through 1999. Competitive forces within the electric utility industry are continuing to increase due to a variety of influences, including legislative and regulatory actions, technological advances, and changes in consumer demand. The company has developed, and is continuing to develop, a number of initiatives to retain and continue to serve its existing customers and to expand its retail and wholesale customer base. The company believes the steps it is taking, including a companywide process reengineering effort, will have significant, positive effects, including reduced operating costs and improved customer service, in the next few years. The company also benefits from a diverse retail base with no significant dependence on any one retail customer or industry. WMECO continues to operate predominantly in a state-approved franchise under traditional cost-of-service regulation. Retail wheeling, under which a retail customer would be permitted to select an electricity supplier and require the local electric utility to transmit the power to the customer's site, is not required in Massachusetts. However, bills related to retail wheeling have been introduced in the legislature. Massachusetts regulators have been studying the potential restructuring of the electric utility industry. To date, none of these bills have been enacted and the regulatory proceeding has not progressed to the point where management can assess the impact of any potential outcomes on the company. While retail competition is not required in the company's retail service territory, competitive forces are nonetheless influencing retail pricing. These forces include competition from alternate fuels such as natural gas, competition from customer-owned generation and regional competition for business retention and expansion. The company's retail business group continues to work with customers to address their concerns. The company has reached long-term rate agreements with many new and existing customers to gain or retain their business. In general, these rate agreements have terms of about five years. Negotiated retail rate reductions for customers under rate agreements in effect for 1994 amounted to approximately $4 million. Management believes that the aggregate amount of retail rate reductions will increase in 1995 but that the related agreements will continue to provide significant benefits to the company, including the preservation of approximately 7 percent of retail revenues. The company is also working with its regulators to address the needs of customers more widely. The company has a 20-month rate plan in effect through February 1996. Management will continue to evaluate the use of agreements of this type to keep retail rates competitive. The company acts as both a buyer and a seller of electricity in the highly competitive wholesale electricity market in the Northeastern United States (Northeast). Many of the contracts signed in the late 1980s have or will expire in the mid-1990s and much of revenues produced by such contracts has not been replaced through new wholesale power arrangements. In the last few years NU has entered into several smaller long-term sales contracts which will continue approximately through the year 2005. Wholesale sales are made primarily to investor-owned utilities throughout the Northeast. The company will be increas- ing its efforts to increase wholesale sales through intensified marketing efforts. The company's wholesale power marketing efforts benefit from the interconnection of the NU system's transmission system with all the major utilities in New England. RATE MATTERS The company follows accounting principles that allow the rate treatment for certain events or transactions to be reflected. These principles may differ from the accounting principles followed by nonregulated enterprises. Regulators may permit incurred costs, which would normally be treated as expenses by nonregulated enterprises, to be deferred as regulatory assets and recovered in revenues at a later date. Regulatory assets at December 31,1994 were approximately $184 million. Based on current regulation,the company believes that its use of regulatory accounting is still appropriate. See "Notes to Consolidated Financial Statements," Note 1H, for further details on regulatory accounting. On May 26, 1994, the Massachusetts Department of Public Utilities (DPU) approved a settlement agreement under which WMECO's customers received a base-rate reduction of approximately $13 million over a 20-month period effective June 1, 1994 and a guarantee of no general base-rate increases before February 1996. This agreement also terminated, without findings, all performance review proceedings regarding the treatment of replacement-power costs incurred by WMECO during power outages from mid-1987 through mid-1993. The DPU also approved the amortization of previously deferred expenses for postretirement benefits beginning in July 1994. In addition, under the agreement, WMECO's largest customers will be offered discounts on their electric bills in return for providing WMECO with five years' notice of any plans to self-generate or purchase electricity from a different provider. The combined base-rate reduction and service-extension discounts will total approximately 5 percent for those larger customers. The settlement agreement did not have a significant adverse impact on WMECO's earnings. NUCLEAR PERFORMANCE The composite capacity factor of the five nuclear generating units that the NU system operates (including the Connecticut Yankee [CY] unit) was 67.5 percent for 1994, compared with 80.8 percent for 1993 and a 1994 national average of 73.2 percent. The lower 1994 capacity factor was primarily the result of extended refueling and maintenance outages for Millstone 1, Millstone 2, and Seabrook. CY, Seabrook, and Millstone 2 were also out of service for varying lengths of time in 1994 because of unexpected technical and operating difficulties. These difficulties included a manual shutdown of CY when both service water headers were declared inoperable and an automatic trip from 100 percent power for Seabrook when a main steam isolation valve closed during quarterly surveillance testing, and a Millstone 2 shutdown to replace a degraded lower seal on a reactor coolant pump. On October 1, 1994, Millstone 2 was shut down for a planned 63 day refueling and maintenance outage. The outage has encountered several unexpected difficulties, which will lengthen the duration of the outage. The outage extensions were caused by a significant scope increase in service water system repairs as identified through a comprehensive inspection plan and by a need for management to exercise a deliberate approach to the conduct of work during the early portions of the outage. The outage schedule is currently under review, but the unit is not expected to return to service before April 1995. Replacement power costs attributable to the extension of the outage for WMECO are expected to be in the range of approximately $1 million per month. These costs are recovered through WMECO's fuel adjustment clause. In addition, WMECO'S share of the operation and maintenance costs to be incurred during the outage are estimated to be $10 million, an increase of approximately $4 million as a result of the extension. The recovery of these costs is subject to prudence reviews in Massachusetts. The Nuclear Regulatory Commission (NRC's) latest report for the Millstone Station noted significant weaknesses of Millstone's 2 operations and maintenance. In a public statement in late 1994, a senior NRC official expressed disappointment with the continued weaknesses in Millstone 2's performance. The primary cause of the NRC's disappointment with Millstone 2's performance appears to be that, despite significant management attention and action over a period of years, the NRC does not believe it has seen enough objective evidence of improvement in reducing procedural noncompliance and other human errors. Management has acknowledged the basis for the NRC's concern with Millstone 2 and has been devoting increased attention to resolving these issues. Management and the NRC expect to continue to monitor closely the developments at Millstone 2. ENVIRONMENTAL MATTERS NU devotes substantial resources to identify and then to meet the multitude of environmental requirements it faces. NU has active auditing programs addressing a variety of different regulatory requirements, including an environmental auditing program to detect and remedy noncompliance with environmental laws or regulations. The company 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 liabilities has not been material with respect to the earnings or financial position of the company. At December 31, 1994, the liability recorded by the company, amounted to approximately $1 million. These costs could rise to as much as approximately $2 million if alternate remediation remedies become necessary. The company expects that the implementation of the 1990 Clean Air Act Amendments (CAAA) as they relate to sulfur dioxide emissions will require only modest emission reductions for the company. WMECO's exposure is minimal because of the companies' investment in nuclear energy in the 1970s and 1980s and the burning of low-sulfur fuels. The CAAA requirements for emissions limits for nitrogen oxides will initially be met by capital expenditures of approximately $1 million. NUCLEAR DECOMMISSIONING The company's estimated cost to decommission its shares of Millstone units 1, 2, and 3 is approximately $196 million in year-end 1994 dollars. In addition, the company's estimated cost to decommission its shares of the regional nuclear generating units is approximately $53 million. These costs are being recognized over the lives of the respective units and a portion of the costs is being recovered through rates. Yankee Atomic Electric Company (YAEC) has begun compo- nent removal activities related to the decommissioning of its nuclear facility. The company's estimated obligation to YAEC has been recorded on its Balance Sheets. Management expects that the company will continue to be allowed to recover these costs. The staff of the Securities and Exchange Commission has questioned certain of the current accounting practices of the electric utility industry, including this company, regarding the recognition, measurement, and classification of decommissioning costs for nuclear generating stations in the financial statements of electric utilities. The Financial Accounting Standards Board is currently reviewing the accounting for removal costs, including decommissioning and similar costs. If current electric utility industry accounting practices for such decommissioning costs are changed: (1) annual provisions for decom- missioning could increase, (2) the estimated costs for decommissioning could be recorded as a liability rather than as accumulated depreciation, and (3) trust fund income from the external decommissioning trust could be reported as investment income rather than as a reduction to decommissioning expense. See the "Notes To Financial Statements," Note 3, for further information on nuclear decommissioning. PROPERTY TAXES CY has a significant court appeal for municipal property tax assessments in the town of Haddam, Connecticut. The central issue in this case is the fair market value of utility property. CY 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, Massachusetts, and some of New Hampshire. However, towns such as Haddam advocate a method that approximates reproduction costs. CY's appeal is still pending. The company estimates that, for assessments in towns such as Haddam, the change to the reproduction cost methodology could result in property valuations approximately three times greater than values approximating net book cost. If other towns in Connecticut or Massachusetts adopt this methodology, there could be a significant adverse impact on the company's future results of operations and financial condition. However, the extent to which other towns successfully adopt this methodology and any subsequent increase in the company's property tax liability cannot be determined at this time. LIQUIDITY AND CAPITAL RESOURCES Cash provided from operations in 1994 was relatively flat as compared with 1993. Cash used for financing activities was approximately $9 million lower in 1994, as compared with 1993, primarily due to lower repayment of short-term debt, partially offset by higher net reacquisitions and retirements of long-term debt. Cash used for investments was approximately $8 million higher in 1994, compared with 1993, primarily due to an increase in loans to other system companies under the NU system money pool. In 1994, the company refinanced approximately $90 million of debt, which is expected to reduce interest costs by approximately $2 million annually. With interest rates rising in mid-1994, a lot of refinancing completed, and construction needs remaining modest, the focus of the company's financing activities will shift toward using the significant amount of cash generated by the company to retire debt and to prepare the company for an increasingly competitive business. The company is obligated to meet approximately $107 million of long-term debt and preferred stock maturities and cash sinking-fund requirements during the 1995 through 1999 period, including approximately $36 million for 1995. The company's construction program expenditures, including allowance for funds used during construction (AFUDC), for the period 1995 through 1999 are estimated to be approximately $170 million, including approximately $36 million for 1995. The construction program's main focus is maintaining and upgrading the existing transmission and distribution system, as well as nuclear and fossil-generating facilities. NU does not foresee the need for new major generating facilities, at least until the year 2009. Construction expenditures and debt sinking fund requirements will continue to be met through internal cash generation. WMECO entered into interest rate cap contracts to reduce a portion of interest rate risk on certain variable-rate tax-exempt pollution control revenue bonds. Any premiums paid on these contracts are deferred and amortized over the life of the contracts. The differential paid or received as interest rates is recognized in income when realized. 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) 1994 vs. 1993 1993 vs. 1992 -------------------------------------------------------------------- (Millions of Dollars) Regulatory decisions $(4) $12 Fuel and purchased power cost recoveries 13 (19) Sales volume - 4 Wholesale Revenues - 8 Other revenues (3) (1) -- --- Total revenue change $ 6 $ 4 === === Operating revenues increased approximately $6 million in 1994 as compared with 1993. Revenues related to regulatory decision decreased in 1994, primarily because 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. Operating revenues increased approximately $4 million in 1993 as compared with 1992. Revenues related to regulatory decisions increased primarily because of the effects of the July 1992 and July 1993 retail rate increases. Fuel and purchased power cost recoveries decreased primarily due to lower energy costs. Retail sales in 1993 were relatively flat. Wholesale revenues increased primarily because of higher capacity interchange revenues. FUEL, PURCHASED, AND NET INTERCHANGE POWER Fuel, purchased, and net interchange power decreased approximately $19 million in 1993, as compared to 1992, primarily due to lower outside purchases as a result of better nuclear performance in 1993. OTHER OPERATION AND MAINTENANCE EXPENSES Other operation and maintenance expenses decreased approximately $10 million in 1994, as compared with 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. Other operation and maintenance expenses increased approximately $11 million in 1993, as compared to 1992, primarily due to higher capacity interchange charges, increased demand-side-management costs, and the 1993 one-time costs associated with an employee-reduction program, partially offset by lower 1993 costs associated with the operation and maintenance activities of the nuclear units. AMORTIZATION OF REGULATORY ASSETS, NET Amortization of regulatory assets, net increased approximately $3 million in 1993, as compared to 1992, primarily because of higher amortization of Millstone 3 deferred costs. FEDERAL AND STATE INCOME TAXES Federal and state income taxes increased approximately $5 million in 1994, as compared to 1993 due primarily to higher taxable income. Federal and state income taxes increased approximately $8 million in 1993, as compared to 1992, primarily because of higher taxable income and one-time adjustments in 1992 causing 1992 taxes to be lower than would otherwise be expected. INTEREST CHARGES Interest on long-term debt decreased approximately $2 million in 1994, as compared to 1993, primarily because of 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 $4 million in 1993 represents the one-time change in the method of accounting for Connecticut municipal property tax expense recognized in the first quarter of 1993. -------------------------------------------------------------------------- SELECTED FINANCIAL DATA -------------------------------------------------------------------------- 1994 1993 1992 1991 1990 -------------------------------------------------------------------------- (Thousands of Dollars) Operating Revenues.......$ 421,477 $ 415,055 $ 410,720 $ 409,840 $ 375,456 Operating Income......... 70,053 60,067 60,513 59,723 57,448 Net Income............... 49,457 40,594(a) 37,022 34,637 35,191 Cash Dividends on Common Stock........... 29,514 28,785 29,536 31,499 34,459 Total Assets.............1,183,618 1,204,642 1,130,684 1,119,593 1,134,986 Long-Term Debt*.......... 379,969 393,232 392,976 401,095 419,527 Preferred Stock Not Subject to Mandatory Redemption... 68,500 73,500 73,500 88,500 88,500 Preferred Stock Subject to Mandatory Redemption*... 24,675 27,000 28,500 28,502 30,000 Obligations Under Capital Leases*................. 36,797 36,902 41,509 44,134 52,370 * Includes portions due within one year. (a)Includes the cumulative effect of change in accounting for municipal property tax expense, which increased earnings for common shares by $3.9 million. STATEMENTS OF QUARTERLY FINANCIAL DATA (UNAUDITED) -------------------------------------------------------------------------- Quarter Ended --------------------------------------------------- 1994 March 31 June 30 September 30December 31 -------------------------------------------------------------------------- (Thousands of Dollars) Operating Revenues.. $112,984 $101,188 $102,597 $104,708 ======== ======== ======== ======== Operating Income.... $ 19,468 $ 21,268 $ 11,374 $ 17,943 ========= ======== ========= ========= Net Income.......... $ 13,961 $ 16,035 $ 6,395 $ 13,066 ========= ======== ========== ========= 1993 -------------------------------------------------------------------------- Operating Revenues.. $108,950 $ 92,383 $105,510 $108,212 ======== ======== ======== ======== Operating Income.... $ 17,659 $ 13,529 $ 13,045 $ 15,834 ========= ======== ======== ========= Net Income.......... $ 15,350 $ 7,316 $ 7,182 $ 10,746 ========= ========= ======== ========= 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,) --------------------------------------------------------------------- 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 1990 1,184,285 3,874 7,619 191,759 826 EX-13.4 19 Exhibit 13.4 1994 ANNUAL REPORT PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE --------------------------------------- 1994 Annual Report Public Service Company of New Hampshire Index Contents Page -------- ---- Balance Sheets..................................... 1-2 Statements of Income............................... 3 Statements of Cash Flows........................... 4 Statements of Common Equity........................ 5 Notes to Financial Statements...................... 6-27 Report of Independent Public Accountants........... 28 Management's Discussion and Analysis of Financial Condition and Results of Operations.............. 29-35 Selected Financial Data............................ 37-38 Statistics......................................... 39 Statements of Quarterly Financial Data............. 39 Preferred Stockholder and Bondholder Information... Back Cover PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE BALANCE SHEETS
------------------------------------------------------------------------------------- At December 31, 1994 1993 ------------------------------------------------------------------------------------- (Thousands of Dollars) ASSETS ------ Utility Plant, at original cost: Electric................................................ $2,038,625 $1,980,050 Less: Accumulated provision for depreciation......... 474,129 441,076 ----------- ----------- 1,564,496 1,538,974 Construction work in progress........................... 17,781 8,573 Nuclear fuel, net....................................... 2,248 2,107 ----------- ----------- Total net utility plant............................. 1,584,525 1,549,654 ----------- ----------- Other Property and Investments: Nuclear decommissioning trusts, at market in 1994 and at cost in 1993 (Note 12)......................... 1,815 1,486 Investments in regional nuclear generating companies and subsidiary company, at equity............ 19,551 19,816 Other, at cost.......................................... 394 429 ----------- ----------- 21,760 21,731 ----------- ----------- Current Assets: Cash.................................................... 322 5,995 Notes receivable from affiliated companies.............. 35,000 - Receivables, less accumulated provision for uncollectible accounts of $2,015,000 in 1994 and of $1,816,000 in 1993............................. 76,173 76,665 Accounts receivable from affiliated companies........... 3,779 859 Accrued utility revenues................................ 36,547 35,770 Fuel, materials, and supplies, at average cost.......... 37,453 41,187 Prepayments and other................................... 20,829 10,429 ----------- ----------- 210,103 170,905 ----------- ----------- Deferred Charges: Regulatory assets (Note 1H)........................ 971,505 973,353 Deferred receivable from affiliated company............. 33,284 33,284 Unamortized debt expense................................ 17,064 19,643 Other................................................... 7,726 5,941 ----------- ----------- 1,029,579 1,032,221 ----------- ----------- Total Assets........................................ $2,845,967 $2,774,511 =========== ===========
The accompanying notes are an integral part of these financial statements. PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE BALANCE SHEETS
-------------------------------------------------------------------------------------- At December 31, 1994 1993 -------------------------------------------------------------------------------------- (Thousands of Dollars) CAPITALIZATION AND LIABILITIES ------------------------------ Capitalization: Common stock, $1 par value--authorized and outstanding 1,000 shares in 1994 and 1993........... $ 1 $ 1 Capital surplus, paid in................................. 421,784 421,245 Retained earnings........................................ 125,034 60,840 ----------- ----------- Total common stockholder's equity............... 546,819 482,086 Cumulative preferred stock subject to mandatory redemption-- $25 par value--authorized 25,000,000 shares; outstanding 5,000,000 shares in 1994 and 1993 (Note 6)......................................... 125,000 125,000 Long-term debt (Note 7).............................. 905,985 999,985 ----------- ----------- Total capitalization............................ 1,577,804 1,607,071 ----------- ----------- Obligations Under Seabrook Power Contract and Other Capital Leases (Notes 2 and 3).......... 849,776 815,553 ----------- ----------- Current Liabilities: Notes payable to affiliated company...................... - 2,500 Long-term debt--current portion.......................... 94,000 94,000 Obligations under Seabrook Power Contract and other capital leases--current portion (Notes 2 and 3). 38,191 41,006 Accounts payable......................................... 45,984 27,119 Accounts payable to affiliated companies................. 17,309 17,576 Accrued taxes............................................ 4,304 122 Accrued interest......................................... 10,496 11,142 Accrued pension benefits................................. 36,269 31,890 Other.................................................... 20,350 22,014 ----------- ----------- 266,903 247,369 ----------- ----------- Deferred Credits: Accumulated deferred income taxes (Note 1K)......... 62,080 18,076 Accumulated deferred investment tax credits.............. 5,614 6,174 Deferred contract obligation--YAEC (Note 4).......... 28,572 24,150 Deferred revenue from affiliated company (Note 10G)........................................ 33,284 33,284 Other.................................................... 21,934 22,834 ----------- ----------- 151,484 104,518 ----------- ----------- Commitments and Contingencies (Note 10) Total Capitalization and Liabilities............ $2,845,967 $2,774,511 =========== ===========
The accompanying notes are an integral part of these financial statements. PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE STATEMENTS OF INCOME
------------------------------------------------------------------------------------------------------- January 1, January 1, June 5, January 1, 1994 1993 1992 1992 to to to to December 31, December 31, December 31, June 4, For the Periods 1994 1993 1992 1992 ------------------------------------------------------------------------------------------------------- (Thousands of Dollars) Operating Revenues.............................. $ 922,039 $ 864,415 $ 492,559 |$ 381,769 ------------- ------------- -------------|------------ Operating Expenses: | Operation -- | Fuel, purchased and net interchange power.. 222,801 208,023 105,346 | 123,784 Other...................................... 303,271 301,534 176,679 | 103,250 Maintenance................................... 43,725 35,427 20,535 | 22,520 Depreciation.................................. 38,703 38,580 21,526 | 25,183 Amortization of regulatory assets, net........ 55,319 67,379 51,143 | 36,528 Federal and state income taxes (Note 8)... 68,088 54,087 39,197 | 16,449 Taxes other than income taxes................. 38,046 34,675 16,927 | 19,805 ------------- ------------- -------------|------------ Total operating expenses................ 769,953 739,705 431,353 | 347,519 ------------- ------------- -------------|------------ Operating Income................................ 152,086 124,710 61,206 | 34,250 ------------- ------------- -------------|------------ Other Income: | | Deferred Seabrook return--other funds......... - - - | 12,101 Equity in earnings of regional nuclear | generating companies and subsidary company.. 2,079 1,777 1,031 | 869 Bankruptcy related expenses................... - - - | (5,084) Gain on generating projects................... - - - | 6,498 Other, net.................................... 629 635 2,519 | 63 Income taxes--(expense) credit................ (546) 3,868 14,254 | 12,814 ------------- ------------- -------------|------------ Other income, net....................... 2,162 6,280 17,804 | 27,261 ------------- ------------- -------------|------------ Income before interest charges.......... 154,248 130,990 79,010 | 61,511 ------------- ------------- -------------|------------ Interest Charges: | Interest on long-term debt.................... 76,410 77,842 47,625 | 54,125 Other interest................................ 394 911 1,987 | 3,913 Deferred Seabrook return--borrowed funds, | net of income taxes.......................... - - - | (9,305) ------------- ------------- -------------|------------ Interest charges, net................... 76,804 78,753 49,612 | 48,733 ------------- ------------- -------------|------------ | Net Income...................................... $ 77,444 $ 52,237 $ 29,398 |$ 12,778 ============= ============= =============|============
| PSNH became a wholly owned subsidiary of Northeast Utilities on June 5, 1992. The accompanying notes are an integral part of these financial statements. PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE STATEMENTS OF CASH FLOWS
------------------------------------------------------------------------------------------------------ Jan. 1, Jan. 1, Jun. 5, Jan. 1, 1994 1993 1992 1992 to to to to Dec. 31, Dec. 31, Dec. 31, Jun. 4, For the Periods 1994 1993 1992 1992 ------------------------------------------------------------------------------------------------------ (Thousands of Dollars) Cash Flows From Operating Activities: | Net Income...............................................$ 77,444 $ 52,237 $ 29,398 |$ 12,778 Adjustments to reconcile to net cash | from operating activities: | Depreciation........................................... 38,703 38,580 21,526 | 25,183 Deferred income taxes and investment tax credits, net.. 67,047 50,027 22,543 | 3,141 Deferred return - Seabrook............................. - - - | (21,406) Recoverable energy costs, net of amortization.......... (81,206) (39,654) (42,910)| 1,469 Amortization of regulatory asset, net.................. 55,319 67,379 51,143 | 36,528 Other sources of cash.................................. 3,213 30,001 12,816 | 15,967 Other uses of cash..................................... (4,535) (4,394) (4,435)| (4,400) Changes in working capital: | Receivables and accrued utility revenues............... (3,205) (3,161) (18,314)| 34,432 Fuel, materials, and supplies.......................... 3,734 3,936 459 | (4,945) Accounts payable....................................... 18,598 (2,894) 5,083 | (8,189) Accrued taxes.......................................... 4,182 (1,602) (17,323)| 20,409 Other working capital (excludes cash).................. 742 (2,224) 12,610 | (26,056) | ---------- ---------- ----------|---------- Net cash flows from operating activities................... 180,036 188,231 72,596 | 84,911 ---------- ---------- ----------|---------- Cash Flows Used For Financing Activities: | Issuance of common shares................................ - - 425,000 | - Issuance of long-term debt............................... - 44,800 75,000 | - Net decrease in short-term debt.......................... (2,500) (41,000) (64,500)| - Reacquisitions and retirements of long-term debt......... (94,000) (138,800) (171,000)| (27,000) Cash dividends on preferred stock........................ (13,250) (13,250) (9,938)| (3,312) Acquisition settlement................................... - - (841,466)| - ---------- ---------- ----------|---------- Net cash flows used for financing activities............... (109,750) (148,250) (586,904)| (30,312) ---------- ---------- ----------|---------- Investment Activities: | Investment in plant: | Electric utility plant................................. (39,721) (35,360) (15,352)| (25,266) Nuclear fuel........................................... (1,249) (614) (552)| (9,990) ---------- ---------- ----------|---------- Net cash flows used for investments in plant............. (40,970) (35,974) (15,904)| (35,256) Sale of Seabrook assets to NAEC (Note 1A)........... - - 504,265 | - NU System Money Pool..................................... (35,000) - - | - Other investment activities, net......................... 11 (340) (180)| - ---------- ---------- ----------|---------- Net cash flows (used for) from investments................. (75,959) (36,314) 488,181 | (35,256) ---------- ---------- ----------|---------- Net (Decrease) Increase in Cash for the Period............. (5,673) 3,667 (26,127)| 19,343 Cash - beginning of period................................. 5,995 2,328 28,455 | 9,112 ---------- ---------- ----------|---------- | Cash - end of period.......................................$ 322 $ 5,995 $ 2,328 |$ 28,455 ========== ========== ==========|========== Supplemental Cash Flow Information: | Cash paid during the year for: | Interest, net of amounts capitalized during construction.$ 74,507 $ 75,609 $ 35,405 |$ 53,427 ========== ========== ==========|========== | Income taxes.............................................$ 167 $ 2,390 $ 410 |$ 909 ========== ========== ==========|========== Increase in obligations: | Seabrook Power Contract..................................$ 51,924 $ 84,796 $ 37,490 |$ - ========== ========== ==========|========== Capital leases...........................................$ 1,342 $ 4,696 $ - |$ - ========== ========== ==========|========== PSNH became a wholly owned subsidiary of Northeast Utilities on June 5, 1992.
The accompanying notes are an integral part of these financial statements. PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE STATEMENTS OF COMMON EQUITY
--------------------------------------------------------------------------------------- Capital Common Surplus, Retained Stock Paid In Earnings Total --------------------------------------------------------------------------------------- (Thousands of Dollars) Balance at January 1, 1992............... $37,494 $646,298 $ 632 $684,424 Net income........................... 12,778 12,778 Cash dividends on preferred stock.... (5,704) (5,704) Stock dividends on common stock...... 1,962 16,456 (18,418) - Capital stock expenses, net.......... (2) (2) -------- --------- --------- --------- Balance at June 4, 1992.................. $39,456 $662,752 $(10,712) $691,496 ======== ========= ========= ========= Balance at June 5, 1992.................. $ - $ - $ - $ - Net income........................... 29,398 29,398 Cash dividends on preferred stock.... (7,545) (7,545) Issuance of 1,000 shares of common stock, $1 par value................ 1 1 Premium on common stock.............. 424,999 424,999 Capital stock expenses, net.......... (4,237) (4,237) -------- --------- --------- --------- Balance at December 31, 1992............. 1 420,762 21,853 442,616 Net income........................... 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........................... 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 ======== ========= ========= =========
PSNH became a wholly owned subsidiary of Northeast Utilities on June 5, 1992. 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. MERGER WITH NORTHEAST UTILITIES On June 5, 1992 (Acquisition Date), Northeast Utilities (NU) acquired Public Service Company of New Hampshire (PSNH) pursuant to a merger agreement and the company became a wholly owned operating subsidiary of NU. In a related transaction, PSNH's 35.6 percent share of the Seabrook 1 nuclear power plant (Seabrook 1) and other Seabrook-related assets were transferred to North Atlantic Energy Corporation (NAEC), another new NU subsidiary. In accordance with generally accepted accounting principles, the acquisition of PSNH has been accounted for as a purchase. On June 29, 1992, PSNH's New Hampshire Yankee Division (NHY) was dissolved and North Atlantic Energy Service Corporation (NAESCO), a wholly owned subsidiary of NU, with the approval of the Securities and Exchange Commission (SEC) and the Nuclear Regulatory Commission (NRC), began management of the Seabrook 1 power plant as agent for the Seabrook joint owners. On June 29, 1992, all NHY employees became employees of NAESCO. B. GENERAL PSNH, The Connecticut Light and Power Company, Western Massachusetts Electric Company, NAEC, and Holyoke Water Power Company are the operating subsidiaries comprising the Northeast Utilities system (the system) and are wholly owned by NU. 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 acts as agent for system companies in constructing and 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. C. RECLASSIFICATIONS Certain reclassifications of prior years' data have been made to conform with the current year's presentation. D. 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, based on PSNH's ability to exercise significant influence over their operating and financial policies. The electricity produced by the facilities that are operating is committed to the participants substantially on the basis of their 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 more or of the companies. For more information on these agreements, see Note 10E, "Commitments and Contingencies - Purchased Power Arrangements." The YAEC 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: The company has a 2.85 percent joint ownership interest in Millstone 3, a 1,154-megawatt (MW) nuclear generating unit. As of December 31, 1994 and 1993, plant-in-service included approximately $118.3 million and $118.1 million, respectively, and the accumulated provision for depreciation included approximately $24.2 million and $21.1 million, respectively, for PSNH's proportionate 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, 1994 and 1993, plant-in-service included approximately $6.0 million and the accumulated provision for depreciation included approximately $3.3 million and $3.1 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. E. 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. For Millstone 3, the costs of removal, less salvage, that have been funded through an external decommissioning trust will be paid with funds from the trust and charged to the accumulated reserve for decommissioning included in the accumulated provision for depreciation over the expected service life of the plant. See Note 4, "Nuclear Decommissioning," for additional information. The depreciation rates for the several classes of electric plant-in-service are equivalent to a composite rate of 3.6 percent for the years ended December 31, 1994, and December 31, 1993, 3.5 percent for the six-month and twenty-six day period ending December 31, 1992, and 3.4 percent for the five-month and four-day period ending June 4, 1992. F. 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 PSNH, 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 the NHPUC. G. REVENUES Other than 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. 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. For additional information see Note 10B, "Commitments and Contingencies - PSNH Rate Agreement." H. REGULATORY ACCOUNTING PSNH follows accounting policies that reflect the impact of the rate treatment of certain events or transactions that differ from generally accepted accounting principles for those events or transactions followed by nonregulated enterprises. Under regulatory accounting, assuming that future revenues are expected to be sufficient to provide recovery, regulators may permit incurred costs, normally treated as expenses, to be deferred and recovered in revenues at a later date. Regulatory accounting is unique in that the actions of a regulator can provide reasonable assurance of the existence of an asset. Regulators, through their actions, may also reduce or eliminate the value of an asset, or create a liability. If the economic entity no longer comes under the jurisdiction of a regulator or external forces, such as a move to a competitive environment, effectively limiting the influence of cost-of-service based rate regulation, the entity may be forced to abandon regulatory accounting, requiring a reexamination and potential write-off of net regulatory assets. PSNH continues to be subject to cost-of-service based rate regulation. Based on current regulation, PSNH believes that its use of regulatory accounting is still appropriate. The components of regulatory assets are as follows: At December 31, 1994 1993 -------------------------------------------------------------- (Thousands of Dollars) Regulatory asset (Note 1I) ...........$678,974 $769,498 Recoverable energy costs (Note 1J) ...194,994 122,861 Income taxes, net (Note 1K) .......... 66,466 54,250 Unrecovered contract obligation- YAEC (Note 4) ........................ 28,572 24,150 Other ................................ 2,499 2,594 ------- -------- $971,505 $973,353 ======== ======== I. REGULATORY ASSET The regulatory asset represents the aggregate value, as of the Acquisition Date, placed by the 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 and the $700 million value assigned to Seabrook by the Rate Agreement. The regulatory asset was valued at approximately $920.6 million on the Acquisition Date. The Rate Agreement provides for the recovery, through rates, of the amortization of the regulatory asset with a return each year on the unamortized portion of the asset. The Rate Agreement provides that $425 million of the regulatory asset be amortized over the first seven years after May 16, 1991 (Reorganization Date), with the remaining amount to be amortized over the 20-year period after the Reorganization Date. J. 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 has begun to recover these costs. 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 purchase power costs assumed in the Rate Agreement and PSNH's actual costs, which include the costs under the Seabrook Power Contract. 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 attempting to negotiate the rate orders mandating the purchase of high-cost NUG power. In September 1994, the NHPUC approved an amendment to the Rate Agreement allowing settlement agreements to be implemented with two NUGs. The two NUGs have given up their right to sell their output to PSNH in exchange for lump sum cash payments of 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 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. At December 31, 1994, PSNH's recoverable energy costs included fuel and purchase power deferrals ($154.9 million), the deferred buyout ($39.8 million), and the D&D assessment ($0.3 million). See Note 10B, "Commitments and Contingencies - PSNH Rate Agreement," for further information. K. 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. See Note 8, "Income Tax Expense," for the components of income tax expense. In 1992, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes (SFAS 109). SFAS 109 supersedes previously issued income tax accounting standards. PSNH adopted SFAS 109, on a prospective basis, during the first quarter of 1993. The adoption of SFAS 109 has not had a material effect on the net income or on the balance sheet of the company. As a result of the adoption of SFAS 109, the company has increased the deferred tax asset for net-operating-losses (NOLs) previously not recognized. A valuation reserve was not established. As it is probable that the increase in deferred tax liabilities will be recovered from customers through rates, PSNH also established a regulatory asset. The tax effect of temporary differences which give rise to the accumulated deferred tax obligation are as follows: At December 31, 1994 1993 ------------------------------------------------------------ (Thousands of Dollars) Accelerated depreciation and other plant-related differences .......... $ 106,683 $ 150,238 Net operating loss carryforwards ..... (247,440) (270,612) Regulatory liabilities - income tax gross up (46,445) (49,423) Other ................................ 249,282 187,873 -------- -------- $ 62,080 $ 18,076 ========= ========= At December 31, 1994, PSNH had a regular tax NOL carryforward of approximately $726 million, and an Alternative Minimum Tax (AMT) NOL carryforward of $529 million, both to be used against PSNH's federal taxable income and expiring between the years 2000 and 2006. PSNH also had Investment Tax Credit (ITC) carryforwards of $54 million, which expire between the years 1995 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 $249 million of the NOL, $189 million of the AMT NOL, and $23 million of the ITC carryforwards are subject to this limitation. L. DERIVATIVE FINANCIAL INSTRUMENTS PSNH utilizes interest-rate caps to manage well defined interest rate 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 - Other. Amounts receivable under cap agreements are accrued as a reduction of interest expense. Any material unrealized gains or losses on interest rate caps will be deferred until realized. For further information, see Note 11, "Derivative Financial Instruments." 2. SEABROOK POWER CONTRACT On June 5, 1992, NAEC and PSNH entered into the Seabrook Power Contract (Contract), under which PSNH is obligated to buy from NAEC, and NAEC is obligated to sell to PSNH, all of NAEC's 35.6 percent ownership share of the capacity and output of Seabrook 1 for a period equal to the length of the NRC's full power operating license for Seabrook 1. Accordingly, 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, 1994, this right was valued at approximately $882.8 million. Under the Contract, PSNH is unconditionally obligated to pay NAEC's cost of service during this period whether or not Seabrook 1 is operating. NAEC's cost of service includes all of its Seabrook-related costs, including operation and maintenance expense, fuel expense, property tax expense, depreciation expense, and certain overhead and other costs. The Contract establishes the value of the initial investment in Seabrook (Initial Investment) at $700 million and the initial investment in nuclear fuel at $0. NAEC is depreciating its Initial Investment on a straight line basis over the remaining term of Seabrook's full power operating license. Any subsequent additions to Seabrook 1 will be depreciated on a straight- line basis over the remaining term of the Contract at the time the additions are brought into service. The Contract provides that NAEC's return on its allowed investment in Seabrook 1 (its investment in working capital, fuel, capital additions after the date of commercial operation of Seabrook 1 and a portion of the Initial Investment) is calculated based on NAEC's actual capitalization from time to time over the term of the Contract, which includes its actual debt and preferred equity costs, and a common equity cost of 12.53 percent for the first ten years of the Contract, 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 was 40 percent at the Acquisition Date, and will increase by 15 percent in each of the following four years beginning May 15, 1993. As of December 31, 1994, the portion of the initial investment included in the allowed investment was 70 percent. From the Acquisition Date through December 31, 1994, NAEC recorded an additional $131.5 million of deferred return. The deferred return on the excluded portion of the Initial Investment, including the $50.9 million, will be recovered with carrying charges by NAEC through the Contract beginning six months after the end of PSNH's Fixed Rate Period and will be fully recovered by May 15, 2001. If Seabrook 1 is shut down prior to the expiration of the NRC operating license term, PSNH will be unconditionally required to pay NAEC termination costs for 39 years, less the period during which Seabrook 1 has operated. These costs are designed to reimburse NAEC for its share of Seabrook 1 shut-down and decommissioning costs and to pay NAEC a return of and on any undepreciated balance of its Initial Investment in the plant over the then- remaining term of the Contract, 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 such cancellation). Contract payments charged to operating expense were $143 million, including an interest component of $43 million for the year ended December 31, 1994; $123 million, including an interest component of $33 million for the year ended December 31, 1993; and $26.5 million, including $16.3 million for the period June 5, 1992 through December 31, 1992. On February 15, 1994, NAEC acquired Vermont Electric Generation and Transmission Cooperative, Inc.'s (VEG&T) 0.4 percent ownership interest in Seabrook for approximately $6.4 million. NAEC sells the output from the Seabrook interest purchased from VEG&T on February 15, 1994 to PSNH under an agreement that has been approved by the FERC and is substantially similar to the Seabrook Power Contract between PSNH and NAEC that was effective on the Acquisition Date. 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, 1994, are approximately: Seabrook Power Contracts ------------------------ (Thousands of Dollars) 1995 ................................ $ 72,300 1996 ................................ 81,200 1997 ................................ 91,100 1998 ................................ 169,700 1999 ................................ 167,900 After 1999 .......................... 1,341,900 ---------- Future minimum payments ............. 1,924,100 Less amount representing interest .. 1,041,300 ---------- Present value of Seabrook Power Contracts payments ............... $ 882,800 ========== 3. LEASES PSNH has entered into lease agreements, 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 ---- -------------- ---------------- 1994 ................ $1,061,000 $4,255,000 1993 ................ 701,000 6,197,000 1992 ................ - 8,511,000 Interest included in capital leases was $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 noncancelable leases, as of December 31, 1994, are approximately: Operating Leases ---------------- (Thousands of Dollars) 1995 ............................... $ 7,900 1996 ............................... 6,900 1997 ............................... 5,800 1998 ............................... 4,500 1999 ............................... 4,000 After 1999 ......................... 14,100 -------- Future minimum lease payments $43,200 ======= 4. NUCLEAR DECOMMISSIONING 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 Millstone 3. A 1994 Seabrook decommissioning study, which is currently under review by the New Hampshire Decommissioning Financing Committee, 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, technology, and inflation. The estimated cost of decommissioning PSNH's 2.85 percent ownership share of Millstone 3 and NAEC's 36.0 percent share of Seabrook 1 (utilizing the currently approved decommissioning study), in year-end 1994 dollars, is $12.8 million and $137.3 million, respectively. These estimated costs have been levelized and assume after-tax earnings on the Millstone and Seabrook decommissioning funds of 6.5 percent and 6.1 percent, respectively. Future escalation rates in decommissioning costs for Millstone 3 and Seabrook 1 are assumed. 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 1994 and 1993, and $0.2 million in 1992. Nuclear decommissioning costs, as a cost of removal, are included in the accumulated provision for depreciation on PSNH's Balance Sheets. At December 31, 1994, the balance in the accumulated reserve for decommissioning amounted to $1.8 million. See "Nuclear Decommissioning" in Management's Discussion and Analysis for a discussion of changes being considered by the FASB related to accounting for decommissioning costs. 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'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. PSNH records its Seabrook decommissioning costs as a component of purchased power expense on its Statement of Income. Under the Rate Agreement, PSNH's Seabrook decommissioning costs are recovered through base rates. As of December 31, 1994, PSNH has collected, through rates, approximately $1.5 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 trusts increase the decommissioning trusts balance and the accumulated reserve for decommissioning. Due to PSNH's adoption, effective January 1, 1994, of SFAS 115, Accounting for Certain Investments in Debt and Equity Securities, unrealized gains and losses associated with the decommissioning trusts also impact the balance of the trusts and the accumulated reserve for decommissioning. As of December 31, 1994, NAEC (including pre-Acquisition Date payments made by PSNH) has paid approximately $10.1 million, into Seabrook 1's decommissioning trust. 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. 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. Because allowances for decommissioning have increased significantly in recent years, ratepayers in future years may need to increase their payments to offset the effects of any insufficient rate recoveries in previous years. PSNH, along with other New England utilities, has equity investments in the four Yankee companies. Each Yankee company owns a single nuclear generating unit. PSNH's ownership share of the estimated costs, in year- end 1994 dollars, of decommissioning of CY, MY, and VY are $18.1 million, $16.9 million, and $13.2 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 by PSNH. YAEC has begun component removal activities related to decommissioning of its nuclear facility. In June 1992, YAEC filed a rate filing to obtain FERC authorization to collect the closing and decommissioning costs and to recover the remaining investment in the YAEC nuclear power plant over the remaining period of the plant's Nuclear Regulatory Commission (NRC) operating license. The bulk of these costs has been agreed to by the YAEC joint owners and approved, as a settlement, by FERC. In October 1994, YAEC submitted a revised decommissioning cost estimate as part of its decommissioning plan with the NRC. Following the receipt of NRC approval, this estimate will be filed with the FERC. This revised estimate increased PSNH's ownership share of decommissioning YAEC's nuclear facility by approximately $6.6 million in January 1, 1994 dollars. At December 31, 1994, the estimated remaining costs, including decommissioning, amounted to $408.2 million, of which PSNH's share was approximately $28.6 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 a corresponding obligation, on its Balance Sheets. 5. SHORT-TERM DEBT PSNH has credit lines totaling $125 million available through a Revolving- Credit Facility 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, 1994 and 1993, there were no borrowings under the Facility. 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. 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. Investing and borrowing subsidiaries receive or pay interest based on the average daily Federal Funds rate. At December 31, 1994, there were no outstanding borrowings from the Pool. At December 31, 1993, PSNH had $2.5 million in outstanding borrowings the Pool, for which the average interest rate was 2.9 percent. 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. 6. PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION Details of preferred stock subject to mandatory redemption are: Shares Outstanding December 31, -------------------------- Description December 31, 1994 1994 1993 1992 ----------------------------------------------------------------- (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 a sinking fund 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, ------------------- 1994 1993 ---------------------------------------------------------------- (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 141,000 235,000 Pollution Control Revenue Bonds: 7.65% Series A ........due 2021 66,000 66,000 7.50% Series B ........due 2021 108,985 108,985 7.65% Series C ........due 2021 112,500 112,500 Adjustable Rate Series D due 2021 39,500 39,500 Adjustable Rate 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 ... 94,000 94,000 -------- -------- Long-term debt, net ............ $905,985 $999,985 ======== ======== Long-term debt maturities and cash sinking-fund requirements on debt outstanding at December 31, 1994 for the years 1995 through 1999 are approximately $94,000,000 in 1995, $219,500,000 in 1996, $0 in 1997, $170,000,000 in 1998, and $0 in 1999. 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 its 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 two bank facilities, the Term Loan and Revolving Credit Facility are 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, 1994, and the principal amount outstanding under the Term Loan was $141 million and $235 million, respectively. The average effective interest rates for the Term Loan for 1994 and 1993 were approximately 5.2 percent and 4.3, respectively. At December 31, 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 issued five series of Pollution Control Revenue Bonds (PCRBs) and loaned the proceeds to PSNH. At December 31, 1994 and 1993, $516.5 million of the PCRBs were outstanding. The average effective interest rates on the variable-rate pollution percent control notes ranged from 2.90 to 4.3 percent for 1994 and from 2.5 percent to 3.4 percent for 1993. 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 obligation 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: Jan. 1, 1993 Jan. 1, 1994 to June 5, 1992 Jan. 1, 1992 to Dec. 31, 1993 to to For the Periods Dec.31, 1994 (Note 1K) Dec. 31. 1992 June 4, 1992 ----------------------------------------------------------------------------- (Thousands of Dollars) Current income taxes: Federal .............. $ 368 $ (937) $ 2,400 | $ 415 State ................ 1,219 1,183 - | 79 --------- -------- -------- | --------- Total current 1,587 246 2,400 | 494 --------- -------- -------- | --------- | Deferred income taxes, net: | Federal 63,941 47,407 23,086 | 8,703 State 3,666 3,131 - | - --------- -------- -------- | --------- | Total deferred 67,607 50,538 23,086 | 8,703 --------- -------- -------- | --------- | | Investment tax credits, net (560) (565) (326) | (341) -------- --------- -------- | --------- | Total income tax expense $ 68,634 $ 50,219 $ 25,160 | $ 8,856 ======== ======== ======== ======== The components of total income tax expense are classified as follows: Income taxes charged to operating expenses... $68,088 $54,087 $39,197 | $16,449 Income taxes associated | with the deferred | return on Seabrook.. - - - | 4,793 Income taxes associated | with allowance for funds | used during construction | and the deferred return | on NHEC deferred costs - - 217 | 428 Other income taxes - credit 546 (3,868) (14,254) | (12,814) -------- -------- ------- | ------- | Total income tax expense. $ 68,634 $ 50,219 $25,160 | $ 8,856 ======== ======== ======= ======= Deferred income taxes are comprised of the tax effects of temporary differences as follows: Jan. 1, 1993 Jan. 1, 1994 to June 5, 1992 Jan. 1, 1992 to Dec. 31, 1993 to to For the Periods Dec. 31, 1994 (Note 1K) Dec. 31, 1992 June 4, 1992 ------------------------------------------------------------------------------- (Thousands of Dollars) Depreciation $ 2,701 $ 4,549 $ 1,629 | $12,333 Energy adjustment clauses 30,954 15,155 14,520 | (1,359) Deferred tax asset | associated with NOL 23,611 25,438 9,335 | (2,317) Alternative minimum tax (301) 1,056 (2,441) | (394) Amortization of prepaid | deferred taxes 11,501 7,667 - | - Deferred return on Seabrook - - - | 4,793 Severance benefits - - 254 | (1,020) Other (859) (3,327) (211) | (3,333) --------- -------- ------- | -------- | | Deferred income taxes, net $67,607 $50,538 $23,086 | $ 8,703 ======= ======= ======= ======== A reconciliation between income tax expense and the expected tax expense at the applicable statutory rates is as follows: Jan. 1, 1993 Jan. 1, 1994 to June 5, 1992 Jan. 1, 1992 to Dec.31, 1993 to to For the Periods Dec. 31,1994 (Note 1K) Dec. 31, 1992 June 4, 1992 ---------------------------------------------------------------------------- (Thousands of Dollars) Expected federal income tax at 35 percent of pretax income for 1994 and 1993 and at 34 percent for 1992 $51,127 $35,860 $18,550 |$ 7,356 Tax effect of differences: | Depreciation differences 1,407 1,593 1,032 | (8,314) Amortization of regulatory | asset - Rate Agreement 20,007 23,765 17,624 | 12,477 Seabrook intercompany loss (19,637) (19,176) (11,903) | - Reorganization expenses - - 22 | 1,728 Deferred investment return - - - | (3,832) State income taxes, net of | federal benefit 3,175 2,804 - | - Amortization of prepaid deferred | taxes 11,501 7,667 - | - Other, net 1,054 (2,294) (165) | (559) -------- ------ --------- | ------- | Total income tax expense $68,634 $50,219 $25,160 |$ 8,856 ======= ======= ======= ======= 9. EMPLOYMENT BENEFITS <9A>A. PENSION BENEFITS The company participates in a uniform noncontributory defined benefit retirement plan covering all regular system employees (the Plan). Benefits are based on years of service and employees' highest eligible compensation during five consecutive years of employment. Effective January 1993, PSNH's plan was merged into the NU system's uniform noncontributory defined benefit plan. The company's direct portion of the system's pension cost, part of which was charged to utility plant, approximated $4.4 million in 1994, $6.6 million 1993, and $4.4 million for the period January 1, 1992 to June 4, 1992 and $3.5 million for the period June 5, 1992 to December 31, 1992. The pension cost for January 1, 1992 to June 4, 1992 includes employees of NHY, who are now employees of NAESCO. Pension costs for 1994 and 1993 included approximately $1.9 million and $3.4 million, respectively, related to work force 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: Jan. 1, 1994 Jan. 1, 1993 June 5, 1992 Jan. 1, 1992 to to to to For the Periods Dec. 31, 1994 Dec. 31, 1993 Dec. 31, 1992 June 4, 1992 ---------------------------------------------------------------------- (Thousands of Dollars) Service cost $ 5,531 $ 7,539 $ 2,889 | $ 3,850 Interest cost 11,129 11,180 6,810 | 6,200 Return on plan assets 246 (19,308) (5,026) | (4,561) Net amortization (12,526) 7,215 (1,206) | (1,067) ------- -------- ------ | -------- | Net pension cost $ 4,380 $ 6,626 $ 3,467 | $ 4,422 ======== ======== ======= ======== -------------------------------------------------------------------- For calculating pension cost, the following assumptions were used: Jan. 1, 1994 Jan. 1, 1993 June 5, 1992 Jan. 1, 1992 to to to to For the Periods Dec. 31, 1994 Dec. 31, 1993 Dec. 31, 1992 June 4, 1992 ------------------------------------------------------------------------------- Discount rate ............ 7.75% 8.00% 8.00% | 8.00% Expected long-term rate . | of return ............... 8.50 8.50 9.00 | 9.00 Compensation/progression . | rate .................. 4.75 5.00 6.00 | 6.00 The following table represents the Plan's funded status reconciled to the Balance Sheets: At December 31, 1994 1993 ------------------------------------------------------------------- (Thousands of Dollars) Accumulated benefit obligation, including $111,198,000 of vested benefits at December 31, 1994 $111,691,000 of vested benefits at December 31, 1993 $121,202 $122,429 ======== ======== Projected benefit obligation (PBO) $146,972 $156,475 Market value of plan assets 136,104 145,536 -------- -------- PBO in excess of plan assets (10,868) (10,939) Unrecognized transition amount 5,004 5,338 Unrecognized prior service costs 5,775 4,890 Unrecognized net gain ...... (36,180) (31,179) -------- -------- Accrued pension liability .. $(36,269) $ (31,890) ========= ========== The following actuarial assumptions were used in calculating the Plan's year-end funded status: For the Years Ended December 31, 1994 1993 ------------------------------------------------------------ Discount rate...................... 8.25% 7.75% Compensation/progression rate 5.00 4.75 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. These benefits are available for employees leaving the company who are otherwise eligible to retire and have met specified service requirements. Effective January 1, 1993, the company adopted SFAS 106, Employer's Accounting for Postretirement Benefits Other Than Pensions, on a prospective basis. PSNH's direct portion of health care and life insurance costs, part of which were deferred or charged to utility plant, approximated $7.6 million in 1994, $9.1 million in 1993, and $3.3 million in 1992. On January 1, 1993, the accumulated postretirement benefit obligation represented the company's transition obligation upon the adoption of SFAS 106. As allowed by SFAS 106, the company is amortizing its transition obligation of approximately $59 million over a 20-year period. 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. During 1993, the company began funding SFAS 106 postretirement costs through external trusts. The company is funding annually 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 following table represents the plan's funded status reconciled to the Balance Sheet. At December 31, 1994 1993 ------------------------------------------------------------------ (Thousands of Dollars) Accumulated postretirement benefit obligation of: Retirees ...................... $39,881 $51,832 Fully eligible active employees 52 99 Active employees not eligible to retire 9,065 7,888 --------- ------- Total accumulated postretirement benefit obligation .................... 48,998 59,819 Market value of plan assets ...... 6,606 2,387 --------- -------- Accumulated postretirement benefit obligation in excess of plan assets (42,392) (57,432) Unrecognized transition amount ... 52,930 55,870 Unrecognized net gain ............ (13,204) (1,065) -------- -------- Accrued postretirement benefit liability $ (2,666) $ (2,627) ======== ======== ------------------------------------------------------------- The components of health care and life insurance costs are: For the Years Ended December 31, 1994 1993 ------------------------------------------------------------ (Thousands of Dollars) Service cost ..................... $ 971 $1,260 Interest cost .................... 3,844 4,800 Return on plan assets ............ 37 - Net amortization ................. 2,735 3,046 ------ ------ Net health care and life insurance costs $7,587 $9,106 ====== ====== ------------------------------------------------------------- The following actuarial assumptions were used in calculating the Plan's year-end funded status: At December 31, 1994 1993 ------------------------------------------------------------ (Thousands of Dollars) Discount rate .................... 8.00% 7.75% Long-term rate of return - health assets,net of tax ........ 5.00 5.00 Long-term rate of return - life assets 8.50 8.50 Health care cost trend rate (a) .. 10.20 11.10 (a) Annual growth in per capita cost of covered health care benefits was assumed to decrease to 5.4 percent for 2002. 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, 1994 by $2.4 million and the aggregate of the service and interest cost components of net periodic postretirement benefit cost for the year then ended by $233,000. 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 previously deferred costs. Deferral of such costs are permitted since it is expected that the period of recovery of deferred costs will be within the time frame established by the applicable accounting requirements. 10. COMMITMENTS AND CONTINGENCIES A.CONSTRUCTION PROGRAM The construction program is subject to periodic review and revision. Actual construction expenditures may vary from estimates due to factors such as revised load estimates, inflation, revised nuclear safety regulations, delays, difficulties in the licensing process, the availability and cost of capital, and the granting of timely and adequate rate relief by regulatory commissions, as well as actions by other regulatory bodies. PSNH currently forecasts construction expenditures (including AFUDC) of $195.5 million for the years 1995-1999, including $50.7 million for 1995. In addition, PSNH estimates that nuclear fuel requirements, for its share of Millstone 3, will be $4.2 million for the years 1995-1999, including $790,000 for 1995. B.PSNH RATE AGREEMENT The Rate Agreement provided the financial basis for PSNH's Plan of Reorganization (the Plan). The Rate Agreement calls for seven successive 5.5 percent annual increases in PSNH's base rates for its charges to retail customers (the Fixed-Rate Period). The first increase was put into effect on January 1, 1990 and the remaining two increases are scheduled to be put into effect annually beginning on June 1, 1995. As discussed in Note 1J, "Recoverable Energy Costs," the FPPAC protects PSNH from changes in fuel and purchased power costs. Although the Rate Agreement provides an unusually high degree of certainty as to PSNH's future retail rates, it also entails a risk when sales are lower than anticipated or if PSNH should experience unexpected increases in its costs other than those for fuel and purchased power, since PSNH has agreed that it will not seek additional rate relief during the Fixed-Rate Period, except in limited circumstances. However, in order to provide protection from significant variations from the costs assumed in base rates over the Fixed-Rate Period, the Rate Agreement establishes a return on equity (ROE) collar to prevent PSNH from earning a ROE in excess of an upper limit or below a lower limit. To date, PSNH's ROE has been within the limits of the ROE collar. 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. Changing environmental requirements could hinder the construction of new generating units, transmission and distribution lines, substations, and other facilities. The cumulative long-term, economic 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 is, based upon information currently available, its estimated environmental remediation costs for waste disposal sites for which it expects to bear legal liability. In most cases, the extent of additional future environmental cleanup costs is 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 methods, and the possible effects of technological changes. At December 31, 1994, the liability recorded by PSNH for its estimated environmental remediation costs, excluding any possible insurance recoveries or recoveries from third parties, amounted to approximately $2 million. PSNH cannot estimate the potential liability for future claims 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 The Price-Anderson Act currently limits public liability from a single incident at a nuclear power plant to $8.9 billion. The first $200 million of liability would be provided by purchasing the maximum amount of commercially available insurance. Additional coverage of up to a total of $8.3 billion would be provided by an assessment of $75.5 million per incident, levied on each of the 110 nuclear units that are currently subject to the Secondary Financial Protection Program in the United States, subject to a maximum assessment of $10 million per incident per nuclear unit in any year. In addition, if the sum of all public liability claims and legal costs arising from any nuclear incident exceeds the maximum amount of financial protection, each reactor operator can be assessed an additional 5 percent, up to $3.8 million, or $415.3 million in total, for all 110 nuclear units. The maximum assessment is to be adjusted at least every five years to reflect inflationary changes. Under the terms of the Contract with NAEC, PSNH would be obligated to pay for any assessment charged to NAEC as a "cost of service." At December 31, 1994, based on PSNH's ownership interests in Millstone 3, and NAEC's ownership interests in Seabrook 1, PSNH's maximum liability would be $30.7 million per incident. In addition, through PSNH's purchased power contracts with the three operating Yankee regional nuclear generating companies, PSNH would be responsible for up to an additional $11.1 million per incident. The payments for PSNH's ownership interest in nuclear generating facilities and costs resulting from the Contract with NAEC would be limited to a maximum of $5.3 million per incident per year. Effective January 1, 1995, insurance was purchased from Nuclear Mutual Limited (NML) to cover the primary cost of repair, replacement, or decontamination of utility property resulting from insured occurrences with respect to PSNH's ownership interest in Millstone 3 and CY. All companies insured with NML are subject to retroactive assessments if losses exceed the accumulated funds available to NML. The maximum potential assessment against PSNH with respect to losses arising during the current policy year is approximately $0.5 million under the NML primary property insurance program. Insurance has been purchased from Nuclear Electric Insurance Limited (NEIL) to cover (1) certain extra costs incurred in obtaining replacement power during prolonged accidental outages with respect to PSNH's Contract with NAEC; and (2) the excess cost of repair, replacement, or decontamination or premature decommissioning of utility property resulting from insured occurrences with respect to PSNH's ownership interests in Millstone 3, CY, MY, and VY; and NAEC's ownership interest in Seabrook. All companies insured with NEIL are subject to retroactive assessments if losses exceed the accumulated funds available to NEIL. The maximum potential assessments against PSNH (including costs resulting from PSNH's Contract with NAEC) with respect to losses arising during current policy years are approximately $1.5 million under the replacement power policies and $11.3 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 from American Nuclear Insurers/Mutual Atomic Energy Liability Underwriters, aggregating $200 million on an industry basis for coverage of worker claims. All reactor operators insured under this coverage are subject to retrospective assessments of $3.1 million per reactor. The maximum potential assessments against PSNH (including costs resulting from PSNH's Contract with NAEC) with respect to losses arising during the current policy period are approximately $1.9 million. E.PURCHASED POWER ARRANGEMENTS PSNH, along with CL&P and WMECO, purchase approximately 10 percent of their electricity requirements pursuant to long-term contracts with the Yankee companies. Under the terms of its agreements, the company pays its ownership share (or entitlement share) of generating costs, which includes depreciation, taxes, operation and maintenance expenses, the estimated cost of decommissioning, and a return on invested capital. These costs are recorded as purchased power expense and recovered through the company's rates. PSNH's total cost of purchases under these contracts for the units that are operating amounted to $23.4 million in 1994, $26.5 million in 1993 and $24.8 million in 1992. See Note 1D, "Summary Of Significant Accounting Policies-Investments and Jointly Owned Electric Utility Plant" and Note 4, "Nuclear Decommissioning" for more information on the Yankee companies. PSNH has entered into multiple purchases of capacity and energy from nonutility generators pursuant to rate orders. These arrangements have terms from 20 to 30 years, and require the company to purchase the energy at specified prices or formula rates. For the 12 months ended December 31, 1994, approximately 14 percent of NU system electricity requirements was met by nonutility generators. The total cost to the company of purchases under these arrangements amounted to $130 million in 1994, $133.4 million in 1993, and $92.1 million in 1992. These costs are eventually recovered through the company's rates. See Note 1J, "Summary of Significant Accounting Policies - Recoverable Energy Costs" for further information. In an effort to control costs from nonutility generators and as required by the rate agreement, PSNH has been negotiating with 13 nonutility generators. As of February 1995, eight of those negotiations were complete. This includes five hydroelectric facilities that were renegotiated to convert their rate orders to long- term contracts and three wood-burning facilities had either their rate orders bought out or entered into a new contract. Mediation efforts continue with the five wood burners that have not been settled. PSNH entered into a buy-back agreement to purchase the capacity and energy of the New Hampshire Electric Cooperative, Inc.'s (NHEC) Seabrook entitlement and to pay all of NHEC's Seabrook costs for a ten- year period which began July 1, 1990. The total cost of purchases under this agreement was $15.7 million in 1994, $14.4 million in 1993, and $13.8 million in 1992. Part of these costs is collected currently through the FPPAC and part is deferred for future collection in accordance with the Rate Agreement. In connection with the agreement, NHEC agreed to continue as a firm-requirements customer of PSNH for 15 years. The estimated annual cost of PSNH's significant purchased power arrangements are as follows: 1995 1996 1997 1998 1999 ------------------------------------------------------------- (Millions of Dollars) Yankee companies ......$ 27.3 $ 28.5$ 25.5 $ 30.5 $ 30.1 Nonutility generators . 116.3 121.6 123.9 126.0 128.1 NHEC .................. 16.5 16.5 25.1 33.2 32.8 F.HYDRO-QUEBEC Along with other New England utilities, PSNH 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, its proportionate share of the annual operation, maintenance, and capital costs of these facilities, which are currently forecast to be $53.7 million for the years 1995-1999, including $12.0 million for 1995. G.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 Contract. 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 1994, there were three outstanding contracts held by PSNH, covering $225 million of its variable rate debt, with terms ranging from one to three years. The contact entitles 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. These contracts are settled on a quarterly basis. As of December 31, 1994, PSNH had a total of $75 million in caps outstanding, with a positive mark-to-market position of approximately $0.8 million. PSNH is exposed to credit risk on the interest-rate caps if the counterparties fail to perform their obligations. However, PSNH 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 and nuclear decommissioning trusts: The carrying amounts approximate fair value. SFAS 115 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. 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: At December 31, 1994 Carrying Amount Fair 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 ----------------------------------------------------------------- At December 31, 1993 Carrying Amount Fair Value ----------------------------------------------------------------- (Thousands of Dollars) Preferred stock subject to mandatory redemption ........................$125,000 $139,375 Long-term debt - First Mortgage Bonds .............. 342,500 359,878 Other long-term debt .............. 751,485 783,389 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. 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, 1994 and 1993, and the related statements of income, common equity and cash flows for the years ended December 31, 1994 and 1993 and the periods from January 1, 1992 to June 4, 1992 and June 5, 1992 to December 31, 1992. 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, 1994 and 1993, and the results of its operations and its cash flows for the years ended December 31, 1994 and 1993 and the periods from January 1, 1992 to June 4, 1992 and June 5, 1992 to December 31, 1992, in conformity with generally accepted accounting principles. As explained in Note 9B to the financial statements, effective January 1, 1993, Public Service Company of New Hampshire changed its methods of accounting for postretirement benefits other than pensions. /s/ Arthur Andersen LLP ARTHUR ANDERSEN LLP Hartford, Connecticut February 17, 1995 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 increased to approximately $77 million in 1994 from approximately $52 million in 1993. The increase from 1993 is a result of increased revenues from retail rate increases, higher retail kilowatt-hour sales, and higher income from the amortization of the company's regulatory liability. In 1994, PSNH's retail kilowatt-hour sales rose by 2.0 percent over 1993, due in large part to the beginning of an economic recovery in New England. Employment levels have risen, unemployment rates have fallen, and personal income has increased in New Hampshire. Retail sales were also affected by colder winter weather in early 1994. In 1995, PSNH expects little retail sales growth over 1994, primarily because of the effects of higher interest rates on the economy and a return to normal weather. Over the longer term, retail kilowatt-hour sales growth is expected to be strong in New Hampshire, which by some measures has the fastest growing economy in New England. In 1994, many businesses announced plans to expand in New Hampshire. The company estimates that it will have compounded annual sales growth of 1.9 percent from 1994 through 1999. Competitive forces within the electric utility industry are continuing to increase due to a variety of influences, including legislative and regulatory actions, technological advances, and changes in consumer demand. PSNH has developed, and is continuing to develop, a number of initiatives to retain and continue to serve its existing customers and to expand its retail customer base. The company believes the steps it is taking, including a companywide process reengineering effort, will have significant, positive effects, including reduced operating costs and improved customer service, in the next few years. The company also benefits from a diverse retail base with no significant dependence on any one retail customer or industry. PSNH continues to operate predominantly in a state-approved franchise territory under traditional cost-of-service regulation. Retail wheeling, under which a retail customer would be permitted to select an electricity supplier and require the local electric utility to transmit the power to the customer's site, is not required in PSNH's service territory. Several bills related to retail wheeling have been introduced in the New Hampshire legislature. To date, none of these bills have been enacted. The chairman of the New Hampshire Public Utilities Commission (NHPUC) has set up a roundtable discussion with legislators, utilities, customers and other interested parties regarding competition in the electric utility industry. In addition, a new entity, Freedom Electric Power Company (FEPCO), has filed with the NHPUC for permission to do business as an electric utility to serve selected large PSNH customers. PSNH and other New Hampshire utilities are opposing FEPCO's petition before the NHPUC. Management cannot assess the impact of any potential legislative or regulatory outcomes on PSNH. While retail competition is not required in the company's retail service territory, competitive forces are nonetheless influencing retail pricing. These forces include competition from alternate fuels such as natural gas, competition from customer-owned generation, and regional competition for business retention and expansion. PSNH's retail business group continues to work with customers to address their concerns. PSNH has reached long-term rate agreements with new and existing customers to gain or retain their business. In general, these rate agreements have terms of about five years. Negotiated retail rate reductions for PSNH customers under rate agreements in effect for 1994 amounted to approximately $3 million. Management believes that the aggregate amount of negotiated retail rate reductions will increase in 1995, but that the related agreements will continue to provide significant benefits to PSNH, including the preservation of approximately 4 percent of retail revenues. The company is also working with its regulators to address the needs of customers more widely. PSNH has a seven-year rate agreement in effect through May 1997. Management will continue to evaluate the use of agreements of this type to keep retail rates competitive. RATE MATTERS PSNH follows accounting principles that allow the rate treatment for certain events or transactions to be reflected. These principles may differ from the accounting principles followed by nonregulated enterprises. Regulators may permit incurred costs, which would normally be treated as expenses by non- regulated enterprises, to be deferred as regulatory assets and recovered in revenues at a later date. Regulatory assets at December 31, 1994 were approximately $972 million. Based on current regulation, the company believes that its use of regulatory accounting is still appropriate. See the "Notes To Financial Statements," Note 1H, for further details on regulatory accounting. In June 1994, PSNH's base rates increased by 5.5 percent under a seven-year 1989 rate agreement approved by the NHPUC. The costs associated with purchases by PSNH from certain nonutility generators (NUGs) over the level assumed in rates are deferred and recovered over ten-year periods through the Fuel and Purchased Power Adjustment Clause (FPPAC). At December 31, 1994, the unrecovered deferrals were approximately $174 million. PSNH is attempting to renegotiate these arrangements with the NUGs. On September 23, 1994, the NHPUC approved settlement agreements with two wood- fired NUGs covering approximately 20 megawatts (MW) of capacity. These two NUGs gave up their rights to sell their output to PSNH in exchange for lump sum cash payments by PSNH totaling approximately $40 million. The buyout payment was added to the deferred balance of NUG costs. The savings resulting from the agreements will be used to reduce the NUG deferred balance over the remaining period of the cancelled arrangements. PSNH is involved in mediations with the owners of the six remaining wood-fired facilities, which account for approximately 87 MW of capacity. PSNH has reached an agreement with one of these six NUGs, which calls for a payment by PSNH of $52 million in return for a substantial reduction in the rates charged to PSNH. The agreement was filed with the NHPUC in February 1995. SEABROOK PERFORMANCE The Seabrook plant operated at 61.6 percent of capacity for the year ended December 31, 1994, compared with 89.8 percent in 1993 and a 1994 national average of 73.2 percent. The lower 1994 capacity factor was primarily the result of an unplanned outage early in the year and an extended refueling and maintenance outage. The unit was taken out of service on January 25, 1994 when an automatic trip from 100 percent power occurred when a main steam isolation valve closed during quarterly surveillance testing. The unit returned to service on February 18, 1994. The unit began its scheduled 57-day refueling and maintenance outage on April 9, 1994. The unexpected discovery of reactor coolant pump locking cups and a bolt in the reactor vessel contributed substantially to the extension of the outage. The unit returned to service on August 1, 1994 for an outage duration of 114 days. The next refueling outage is scheduled for November 1995. ENVIRONMENTAL MATTERS NU devotes substantial resources to identify and then to meet the multitude of environmental requirements it faces. PSNH has active auditing programs addressing a variety of different regulatory requirements, including an environmental auditing program to detect and remedy noncompliance with environmental laws or regulations. The company 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 the company. At December 31, 1994, the liability recorded by the company, amounted to approximately $2 million, which represents the highest cost probable at this time. The company expects that the implementation of the 1990 Clean Air Act Amendments (CAAA) as they relate to sulfur dioxide emissions will require only modest emissions reductions for PSNH. The company is subject to more stringent emission limits for nitrogen oxides (NOX) within the next five years under the CAAA requirements. PSNH will install at Merrimack Station a selective catalytic reduction (SCR) pollution control system by May 1995 to comply with CAAA requirements. The cost of the SCR installation is approximately $22 million, with approximately $10 million of costs incurred as of December 31,1994. Additional capital costs of approximately $5-$7 million are expected to be incurred to comply with NOX emission limits for 1999. NUCLEAR DECOMMISSIONING The company's estimated cost to decommission its share of Millstone 3 and North Atlantic Energy Corporation's (NAEC) share of Seabrook is approximately $13 million and $137 million, respectively, in year-end 1994 dollars. 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. In addition, the company's estimated cost to decommission its shares of the regional nuclear generating units is estimated to be approximately $48 million. These costs are being recognized over the lives of the respective units and a portion of the costs is being recovered through rates. Yankee Atomic Electric Company (YAEC) has begun component removal activities related to the decommissioning of its nuclear facility. PSNH's estimated obligation to YAEC has been recorded on its Balance Sheets. Management expects that the company will continue to be allowed to recover these costs. The staff of the Securities and Exchange Commission has questioned certain of the current accounting practices of the electric utility industry, including this company, regarding the recognition, measurement, and classification of decommissioning costs for nuclear generating stations in the financial statements of electric utilities. The Financial Accounting Standards Board is currently reviewing the accounting for removal costs, including decommissioning and similar costs. If current electric utility industry accounting practices for such decommissioning costs are changed: (1) annual provisions for decommissioning could increase, (2) the estimated costs for decommissioning could be recorded as a liability rather than as accumulated depreciation, and (3) trust fund income from the external decommissioning trust could be reported as investment income rather than as a reduction to decommissioning expense. See the "Notes to Financial Statements," Note 4, for further information on nuclear decommissioning. PROPERTY TAXES PSNH has had a significant court appeal for municipal property tax assessments in the town of Bow, New Hampshire. The central issue in the case is the fair market value of utility property. The company 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, Massachusetts, and some of New Hampshire. However, towns such as Bow advocate a method that approximates reproduction costs. PSNH's appeal of the property tax as assessed against them by Bow has been dismissed by the Supreme Court of New Hampshire. The company estimates that, for assessments in towns such as Bow, the change to the reproduction cost methodology could result in property valuations approximately three times greater than values approximating net book cost. If other towns adopt this methodology, there could be a significant adverse impact on the company's future results of operations and financial condition. However, the extent to which other towns successfully adopt this methodology and any subsequent increase in the company's property tax liability cannot be determined at this time. LIQUIDITY AND CAPITAL RESOURCES Cash provided from operations decreased approximately $8 million in 1994, as compared with 1993, primarily due to higher payments to nonutility generators. Cash used for financing activities was approximately $38 million lower in 1994, as compared with 1993, primarily due to a lower repayment of short-term debt. Cash used for investments was approximately $40 million higher in 1994, as compared with 1993, 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 Term Loan, 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 prevailing interest rates. The company has entered into interest rate cap contracts to reduce a portion of the interest rate risk on certain variable-rate tax-exempt pollution control revenue bonds and the variable-rate term loan. Any premiums paid on these contracts are deferred and amortized over the life of the contracts. The differential paid or received as interest rates change is recognized in income when realized. For further information on Derivatives, see the "Notes to Financial Statements," Note 11, "Derivative Financial Instruments," and Note 12, "Fair Value of Financial Instruments." PSNH is obligated to meet approximately $559 million of long-term debt and preferred stock maturities and cash sinking-fund requirements during the 1995 through 1999 period, including approximately $94 million for 1995. The company's Term Loan must be repaid in 16 quarterly installments of approximately $24 million that commenced in August 1992. PSNH's Series A preferred stock has an annual sinking fund of approximately $25 million beginning in 1997. The company may need to supplement its internal cash generation with outside financing, including additional borrowings if additional agreements are reached with the wood-fired NUGs. PSNH's construction program expenditures, including allowance for funds used during construction (AFUDC), for the period 1995 through 1999 are estimated to be approximately $196 million, including approximately $51 million for 1995. The construction program's main focus is maintaining and upgrading the existing transmission and distribution system, as well as nuclear and fossil-generating facilities. NU does not foresee the need for new major generating facilities, at least until the year 2009. RESULTS OF OPERATIONS PSNH's results of operations for the twelve months ended December 31, 1994 and 1993 and the period June 5, 1992 through December 31, 1992 reflect the results after the acquisition of PSNH by NU on June 5, 1992. The results for the 1993 period compared to the 1992 period are not comparable because of the significant impacts of the acquisition on the company's results. 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) 1994 vs. 1993 1993 vs. 1992 -------------------------------------------------------------------- (Millions of Dollars) Regulatory decisions $20 $24 Fuel, purchased power and FPPAC cost recoveries 32 23 Sales volume 6 7 Other revenues - 1 Sales to other utilities - (49) 1992 Escrowed revenues - (16) ----- ---- Total revenue change $58 ($10) === ==== Operating revenues increased approximately $58 million in 1994 from 1993. Revenues related to regulatory decisions increased primarily because of the effects of the June 1993 and 1994 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 improving economy and colder winter weather. Retail sales increased 2.0 percent in 1994 from 1993 sales levels. Operating revenues decreased approximately $10 million in 1993 from 1992 primarily due to lower short-term power sales to other utilities as a result of the elimination, effective with the acquisition, of sales to NU, and the one- time impact in 1992 of $16 million of revenues released from escrow at the acquisition date. These decreases were partially offset by retail rate increases in June 1992 and 1993 and higher fuel, purchased power, and FPPAC cost recoveries. Retail sales increased 1.4 percent in 1993 from 1992 sales levels. FUEL, PURCHASED AND NET INTERCHANGE POWER Fuel, purchased and net interchange power increased approximately $15 million in 1994, as compared to 1993, primarily due to an increase in purchased power. Fuel, purchased and net interchange power decreased approximately $21 million in 1993, as compared to 1992, primarily due to the timing in the recognition of fuel expenses under the FPPAC. OTHER OPERATION AND MAINTENANCE EXPENSES Other operation and maintenance expenses increased by approximately $10 million in 1994, as compared to 1993, primarily as a result of 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. Other operation and maintenance expenses increased by approximately $14 million in 1993, as compared to 1992, primarily as a result of the payments made by PSNH to NAEC for costs associated with the Seabrook plant under the Seabrook Power Contract, beginning June 5, 1992. See "Notes to Financial Statements," Note 2, for further information on the Seabrook Power Contract. DEPRECIATION Depreciation expense decreased $8 million in 1993 as compared to 1992, as a result of the transfer of the company's investment in Seabrook to NAEC and the inclusion of such costs in the Seabrook Power Contract. AMORTIZATION OF REGULATORY ASSETS, NET Amortization of regulatory assets, net decreased $12 million in 1994, as compared to 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. Amortization of regulatory assets, net decreased $20 million in 1993, as compared to 1992, primarily due to the amortization of the regulatory liability recognized under the global settlement. FEDERAL AND STATE INCOME TAXES Federal and state income taxes increased approximately $18 million in 1994, as compared to 1993, primarily because of higher taxable income. Federal and state income taxes increased approximately $22 million in 1993, as compared to 1992, primarily because of higher taxable income. DEFERRED NUCLEAR PLANTS RETURN The company has not recorded a deferred Seabrook return after June 4, 1992 because the company's investment in Seabrook was transferred to NAEC at the acquisition date. Prior to the transfer of Seabrook to NAEC, a deferred return was calculated on the portion of the Seabrook investment not reflected in rate base. OTHER INCOME, NET Bankruptcy related expenses for the period prior to June 5, 1992, represent costs associated with PSNH's bankruptcy. In 1988, PSNH filed a petition for reorganization under Chapter 11 of the Bankruptcy Code. The gain on generating projects of $6 million for the period prior to June 5, 1992, represents a first quarter 1992 adjustment related to the settlement of a Seabrook contractor dispute and a Seabrook property tax abatement. INTEREST CHARGES Interest on long-term debt and other interest charges are lower for 1993, as compared to 1992, due to the assumption by NAEC, at the acquisition date, of the company's obligations under the 15.23 percent Notes, paydown of the Term Loan and a reduction in borrowings under the revolving credit facility. PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE --------------------------------------------------------------------------- SELECTED FINANCIAL DATA ---------------------------------------------------------------------------
Jan. 1, 1994 Jan. 1, 1993 June 5, 1992* Jan. 1, 1992 May 16, 1991** to to to to to For the Periods Dec. 31, 1994 Dec. 31, 1993 Dec. 31, 1992 June 4, 1992 Dec. 31, 1991 ------------------------------------------------------------------------------------------------------ (Thousands of Dollars) Operating Revenues $922,039 $864,415 $492,559 | $381,769 $539,827 | | | Operating Income... 152,086 124,710 61,206 | 34,250 82,755 | | | Net Income (Loss)... 77,444 52,237 29,398 | 12,778 52,694 | | | At Dec. 31, 1994 Dec. 31, 1993 Dec. 31, 1992 June 4, 1992* Dec. 31, 1991 ------------------------------------------------------------------------------------------------------ (Thousands of Dollars) Total Assets $2,845,967 $2,774,511 $2,793,768 | $2,693,414 $2,636,525 | | | Long-Term Debt (a).. 999,985 1,093,985 1,187,985 | 1,488,985 1,515,985 | | | Liabilities Subject to | | Settlement (a).. - - - | - - | | | Preferred Stock Subject | | to Mandatory Redemption (a) 125,000 125,000 125,000 | 125,000 125,000 | | | Prefered Stock Not Subject | | to Mandatory Redemption - - - | - - | | | Obligations Under Seabrook | | Power Contract and Other | | Capital Leases (a) 887,967 856,559 787,826 | - - | (a)Includes portions due within one year. * PSNH was acquired by NU on June 5, 1992 - See Note 1 of Notes to Financial Statements. **PSNH was reorganized on May 16, 1991.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE SELECTED FINANCIAL DATA
Jan. 1, 1991 Jan. 1, 1990 to to For the Periods May 15, 1991 Dec. 31, 1990 ----------------------------------------------------------------------- (Thousands of Dollars) Operating Revenues $246,281 $660,122 Operating Income... 21,616 63,059 Net Income (Loss)... (100,791) (210,012) At May 15, 1991** Dec. 31, 1990 ----------------------------------------------------------------------- (Thousands of Dollars) Total Assets $2,502,237 $2,490,534 Long-Term Debt (a).... - - Liabilities Subject to Settlement (a)...... 1,901,803 1,864,681 Preferred Stock Subject to Mandatory Redemption (a) - 420,613 Prefered Stock Not Subject to Mandatory Redemption - 48,587 Obligations Under Seabrook Power Contract and Other Capital Leases (a) - - (a)Includes portions due within one year. * PSNH was acquired by NU on June 5, 1992 - See Note 1 of Notes to Financial Statements. **PSNH was reorganized on May 16, 1991. -------------------------------------------------------------------------- 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,) -------------------------------------------------------------------- 1994 $2,058,654 11,008 6,768 400,775 1,374 1993 1,990,730 11,146 6,817 397,277 1,426 1992* 1,894,359 12,294 6,874 394,046 1,680 1991 1,782,894 11,377 7,184 390,793 2,639 1990 2,585,890 8,324 7,015 388,192 2,766 1989 2,555,404 7,656 7,311 383,497 2,786 STATEMENTS OF QUARTERLY FINANCIAL DATA (UNAUDITED) ---------------------------------------------------------------------------- 1994 March 31 June 30 September 30 December 31 ---------------------------------------------------------------------------- (Thousands of Dollars) Operating Revenues $ 249,279 $ 210,875 $ 227,976 $ 233,909 ========= ========= ========= ========= Operating Income $ 43,441 $ 32,388 $ 38,713 $ 37,544 ========= ========= ========= ========= Net Income (Loss) $ 24,278 $ 14,001 $ 19,262 $ 19,903 ========= ========= ========= ========= ---------------------------------------------------------------------------- 1993 March 31 June 30 September 30 December 31 ---------------------------------------------------------------------------- (Thousands of Dollars) Operating Revenues $ 224,705 $ 192,360 $ 222,717 $ 224,633 ========= ========= ========= ========= Operating Income $ 35,077 $ 21,682 $ 24,725 $ 43,226 ========= ========= ========= ========= Net Income (Loss) $ 15,558 $ 2,995 $ 8,583 $ 25,101 ========= ========= ========= ========= * PSNH was acquired by NU on June 5, 1992 - See Note 1A of Notes to Financial Statements.
EX-13.5 20 Exhibit 13.5 1994 ANNUAL REPORT NORTH ATLANTIC ENERGY CORPORATION --------------------------------- 1994 Annual Report North Atlantic Energy Corporation Index Contents Page -------- ---- Balance Sheets..................................... 1-2 Statements of Income............................... 3 Statements of Cash Flows........................... 4 Statements of Common Stockholder's Equity.......... 5 Notes to Financial Statements...................... 6-16 Report of Independent Public Accountants........... 17 Management's Discussion and Analysis of Financial Condition and Results of Operations............... 18-20 Selected Financial Data............................ 21 Statistics......................................... 21 Statement of Quarterly Financial Data.............. 21 Bondholder Information............................. Back Cover NORTH ATLANTIC ENERGY CORPORATION BALANCE SHEETS
-------------------------------------------------------------------------------- At December 31, 1994 1993 -------------------------------------------------------------------------------- (Thousands of Dollars) ASSETS ------ Utility Plant, at original cost: Electric................................................ $769,379 $758,170 Less: Accumulated provision for depreciation......... 75,176 56,649 --------- --------- 694,203 701,521 Construction work in progress........................... 3,704 7,618 Nuclear fuel, net....................................... 19,797 23,339 --------- --------- Total net utility plant............................. 717,704 732,478 --------- --------- Other Property and Investments: Nuclear decommissioning trusts, at market in 1994 and at cost in 1993 (Note 8)........................... 10,342 7,881 Other, at cost.......................................... 222 - --------- --------- 10,564 7,881 --------- --------- Current Assets: Cash and special deposits (Note 1K)................ 8,166 8,404 Notes receivable from affiliated companies.............. 28,750 - Receivables............................................. - 3,677 Receivables from affiliated companies................... 13,983 20,304 Materials and supplies, at average cost................. 10,036 7,353 Prepayments and other................................... 2,149 4,183 --------- --------- 63,084 43,921 --------- --------- Deferred Charges: Regulatory assets (Note 1G)........................ 166,598 109,765 Unamortized debt expense................................ 4,834 5,507 Other................................................... 795 1,269 --------- --------- 172,227 116,541 --------- --------- Total Assets........................................ $963,579 $900,821 ========= =========
The accompanying notes are an integral part of these financial statements. NORTH ATLANTIC ENERGY CORPORATION BALANCE SHEETS
--------------------------------------------------------------------------------- At December 31, 1994 1993 --------------------------------------------------------------------------------- (Thousands of Dollars) CAPITALIZATION AND LIABILITIES ------------------------------ Capitalization: Common stock--$1 par value--authorized and outstanding 1,000 shares in 1994 and 1993........... $ 1 $ 1 Capital surplus, paid in................................. 160,999 160,999 Retained earnings........................................ 59,236 38,701 --------- --------- Total common stockholder's equity............... 220,236 199,701 Long-term debt (Note 4).............................. 540,000 560,000 --------- --------- Total capitalization............................ 760,236 759,701 --------- --------- Current Liabilities: Long-term debt--current portion.......................... 20,000 - Accounts payable......................................... 4,073 3,999 Accounts payable to affiliated companies................. 38 2,389 Accrued interest......................................... 18,288 18,288 Accrued taxes............................................ 1,439 127 Deferred DOE obligation--current portion................. 845 845 Other.................................................... 329 - --------- --------- 45,012 25,648 --------- --------- Deferred Credits: Accumulated deferred income taxes (Note 1I)......... 120,250 74,772 Deferred obligation to affiliated company (Note 6)... 33,284 33,284 Deferred DOE obligation.................................. 3,553 3,941 Deferred Seabrook tax settlement obligation.............. 1,022 3,475 Other.................................................... 222 - --------- --------- 158,331 115,472 --------- --------- Commitments and Contingencies (Note 7) Total Capitalization and Liabilities............ $963,579 $900,821 ========= =========
The accompanying notes are an integral part of these financial statements. NORTH ATLANTIC ENERGY CORPORATION STATEMENTS OF INCOME
----------------------------------------------------------------------------------------- January 1, January 1, June 5, 1994 1993 1992 to to to December 31, December 31, December 31, For the Periods 1994 1993 1992(a) ----------------------------------------------------------------------------------------- (Thousands of Dollars) Operating Revenues............................. $ 145,751 $ 125,408 $ 78,444 ------------- ------------- ------------- Operating Expenses: Operation -- Fuel...................................... 7,144 7,067 1,688 Other..................................... 37,929 35,656 25,305 Maintenance.................................. 14,951 7,858 9,413 Depreciation................................. 22,959 22,642 12,905 Federal and state income taxes (Note 5).. 8,027 5,673 2,583 Taxes other than income taxes................ 11,791 12,794 10,428 ------------- ------------- ------------- Total operating expenses............... 102,801 91,690 62,322 ------------- ------------- ------------- Operating Income............................... 42,950 33,718 16,122 ------------- ------------- ------------- Other Income: Deferred Seabrook return--other funds (Note 1H)....................... 12,951 13,397 7,784 Other, net................................... 1,272 1,891 200 Income taxes--credit......................... 3,970 1,653 10,428 ------------- ------------- ------------- Other income, net...................... 18,193 16,941 18,412 ------------- ------------- ------------- Income before interest charges......... 61,143 50,659 34,534 ------------- ------------- ------------- Interest Charges: Interest on long-term debt................... 64,022 64,022 36,647 Other interest............................... (280) 45 200 Deferred Seabrook return--borrowed funds (Note 1H)....................... (33,134) (39,406) (15,016) ------------- ------------- ------------- Interest charges, net.................. 30,608 24,661 21,831 ------------- ------------- ------------- Net Income..................................... $ 30,535 $ 25,998 $ 12,703 ============= ============= =============
(a) NAEC began operations on June 5, 1992. The accompanying notes are an integral part of these financial statements. NORTH ATLANTIC ENERGY CORPORATION STATEMENTS OF CASH FLOWS
--------------------------------------------------------------------------------------------------- January 1, January 1, June 5, 1994 1993 1992 to to to December 31, December 31, December 31, For the Periods 1994 1993 1992 --------------------------------------------------------------------------------------------------- (Thousands of Dollars) Cash Flows From Operating Activities: Net Income................................................ $ 30,535 $ 25,998 $ 12,703 Adjustments to reconcile to net cash from operating activities: Depreciation............................................ 22,959 22,642 12,905 Deferred income taxes and investment tax credits, net... 34,449 37,121 8,505 Deferred return - Seabrook.............................. (46,085) (52,803) (22,800) Other sources of cash................................... 5,096 9,050 5,491 Other uses of cash...................................... (2,842) (1,028) (8,104) Changes in working capital: Receivables............................................. 9,998 (790) (20,736) Materials and supplies.................................. (2,683) (1,990) (2,288) Accounts payable........................................ (2,277) 5,026 1,362 Accrued taxes........................................... 1,312 126 (4,970) Other working capital (excludes cash)................... 2,363 822 2,330 ----------- ------------ ------------ Net cash flows from (used for) operating activities......... 52,825 44,174 (15,602) ----------- ------------ ------------ Cash Flows From Financing Activities: Issuance of common shares................................. - - 161,000 Issuance of long-term debt................................ - - 355,000 Net (decrease) increase in short-term debt................ - (18,500) 18,500 Cash dividends on common stock............................ (10,000) - - ----------- ------------ ------------ Net cash flows (used for) from financing activities......... (10,000) (18,500) 534,500 ----------- ------------ ------------ Investment Activities: Investment in plant: Investment in Seabrook assets, net...................... - - (504,265) Electric utility plant.................................. (11,256) (6,707) (6,307) Nuclear fuel............................................ (1,227) (13,983) (511) ----------- ------------ ------------ Net cash flows used for investments in plant.............. (12,483) (20,690) (511,083) NU System Money Pool...................................... (28,750) - - Other investment activities, net.......................... (1,830) (2,844) (1,551) ----------- ------------ ------------ Net cash flows used for investments......................... (43,063) (23,534) (512,634) Net (Decrease) Increase In Cash For The Period.............. (238) 2,140 6,264 Cash and special deposits - beginning of period............. 8,404 6,264 - ----------- ------------ ------------ Cash and special deposits - end of period................... $ 8,166 $ 8,404 $ 6,264 =========== ============ ============ Supplemental Cash Flow Information: Cash paid (received) during the year for: Interest, net of amounts capitalized during construction.. $ 64,056 $ 63,393 $ 18,166 =========== ============ ============ Income taxes.............................................. $ (34,988) $ (32,350) $ (16,000) =========== ============ ============ NAEC began operations on June 5, 1992.
The 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 June 5, 1992 (b)............. $ - $ - $ - $ - Net income for 1992................. 12,703 12,703 Issuance of 1,000 shares of common stock, $1 par value............... 1 1 Premium on common stock............. 160,999 160,999 ---------- ---------- --------- ---------- Balance at December 31, 1992............ 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 ========== ========== ========= ==========
(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. (b) NAEC began operations on June 5, 1992. 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. GENERAL North Atlantic Energy Corporation (NAEC or the Company) is a wholly owned subsidiary of Northeast Utilities (NU). NAEC was incorporated on September 20, 1991 for the purpose of acquiring Public Service Company of New Hampshire's (PSNH) ownership interest in the Seabrook nuclear project (Seabrook). The company has no employees. Upon NU's acquisition of PSNH on June 5, 1992 (Acquisition Date), PSNH's 35.6 percent share of the Seabrook nuclear power plant (Seabrook 1) and other Seabrook-related assets were transferred to NAEC. NAEC also acquired PSNH's 35.6 percent interest in the nuclear fuel for Seabrook 1 and the cancelled Seabrook 2. In addition, it acquired from PSNH ownership of the approximately 719 acres of exclusion area land which surrounds the location of the two Seabrook units. NAEC does not operate Seabrook 1, which at the Acquisition Date, was being operated by the New Hampshire Yankee Division (NHY) of PSNH. Effective June 29, 1992, North Atlantic Energy Service Corporation (NAESCO, another newly formed, wholly owned, subsidiary of NU), replaced NHY as the managing agent and represents the Seabrook joint owners, including NAEC, in the operation of Seabrook 1. On June 29, 1992, all NHY employees became employees of NAESCO. On February 15, 1994, NAEC acquired Vermont Electric Generation and Transmission Cooperative's (VEG&T) 0.4 percent ownership interest of Seabrook for approximately $6.4 million. The company, The Connecticut Light and Power Company, PSNH, Western Massachusetts Electric Company, and Holyoke Water Power Company are the operating subsidiaries comprising the Northeast Utilities system (the system) and are wholly owned by NU. 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 acts as agent for system companies in constructing and 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. B. RECLASSIFICATIONS Certain reclassifications of prior years' data have been made to conform with the current year's presentation. C. JOINTLY OWNED UTILITY PLANT As of December 31, 1994, NAEC has a 35.98 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. As of December 31, 1994 and 1993, plant-in-service included approximately $707.8 million and $758.1 million, respectively, and the accumulated provision for depreciation included approximately $63.1 million and $56.6 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. In February 1994, NAEC purchased an additional 0.4 percent share of Seabrook 1 from VEG&T. 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 FERC. Major facilities are depreciated from the time they are placed in service. For other than major facilities, depreciation factors are applied to the average plant-in-service during the period. 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. For Seabrook 1, the costs of removal, less salvage, that have been funded through external decommissioning trusts will be paid with funds from the trusts and charged to the accumulated reserve for decommissioning included in the accumulated provision for depreciation over the expected service life of the plant. See Note 2, "Nuclear Decommissioning," for additional information. The depreciation rates for the several classes of electric plant-in- service are equivalent to a composite rate of 3.3 percent in 1994 and 3.2 percent in 1993 and 1992. 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 NAEC, 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 the New Hampshire Public Utilities Commission (NHPUC). F. SEABROOK POWER CONTRACT On June 5, 1992, NAEC and PSNH entered into the Seabrook Power Contract (Contract), under which PSNH is obligated to buy from NAEC, and NAEC is obligated to sell to PSNH, all of NAEC's original 35.6 percent ownership share of the capacity and output of Seabrook 1 for a period equal to the length of the Nuclear Regulatory Commission's (NRC) full power operating license for Seabrook 1. The Contract is included as part of the rate agreement between PSNH and the state of New Hampshire (the Rate Agreement). Under the Contract, PSNH is unconditionally obligated to pay NAEC's cost of service during this period whether or not Seabrook 1 is operating. NAEC's cost of service includes all of its Seabrook-related costs, including operation and maintenance expense, fuel expense, property tax expense, depreciation expense, and certain overhead and other costs. The Contract established the value of the initial investment in Seabrook at $700-million (Initial Investment) and the initial investment in nuclear fuel at $0. NAEC is depreciating its Initial Investment on a straight-line basis over the remaining term of Seabrook 1's full power operating license. Any subsequent additions to Seabrook 1 will be depreciated on a straight-line basis over the remaining term of the Contract at the time the additions are brought into service. The Contract provides that NAEC's return on its allowed investment in Seabrook 1 (its investment in working capital, fuel, capital additions after the date of commercial operation of Seabrook 1 and a portion of the Initial Investment) is calculated based on NAEC's actual capitalization from time to time over the term of the Contract, which includes its actual debt and preferred equity costs, and a common equity cost of 12.53 percent for the first ten years of the Contract, and thereafter at an equity rate of return to be fixed in a filing with FERC. If Seabrook 1 is shut down prior to the expiration of the NRC operating license term, PSNH will be unconditionally required to pay NAEC termination costs for 39 years, less the period during which Seabrook 1 has operated. These payments are designed to reimburse NAEC for its share of Seabrook 1 cancellation and decommissioning costs and to provide NAEC a return of and on any undepreciated balance of its Initial Investment in the plant over the then-remaining term of the Contract, 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 such shut down). NAEC is selling the output from the additional 0.4 percent Seabrook interest purchased from VEG&T on February 15, 1994 to PSNH under an agreement that has been approved by the FERC and is substantially similar to the Seabrook Power Contract between PSNH and NAEC that was effective on the Acquisition Date. G. REGULATORY ACCOUNTING NAEC follows accounting policies that reflect the impact of the rate treatment of certain events or transactions that differ from generally accepted accounting principles for those events or transactions followed by nonregulated enterprises. Under regulatory accounting, assuming that future revenues are expected to be sufficient to provide recovery, regulators may permit incurred costs, normally treated as expenses, to be deferred and recovered in revenues at a later date. Regulatory accounting is unique in that the actions of a regulator can provide reasonable assurance of the existence of an asset. Regulators, through their actions, may also reduce or eliminate the value of an asset, or create a liability. If the economic entity no longer comes under the jurisdiction of a regulator or external forces, such as a move to a competitive environment, effectively limiting the influence of cost-of-service based rate regulation, the entity may be forced to abandon regulatory accounting, requiring a reexamination and potential write-off of net regulatory assets. NAEC continues to be subject to cost-of-service based rate regulation. Based on current regulation, NAEC believes that its use of regulatory accounting is still appropriate. The components of regulatory assets are as follows: At December 31, 1994 1993 -------------------------------------------------------------- (Thousands of Dollars) Deferred costs-Seabrook (Note 1H) .... $131,513 $ 85,428 Income taxes, net (Note 1I) .......... 30,461 19,432 Recoverable energy costs (Note 1J) ... 4,624 4,905 -------- --------- ..................................... $166,598 $ 109,765 ======== ========= H. DEFERRED COST - SEABROOK NAEC is phasing into rates the recoverable portions of its investment in Seabrook 1. NAEC is deferring costs as part of its phase-in plan. Its plan is in compliance with SFAS No. 92, Regulated Enterprises - Accounting for Phase-In Plans. As prescribed by the Rate Agreement, NAEC is phasing in its investment in Seabrook 1. As of December 31, 1994, the portion of the investment on which NAEC is entitled to earn a cash return was 70 percent and will increase by 15 percent in each of the next two years beginning May 1, 1995. From the Acquisition Date through December 31, 1994, NAEC recorded $131.5 million of deferred return on the excluded portion of its investment in Seabrook 1, which has been recorded in "Regulatory Assets" on the Balance Sheets. 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. 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. See Note 5, "Income Tax Expense," for the components of income tax expense. When NU acquired PSNH on June 5, 1992, PSNH and NAEC became parties to the Tax Allocation Agreement among the members of the NU system. The Tax Allocation Agreement requires each member of the NU system to pay to NU the amount, if any, that would have been its federal income tax liability if it had filed a separate return, with certain adjustments, and requires NU to distribute the excess of the sum of such payments over the NU system's consolidated federal income tax liability among those members of the NU system that had tax items that reduced the NU system's current consolidated tax liability. A substantial portion of NAEC's cash flow for the first few years of operations is expected to consist of payments made by NU to NAEC under the Tax Allocation Agreement. The amount of such payments will decrease over time but is expected to remain substantial during the first few years of operations when NAEC is expected to incur losses for tax purposes due to the accelerated tax depreciation of Seabrook 1. Under the Tax Allocation Agreement, NAEC's tax losses may be utilized to offset taxable income of the NU system and NU is required, under the Tax Allocation Agreement, to pay NAEC for the use of such tax benefits. Such tax losses, if not fully utilized in the taxable year in which they were incurred, may be carried back to each of the three taxable years of the NU system preceding the taxable year in which they are incurred. If the NU system does not have enough taxable income in the taxable year in which such losses are incurred or in the preceding taxable years to permit it to take full advantage of such tax losses, or if the NU system is in an alternative minimum tax position in any such year, then the amount of payments under the Tax Allocation Agreement to NAEC will be decreased and NAEC's cash flow will be adversely affected. No assurance can be given that NAEC's cash flow will not be adversely affected in subsequent years by the inability of the other members of the NU system to utilize fully the tax losses expected to be incurred by NAEC. In 1992, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes (SFAS 109). SFAS 109 supersedes previously issued income tax accounting standards. NAEC adopted SFAS 109, on a prospective basis, during the first quarter of 1993. The adoption of SFAS 109 has not had a material effect on the net income or on the balance sheet of the company. As it is probable that the increase in deferred tax liabilities will be recovered from customers through rates, NAEC also established a regulatory asset. The tax effect of the temporary differences which give rise to the accumulated deferred tax obligation are as follows: At December 31, 1994 1993 ------------------------------------------------------------- (Thousands of Dollars) Accelerated depreciation and other plant-related differences ........ $ 93,486 $ 46,184 Regulatory assets-income tax gross up 7,223 6,801 Other .............................. 19,541 21,787 -------- -------- ................................... $120,250 $ 74,772 ======== ======== 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 has begun to recover these costs. K. CASH AND SPECIAL DEPOSITS Cash and special deposits at December 31, 1994 and 1993 included $5.7 million and $7.3 million, respectively, in special deposits that will be used to fund the company's share of future Seabrook operational costs. 2. NUCLEAR DECOMMISSIONING A 1994 Seabrook decommissioning study, which is currently under review by the New Hampshire Decommissioning Financing Committee, 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, technology, and inflation. NAEC's 36 percent ownership of the estimated cost of decommissioning Seabrook 1 (utilizing the currently approved decommissioning study), in year-end 1994 dollars, is $137.3 million. These estimated costs have been levelized and assume after-tax earnings on the Seabrook decommissioning funds of 6.1 percent. Future escalation rates in decommissioning costs for Seabrook are assumed. 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 $2.7 million in 1994, $2.6 million in 1993 and $1.4 million in 1992. Nuclear decommissioning, as a cost of removal, is included in the accumulated provision for depreciation on the Balance Sheets. At December 31, 1994, the balance in the accumulated reserve for decommissioning amounted to $10.3 million. See "Nuclear Decommissioning" in the Management's Discussion and Analysis 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'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 trust, held by a financing fund managed by the state of New Hampshire. As of December 31, 1994, NAEC (including pre-Acquisition Date payments made by PSNH) has paid approximately $10.1 million into Seabrook 1's decommissioning trust. Earnings on the decommissioning trust increase the decommissioning trust balance and the accumulated reserve for decommissioning. Due to NAEC's adoption, effective January 1, 1994, of SFAS 115, Accounting for Certain Investments in Debt and Equity Securities, unrealized gains and losses associated with the decommissioning trust also impact the balance of the trust 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. Because allowances for decommissioning have increased significantly in recent years, PSNH may need to increase its payments in future years to offset the effects of any insufficient rate recoveries in previous years. 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, 1994 and 1993, NAEC had no outstanding borrowings from the Pool. 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 the system companies 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 ----------- 1994 1993 ---------------------------------------------------------------- (Thousands of Dollars) First Mortgage Bonds: 9.05% Series A, due 2002 ..... $355,000 $355,000 Notes: 15.23% due 2000 ............. 205,000 205,000 Less: Amounts due within one year 20,000 - -------- -------- Long-term debt, net .... $540,000 $560,000 ======== ======== Long-term debt maturities and cash sinking-fund requirements on debt outstanding at December 31, 1994 for the years 1995 through 1999 are $20,000,000 annually for 1995-1998 and $70,000,000 in 1999. 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 discussed above. 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:
January 1, 1994 January 1 to June 5, to December 31, 1993 to For the Periods December 31, 1994 (Note 1I) December 31, 1992 --------------------------------------------------------------------------------------------------- (Thousands of Dollars) Current income taxes: Federal $(30,553) $(33,225) $(16,350) State 161 124 - -------- -------- -------- Total current (30,392) (33,101) (16,350) -------- -------- -------- Deferred income taxes, net: Federal 34,449 37,199 16,240 State 0 (78) 1,979 -------- -------- --------- Total deferred 34,449 37,121 18,219 -------- -------- --------- Total income tax expense $ 4,057 $ 4,020 $ 1,869 ========= ========= ========= The components of total income tax expense are classified as follows: Income taxes charged to operating expenses $ 8,027 $ 5,673 $ 2,583 Income taxes associated with allowance for funds used during construction (AFUDC) and deferred Seabrook 1 return - borrowed funds - - 9,714 Other income taxes - credit (3,970) (1,653) (10,428) --------- --------- --------- Total income tax expense $ 4,057 $ 4,020 $ 1,869 ========= ========= ========= Deferred income taxes are comprised of the tax effects of temporary differences as follows: January 1, 1994 January 1 to June 5, to December 31, 1993 to For the Periods December 31, 1994 (Note 1I) December 31, 1992 --------------------------------------------------------------------------------------------------- (Thousands of Dollars) Depreciation $22,783 $23,000 $16,146 Alternative minimum tax 73 1,250 (7,641) AFUDC and deferred Seabrook return, net 11,597 13,792 9,714 Property taxes - (1,003) - Other (4) 82 - ------- ------- ------- Deferred income taxes, net $34,449 $37,121 $18,219 ======== ======= ======= A reconciliation between income tax expense and the expected tax expense at the applicable statutory rate is as follows: January 1, 1994 January 1 to June 5, to December 31, 1993 to For the Periods December 31, 1994 (Note 1I) December 31, 1992 --------------------------------------------------------------------------------------------------- (Thousands of Dollars) Expected federal income tax at 35 percent of pretax income for 1994 and 1993 and at 34 percent for 1992 $12,107 $10,506 $ 4,954 Tax effect of differences: Depreciation differences (2,087) (1,481) (1,546) Deferred Seabrook return - other funds (4,533) (4,689) (2,647) State income taxes, net of federal benefit 104 30 1,306 Other, net (1,534) (346) (198) -------- -------- -------- Total income tax expense $ 4,057 $ 4,020 $ 1,869 ======== ======== ========
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 Contract, 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 transferred the $50.9 million deferred return to NAEC as part of the Seabrook-related assets. At the time PSNH sold 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 Contract. 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, NAEC recorded the $32.9 million of income taxes associated with the deferred return as an adjustment to the purchase price of the Seabrook-related assets, with a corresponding obligation to PSNH, on its Balance Sheet. In 1993, due to changes in tax rates, this amount was adjusted to $33.3 million. 7. COMMITMENTS AND CONTINGENCIES A. SEABROOK 1 CONSTRUCTION PROGRAM The construction program for Seabrook 1 is subject to periodic review and revision. Actual construction expenditures may vary from estimates due to factors such as inflation, revised nuclear safety regulations, delays, difficulties in the licensing process, the availability and cost of capital, and other actions taken by regulatory bodies. NAEC currently forecasts construction expenditures (including AFUDC) for its share of Seabrook 1 to be $31.9 million for the years 1995- 1999, including $5.0 million for 1995. In addition, NAEC estimates that its share of Seabrook 1 nuclear fuel requirements will be $46.1 million for the years 1995-1999, including $9.6 million for 1995. 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. Changing environmental requirements could hinder future construction. The cumulative long-term, economic cost impact of increasingly stringent environmental requirements cannot be accurately 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. In most cases, the extent of additional future environmental cleanup costs is 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. NAEC cannot estimate the potential liability for future claims that may be brought against it. However, considering known facts and 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 The Price-Anderson Act currently limits public liability from a single incident at a nuclear power plant to $8.9 billion. The first $200 million of liability would be provided by purchasing the maximum amount of commercially available insurance. Additional coverage of up to a total of $8.3 billion would be provided by an assessment of $75.5 million per incident, levied on each of the 110 nuclear units that are currently subject to the Secondary Financial Protection Program in the United States, subject to a maximum assessment of $10 million per incident per nuclear unit in any year. In addition, if the sum of all public liability claims and legal costs arising from any nuclear incident exceeds the maximum amount of financial protection, each reactor operator can be assessed an additional 5 percent, up to $3.8 million, or $415.3 million in total, for all 110 nuclear units. The maximum assessment is to be adjusted at least every five years to reflect inflationary changes. At December 31, 1994, based on NAEC's ownership interest in Seabrook 1, the maximum liability would be $28.5 million per incident. Payments for NAEC's ownership interest in Seabrook 1 would be limited to a maximum of $3.6 million per incident per year. Insurance has been purchased from Nuclear Electric Insurance Limited (NEIL) to cover the cost of repair, replacement, or decontamination or premature decommissioning of utility property resulting from insured occurrences with respect to NAEC's ownership interest in Seabrook 1. All companies insured with NEIL are subject to retroactive assessments if losses exceed the accumulated funds available to NEIL. The maximum potential assessments against NAEC with respect to losses arising during current policy years are approximately $8.4 million under the property damage, decontamination, and decommissioning policies. Although NAEC 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 from American Nuclear Insurers/Mutual Atomic Energy Liability Underwriters, aggregating $200 million on an industry basis for coverage of worker claims. All companies insured under this coverage are subject to retrospective assessments of $3.1 million per reactor. The maximum potential assessments against NAEC with respect to losses arising during the current policy period are approximately $1.1 million. Under the terms of the Contract, any nuclear insurance assessments described above would be passed on to PSNH as a "cost of service." 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, special deposits, and nuclear decommissioning trust: The carrying amounts approximate fair value. SFAS 115 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. As a result of the adoption of SFAS 115, the investments held by the decommissioning trust decreased by approximately $850 thousand as of December 31, 1994, with a corresponding offset to the accumulated provision for depreciation. 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: At December 31, 1994 Carrying Amount Fair Value ---------------------------------------------------------------- (Thousands of Dollars) First Mortgage Bond ............ $355,000 $351,450 Other long-term debt ........... 205,000 242,925 At December 31, 1993 Carrying Amount Fair Value ------------------------------------------------------------------ (Thousands of Dollars) First Mortgage Bonds ........... $355,000 $373,496 Other long-term debt ........... 205,000 254,057 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. 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, 1994 and 1993, and the related statements of income, common stockholder's equity, and cash flows for the year ended December 31, 1994 and 1993 and the period from June 5, 1992 to December 31, 1992. 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, 1994 and 1993, and the results of its operations and its cash flows for the years ended December 31, 1994 and 1993 and the period from June 5, 1992 to December 31, 1992, in conformity with generally accepted accounting principles. /s/ Arthur Andersen LLP ARTHUR ANDERSEN LLP Hartford, Connecticut February 17, 1995 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 operations. The company is a wholly-owned subsidiary of Northeast Utilities (NU). This section should be read in conjunction with the company's financial statements and footnotes. FINANCIAL CONDITION OVERVIEW On June 5, 1992 (Acquisition Date), NU acquired Public Service Company of New Hampshire (PSNH), and PSNH's 35.6 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 (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 for a period equal to the length of the Nuclear Regulatory Commission 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 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. The company's "cost of service" includes all of its prudently incurred Seabrook-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 investment. The Contract established the initial recoverable investment in Seabrook at $700 million (Initial Investment), plus any capital additions, net of depreciation. The company's only assets are Seabrook and other Seabrook-related assets and its only source of revenue is the Contract. PSNH's obligations under the Contract are solely its own and have not been guaranteed by NU. The Contract contains no provisions entitling PSNH to terminate its obligations. If, however, PSNH were to fail to perform its obligations under the Contract, the company would be required to find other purchasers for Seabrook power. RATE MATTERS NAEC follows accounting principles that allow the rate treatment for certain events or transactions to be reflected. These principles may differ from the accounting principles followed by nonregulated enterprises. Regulators may permit incurred costs, which would normally be treated as expenses by nonregulated enterprises, to be deferred as regulatory assets and recovered in revenues at a later date. Regulatory assets at December 31, 1994 were approximately $167 million. Based on current regulation, the company believes that its use of regulatory accounting is still appropriate. As of December 31, 1994, NAEC has included in rates $490 million of its Seabrook investment. The remaining investment ($210 million) will be phased into rates over the next two years, beginning in May 1995. As of December 31, 1994, the deferred return associated with the amount of investment that has not been included in rates was approximately $183 million, including approximately $51 million which is recorded as utility plant. This amount and the additional deferred amounts associated with the remaining phase-in will be recovered under NAEC's Contract with PSNH over the period December 1997 through May 2001. SEABROOK PERFORMANCE The Seabrook plant operated at 61.6 percent of capacity for the year ended December 31, 1994, compared with 89.8 percent in 1993 and a 1994 national average of 73.2 percent. The lower 1994 capacity factor was primarily the result of an unplanned outage earlier in the year and an extended refueling and maintenance outage. The unit was taken out of service on January 25, 1994 when an automatic trip from 100 percent power occurred when a main steam isolation valve closed during quarterly surveillance testing. The unit returned to service on February 18, 1994. The unit began its scheduled 57-day refueling and maintenance outage on April 9, 1994. The unexpected discovery of reactor coolant pump locking cups and a bolt in the reactor vessel contributed substantially to the duration of the outage. The unit returned to service on August 1, 1994 for an outage duration of 114 days. The next refueling outage is scheduled for November 1995. ENVIRONMENTAL MATTERS/NUCLEAR DECOMMISSIONING NAEC is subject to regulation by federal, state, and local authorities with respect to air and water quality, handling and the disposal of toxic substances and hazardous and solid wastes, and the handling and use of chemical products. The cumulative long-term economic cost impact of increasingly stringent environmental requirements cannot be estimated. However, NAEC has an active environmental auditing program to detect and remedy noncompliance with environmental laws or regulations. NAEC may incur significant additional 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. The estimated cost of decommissioning NAEC's 36 percent ownership share of Seabrook, in year-end 1994 dollars, is approximately $137 million. 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 $2.7 million in 1994 and $2.6 million in 1993. PSNH is obligated to pay the company's share of Seabrook's decommissioning costs even if the unit is shut down prior to the expiration of its license. Nuclear decommissioning, as a cost of removal, is included in the accumulated provision for depreciation on the Balance Sheets. The staff of the Securities and Exchange Commission has questioned certain of the current accounting practices of the electric utility industry, including this company, regarding the recognition, measurement, and classification of decommissioning costs for nuclear generating stations in the financial statements of electric utilities. The Financial Accounting Standards Board is currently reviewing the accounting for removal costs, including decommissioning and similar costs. If current electric utility industry accounting practices for such decommissioning costs are changed: (1) annual provisions for decommissioning could increase, (2) the estimated costs for decommissioning could be recorded as a liability rather than as accumulated depreciation, and (3) trust fund income from the external decommissioning trust could be reported as investment income rather than as a reduction to decommissioning expense. See "Notes to Financial Statements" for further information regarding nuclear decommissioning and other environmental matters. LIQUIDITY AND CAPITAL RESOURCES Cash provided from operations increased approximately $9 million in 1994, as compared with 1993, primarily due to the increased return associated with the phase-in of additional Seabrook plant. Cash used for financing activities was approximately $9 million lower in 1994, as compared with 1993, primarily due to the repayment of short-term debt in 1993, partially offset by the payment of cash dividends on common stock in 1994. Cash used for investments was approximately $20 million higher in 1994, as compared with 1993, primarily due to short-term loans to other NU system companies under the NU system Money Pool and higher investment in plant, partially offset by lower nuclear fuel expenditures in 1994. The company's construction program expenditures amounted to approximately $11 million in 1994, as compared to approximately $7 million for 1993. The increase is due to expenditures incurred as a result of NAEC's purchase of Vermont Electric Generation and Transmission Company's 0.4 percent share of Seabrook in 1994, for approximately $6 million. Nuclear fuel expenditures decreased approximately $13 million in 1994 from 1993 due to expenditures in 1993 for the Seabrook refueling outage. The company has ongoing cash requirements for Seabrook-related capital expenditures, nuclear fuel expenditures, interest and operating expenses. Capital expenditures for the period 1995 through 1999 are expected to be approximately $32 million (including allowance for funds used during construction (AFUDC)), including $5 million for 1995. Nuclear fuel expenditures for the same period are expected to be approximately $46 million (excluding AFUDC), including $10 million for 1995. Such cash requirements are expected to be met from payments under the Contract and the Tax Allocation Agreement, except that to the extent some or all of the capital expenditures and nuclear fuel expenditures may have to be financed, the company expects to borrow under the Money Pool. As of December 31, 1994, there were no borrowings outstanding under the Money Pool. A substantial portion of the company's cash flow for the first few years is expected to consist of payments made by NU to the company under a Tax Allocation Agreement that the company entered into with NU at the time of the acquisition. The amount of such payments will decrease over time but is expected to remain substantial during the first few years when the company is expected to incur losses for tax purposes due to accelerated tax depreciation of Seabrook. The company received approximately $16 million from NU for the period ended December 31, 1994 under this agreement. No assurance can be given, however, as to the extent of the future benefits, if any, that will actually accrue to the company under the Tax Allocation Agreement. (See "Notes to Financial Statements" for further information regarding the Tax Allocation Agreement.) RESULTS OF OPERATIONS Operating revenues represent amounts billed to PSNH under the terms of the Contract and billings to PSNH for decommissioning expense. Operating revenues increased approximately $20 million in 1994, as compared to 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. Operation and maintenance expenses increased approximately $9 million in 1994, as compared to 1993, primarily due to the unplanned and extended Seabrook outages in 1994. Deferred Seabrook return - other and borrowed funds decreased approximately $6 million in 1994, as compared to 1993, primarily because additional Seabrook investment was phased into rates in May 1994. The company has no historical results prior to June 5, 1992. Therefore, the Statements of Income for the periods June 5, 1992 to December 31, 1992 and January 1, 1993 to December 31, 1993 are not comparable. SELECTED FINANCIAL DATA 1994 1993 1992* ---------------------------------------------------------------------- (Thousands of Dollars) Operating Revenues.... $145,751 $125,408 $ 78,444 ======== ======== ========= Operating Income...... $ 42,950 $ 33,718 $ 16,122 ========= ========= ========= Net Income............ $ 30,535 $ 25,998 $ 12,703 ========= ========= ========= Cash Dividends on Common Stock$ 10,000 $ - $ - ========= ========== ========= Total Assets.......... $963,579 $900,821 $818,123 ======== ======== ======== Long-Term Debt(a)..... $560,000 $560,000 $560,000 ======== ======== ======== (a)Includes portion due within one year STATISTICS 1994 1993 1992* --------------------------------------------------------------------------- Gross Electric Utility Plant December 31, (Thousand of Dollars). $792,880 $789,127 $774,920 ======== ======== ======== kWh Sales (Millions).. 2,229 3,218 1,268 ======== ======== ======== STATEMENTS OF QUARTERLY FINANCIAL DATA (UNAUDITED) ------------------------------------------------------------------------- Quarter Ended ----------------------------------------------- 1994 March 31 June 30 September 30 December 31 ------------------------------------------------------------------------- (Thousands of Dollars) 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 ======= ======== ======== ======= 1993 ------------------------------------------------------------------------- Operating Revenues.... $29,153 $29,952 $31,845 $34,458 ======= ======= ======= ======= Operating Income...... $ 6,541 $ 7,964 $ 9,657 $ 9,556 ======= ======= ======= ======= Net Income............ $ 5,185 $ 5,985 $ 7,491 $ 7,337 ======= ======= ======= ======= * The company began commercial opertions on June 5, 1992. EX-27.1 21
UT 0000072741 NORTHEAST UTILITIES AND SUBSIDIARIES 1,000 YEAR DEC-31-1994 DEC-31-1994 PER-BOOK 6,603,447 389,695 779,637 2,812,101 0 10,584,880 671,051 904,371 946,988 2,309,086 375,250 234,700 3,942,005 180,000 0 10,000 170,523 4,425 166,018 73,103 3,119,770 10,584,880 3,642,742 280,126 2,800,866 3,094,510 548,232 49,256 611,006 281,090 329,916 43,042 286,874 219,317 314,191 920,882 2.30 0.00
EX-27.2 22
UT 0000023426 THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES 1,000 YEAR DEC-31-1994 DEC-31-1994 PER-BOOK 4,133,653 241,644 413,003 1,429,157 0 6,217,457 122,229 632,117 765,724 1,520,070 226,250 166,200 1,815,579 168,750 0 10,000 8,111 3,750 120,268 55,701 2,122,778 6,217,457 2,328,052 186,001 1,850,855 2,045,893 282,159 25,962 317,158 118,870 198,288 23,895 174,393 159,388 119,927 532,322 0.00 0.00
EX-27.3 23
UT 0000106170 WESTERN MASSACHUSETTS ELECTRIC COMPANY 1,000 YEAR DEC-31-1994 DEC-31-1994 PER-BOOK 846,494 74,991 75,200 186,933 0 1,183,618 26,812 149,683 111,586 288,081 24,000 68,500 345,669 0 0 0 34,300 675 23,852 12,945 385,596 1,183,618 421,477 32,724 317,884 351,424 70,053 5,718 76,587 27,130 49,457 5,897 43,560 29,514 27,678 115,753 0.00 0.00
EX-27.4 24
UT 0000315256 PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE 1,000 YEAR DEC-31-1994 DEC-31-1994 PER-BOOK 1,584,525 21,760 210,103 1,029,579 0 2,845,967 1 421,784 125,034 546,819 125,000 0 905,985 0 0 0 94,000 0 849,776 38,191 286,196 2,845,967 922,039 68,634 701,865 769,953 152,086 2,708 154,248 76,804 77,444 13,250 64,194 0 76,410 180,036 0.00 0.00
EX-27.5 25
UT 0000880416 NORTH ATLANTIC ENERGY CORPORATION 1,000 YEAR DEC-31-1994 DEC-31-1994 PER-BOOK 717,704 10,564 63,084 172,227 0 963,579 1 160,999 59,236 220,236 0 0 540,000 0 0 0 20,000 0 0 0 183,343 963,579 145,751 4,057 94,774 102,801 42,950 14,223 61,143 30,608 30,535 0 30,535 10,000 64,022 52,825 0.00 0.00