Annual Report (Form 10-K), fiscal year 1994

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.



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

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.

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.

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.

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.

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.


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.

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.



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.

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:
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.

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.

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.

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)
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)
SCHEDULE I NORTHEAST UTILITIES (PARENT) FINANCIAL INFORMATION OF REGISTRANT STATEMENT OF CASH FLOWS YEARS ENDED DECEMBER 31, 1994, 1993, 1992 (Thousands of Dollars)
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.