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. 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]), the System furnishes electric service in Connecticut, New Hampshire and western Massachusetts. In addition to their retail electric service, CL&P, PSNH, WMECO and HWP (including its wholly-owned subsidiary Holyoke Power and Electric Company) together furnish firm wholesale electric service to eight municipalities and 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.
NU acquired PSNH, the largest electric utility in New Hampshire, in June 1992. PSNH was in bankruptcy reorganization proceedings from January 1988 to May 1991, when it emerged from bankruptcy in the first step of an NU- sponsored two-step plan of reorganization. NU's acquisition of PSNH was the second step of the reorganization plan. On October 1, 1993, the Bankruptcy Court in New Hampshire formally terminated the bankruptcy proceeding. See Item 3, Legal Proceedings. PSNH continues to operate its core electric utility business, but pursuant to the reorganization plan, PSNH transferred its 35.6 percent interest in the Seabrook nuclear generating facility (Seabrook) in Seabrook, New Hampshire to North Atlantic Energy Corporation (NAEC), a special purpose subsidiary of NU which sells the capacity and output of that unit to PSNH under two life-of-unit, full cost recovery contracts. In June 1992, NU's subsidiary North Atlantic Energy Service Corporation (North Atlantic) assumed operational responsibility for Seabrook. Before that, Seabrook had been operated by a division of PSNH.
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 nuclear generating facilities in Connecticut. North Atlantic acts as agent for the System companies and other New England utilities in operating Seabrook. Two 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 independent power production facilities. HEC provides energy management services for commercial, industrial and institutional electric customers. See "Non-Utility Businesses."
COMPETITION AND MARKETING
Competition within the electric utility industry is increasing. In response, NU 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. These initiatives are aimed at keeping customers from either leaving NU's retail service territory or replacing NU's electric service with alternative energy sources and at attracting new customers. Management believes that CL&P, PSNH and WMECO must continue to be responsive to their business customers, in particular, in dealing with the price of electricity and to recognize that many business customers have alternatives such as fuel switching, relocation and self- generation if the price of electricity is not competitive.
A System-wide emphasis on improved customer service is a central focus of the reorganization of NU that became effective on January 1, 1994. The reorganization entails realignment of the System into two new core business groups. The first core business group, the energy resources group, is devoted to energy resource acquisition and wholesale marketing and focuses on nuclear, fossil and hydroelectric generation, wholesale power marketing and new business development. The second core business 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 has begun a corporate reengineering process which should help it to identify opportunities to become more competitive while improving customer service and maintaining a high level of operational performance.
ECONOMIC DEVELOPMENT
The cost of doing business, including the price of electricity, is higher in the System's service area, and the Northeast generally, than in most other parts of the country. Relatively high state and local taxes, labor costs and other costs of doing business in New England also contribute to competitive disadvantages for many industrial and commercial customers of CL&P, PSNH and WMECO. These disadvantages have aggravated the pressures on business customers in the current weakened regional economy. As a result, state and local governments in the region frequently offer incentives to attract new business development to, and to expand existing businesses within, their states. Since 1991, CL&P and WMECO have worked actively with state and local economic development authorities to package incentives for a variety of prospective or expanding customers. These economic development packages typically include both electric rate discounts and incentive payments for energy efficient construction, as well as technical support and energy conservation services.
In general, electric rate discounts are phased out over varying periods generally not in excess of ten years. From September 1991 through March 1, 1994, economic development rate agreements had been reached with approximately 45 industrial and commercial customers in the three states served by the System, including 38 customers in CL&P's service territory, one customer in PSNH's service territory and six customers in WMECO's service territory.
As an adjunct to their economic development efforts, CL&P and WMECO have also developed programs which provide incentives to customers planning to construct or significantly renovate commercial or industrial buildings within the System's service territory. Approximately 40 percent of all such construction qualifies for incentive payments for the installation or retrofitting of energy-efficient equipment designed to result in permanent savings for the customer in addition to any savings that result from the rate discounts.
The business expansion-related rate agreements cover small-to- medium-sized industrial companies and a few medium-sized commercial business relocations. In all cases where economic development rates are in effect, the additional load and associated revenues, even though received under discounted rates, result in a net benefit to the System by making a contribution towards the System's fixed costs. During 1993, 28 customers were on economic development rate riders, including 24 CL&P customers and four WMECO customers. The net benefit to the System during 1993 as a result of these agreements was approximately $300,000.
BUSINESS RETENTION/BUSINESS RECOVERY
From 1983 through 1989, the System's retail kilowatt-hour sales grew by an annual average rate of 3.8 percent. Since the end of 1989, retail sales have been level, except for the addition of PSNH's electric load as a result of NU's acquisition of PSNH, effective in June 1992. The leveling effect has resulted in part from the System's conservation and load management (C&LM) efforts, but is largely due to the region's persistent weak economy. Management expects a modest improvement in the economy in 1994 and moderate electric sales growth is anticipated.
To spur economic activity, NU's subsidiaries have worked in concert with state and local authorities to retain businesses that are considering relocating outside of the NU service territory. C&LM incentives are used with temporary rate reductions to produce both short-term and long-term cost savings for customers. These reductions are generally limited to five years but may be for as long as ten years. As of the end of 1993, 25 System customers received such reductions, including 19 CL&P customers, two PSNH customers and five WMECO customers. These customers in the aggregate represented less than 0.5 percent of System revenues.
The NU operating subsidiaries also offer rate reductions to business entities that can demonstrate that they are encountering financial problems threatening their viability but have reasonable prospects for improvement. These "business recovery" reductions can be brief in duration, sometimes lasting only a few months, or may extend for up to five years. From the time these rates became available in late 1991 through the end of 1993, 23 CL&P customers, two PSNH customers and eight WMECO customers have been granted such rate reductions. The CL&P customers provided approximately $10 million in annual revenues; the PSNH customers provided approximately $10 million in annual revenues and the WMECO customers provided approximately $1.5 million in annual revenues.
The bulk of the cost of the presently estimated discounts has been anticipated in base rates. The cost of the C&LM program is also collected from ratepayers.
COMPETITIVE GENERATION
A growing source of competition in the electric utility industry comes from companies that are marketing co-generation systems, primarily to those customers who can use both the electricity and the steam created by such systems. See "Regulatory and Environmental Matters - Public Utility Regulation." For instance, the Pratt & Whitney Aircraft Division of United Technologies Corporation, the System's largest industrial customer, put into service a 25-megawatt generating system in January 1993, reducing CL&P's industrial sales by approximately 1.5 percent, or $8 million, during 1993. While only a few other such systems have been installed in the System's service territory to date, the extent of growth of further self-generation cannot be predicted.
To help convince retail customers not to generate their own power, CL&P, PSNH and WMECO have offered a competitive generation rate or special rate contracts that typically provide for up to ten years of rate reductions in return for a commitment not to self-generate. Two of CL&P's largest customers, together accounting for approximately $12 million of annual revenues in 1993, are operating under these arrangements. The New Hampshire Public Utilities Commission (NHPUC) also approved a special PSNH rate available for operators of sawmills to help prevent those customers from installing diesel generation. Altogether, approximately 28 System customers were on some type of competitive generation rate or special contract at the end of 1993, consisting of two CL&P customers, 20 PSNH customers and six WMECO customers. The PSNH customers provided approximately $3 million in annual revenues and the WMECO customers provided approximately $1.5 million in annual revenues.
Overall, all types of flexible rate riders and special contracts offered by the System have preserved System revenues of approximately $50 million. As each subsidiary intensifies its efforts to retain existing customers and gain new customers, the number of customers covered under such flexible rates, and the number and amount of overall discounts, are expected to rise moderately over the next few years.
RETAIL WHEELING
In principle, retail wheeling would enable a retail customer to select an electricity supplier and force the local electric utility to transmit the power to the customer's site. While wholesale wheeling was mandated by the Energy Policy Act of 1992 (Energy Policy Act) under certain circumstances, retail wheeling is generally not required in any of the System's jurisdictions. See "Regulatory and Environmental Matters - Public Utility Regulation." In Connecticut, the Department of Public Utility Control (DPUC) has begun an investigation into the desirability of retail wheeling; a similar DPUC study undertaken in 1987 concluded that full-scale ail wheeling was not in the public interest at that time. See "Rates-Connecticut Retail Rates."
In New Hampshire, there have been no legislative proposals on full- scale retail wheeling to date.
In Massachusetts, bills being reviewed by legislative committees could permit limited retail wheeling in economically distressed areas and to municipal and state-owned facilities.
FUEL SWITCHING/ELECTROTECHNOLOGIES
A customer's ability to switch to or from electricity as an energy source for heating, cooling or industrial processes (fuel switching) will continue to provide the System with both opportunities and risks over the coming years.
While it is an important load, residential electric space heating makes up only five percent of the System's retail sales. In Connecticut and Massachusetts, the risk of fuel switching among residential customers is concentrated in the area of electric to natural gas conversions with lesser risks of oil and propane conversions, while in New Hampshire, conversions to oil and propane are more common. During 1993, approximately three percent of WMECO and PSNH space heating customers converted their heating systems from electric resistance or baseboard heating. Conversion activity in CL&P's service territory was minimal during 1993 and the net number of electric space heating customers in CL&P's territory increased during 1993. Since 1992, space heating conversions on the System have not represented more than a 0.1 percent loss of annual retail sales. Nonetheless, the System operating companies have implemented a number of programs to mitigate these losses. In New Hampshire, a new thermal energy storage program is being reviewed for approval by the NHPUC. In Connecticut and Massachusetts, programs are in place to encourage the use of ground source and advanced air-to-air heat pumps in both new and existing construction. In addition, in 1993 WMECO lowered rates for its electric space heating cusomters by approximately five percent with permission from the Massachusetts Department of Public Utilities (DPU) to address the competitive threat. Because of these programs and other initiatives, NU forecasts a continued increase in the net number of electric space heating customers.
With respect to residential sales, central air conditioning continues to become more common in the System's service territory. The System has also begun to test the use of electric vehicles in all three of its service territories and is working to promote the manufacture of electric vehicles and their components in the System's service area. The System's energy conservation programs which target electric heat and hot water customers can be effective in lowering electric bills substantially. In 1993, the System embarked upon two aggressive field testing programs involving heat pumps to provide residential heating, cooling and hot water heating in cost effective ways. These programs, in Massachusetts and at Heritage Village in Southbury, Connecticut, are intended to demonstrate that the combination of cost effective conservation and the use of heat pumps will provide lower cost heating, cooling and water heating than other available fuels.
The System also faces commercial load loss because of fuel switching, such as in the area of electrically heated commercial buildings. Additionally, natural gas distribution companies have been actively marketing gas-fired chillers to commercial and industrial customers. Electric space and hot water heating and air conditioning have come under increasing pressure in recent years from aggressive campaigns by natural gas distribution companies seeking to add new customers. In Connecticut and Massachusetts, NU's subsidiaries have initiated market driven heating, ventilating and air-conditioning (HVAC) incentive programs, which include some design assistance, to promote efficient, nonchlorofluorocarbon refrigerant electric chillers.
In response to the threat of load loss due to alternative fuel sources, the System's marketing and customer service staff works proactively to compare relative costs of alternative fuels. In most instances, accurate cost comparisons and energy conservation programs allow the System to preserve most of each customer's load by assisting the customer to achieve a more efficient use of its electric energy.
WHOLESALE MARKETING
In general and subject to existing contractual restrictions, the System's wholesale customers, both within and outside the System's retail service area, are free to select any supplier they choose. NU's subsidiaries do not have an exclusive franchise right to serve such customers. Thus, the wholesale segment of the System's business is highly competitive.
As a result of very limited load growth throughout the Northeast in the past five years and the operation of several new generating plants, competition has grown, and a seller's market for electricity has turned into a buyer's market. Of the approximately 2,000 - 3,000 megawatts of surplus capacity in New England, the System's total is approximately 1,000 megawatts.
The prices the System has been able to receive for new wholesale contracts have generally been far lower than the prices prevalent in recent years.
Nevertheless, in 1993, the System sold a monthly average of 350 megawatts on a daily and short-term basis and 1,150 megawatts under preexisting long-term commitments of capacity to over 20 utilities throughout the Northeast. These sales resulted in approximately $150 million of capacity revenues. The majority of these revenues have been recognized in System company base rates.
In addition, System companies entered into approximately 11 long- term sales contracts in 1993 with both new and existing customers. These contracts are expected to increase sales by a yearly average of 60 megawatts from late 1993 through 2005. The new wholesale customers include the municipal electric systems in Georgetown, Middletown, South Hadley, Princeton, Danvers, Littleton and Mansfield, all in Massachusetts. Including these new sales, the System currently has capacity sales commitments with other New England utilities to sell an aggregate 4,000 megawatt-years of capacity from 1994 through 2008. The net benefits after costs from these sales are estimated at approximately $550 million over the remaining life of the contracts. Most of these benefits will be realized over the next few years. In addition, a contract for the sale of approximately 450 megawatt- years to the municipal electric system in Madison, Maine has been signed and is awaiting certain approvals. For information on competitive pressures affecting wholesale transmission, see "Electric Operations - Generation and Transmission."
Over the next five years, intense competition in the Northeast market is expected to continue as new generating facilities, located for the most part outside the System's retail service areas and contracted to sell to others, become operational. See "Regulatory and Environmental Matters - Public Utility Regulation." This increase in power supply sources could put further downward pressure on prices, but the potential price decreases may be somewhat offset by an improvement in the region's economy and the retirement of a number of the region's existing generating plants. See "Electric Operations - Generation and Transmission."
SUMMARY
To date, the System has not been materially affected by competition, and it does not foresee substantial adverse effect in the near future unless the current regulatory structure or practice is substantially altered. The rate, service, business development and conservation initiatives described above, portions of which are funded in base rates, plus other cost containment efforts described below, have been adequate to date in retaining customers, preventing fuel switching and attracting new customers at a level sufficient to maintain the System's revenue and profit base and should have significant positive effects in the next few years. As noted above, however, the DPUC has begun a retail wheeling investigation in Connecticut, and its outcome is uncertain at this time. In Massachusetts, retail wheeling legislation is under consideration. To date, no such initiatives are underway in New Hampshire. NU's subsidiaries benefit from a diverse retail base, and the System has no significant dependance on any one customer or industry. The System's extensive transmission facilities and diversified generating capacity position it to be a strong factor in the regional wholesale power market for the foreseeable future. The System's wholesale power business should further cushion the financial effects of competitive inroads within its service area. The System believes that the corporate reengineering process initiated in early 1994 and structural reorganization effective January 1, 1994 should better position it to compete in the retail and wholesale electric businesses in the future.
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, which has 150 days to act upon a proposed rate increase, with one 30-day extension possible. If the DPUC does not act within that period, the proposed rates may be put into effect subject to refund.
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.
1992-1993 CL&P RETAIL RATE CASE
In December 1992, CL&P filed an application for rate relief with the DPUC. The updated request sought to increase CL&P's revenues by $344 million or 15.4 percent in total over three years. That increase incorporated requested annual increases of $130 million, $104 million and $110 million starting in May 1993. As an alternative to the multi-year plan, CL&P also proposed a one-time increase totaling about $280 million, or 13.9 percent.
On June 16, 1993, the DPUC issued a decision (Decision) approving the multi-year plan and providing for annual 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 total increase granted of $141.3 million, or 6.11 percent, is approximately 42 percent of CL&P's updated request.
In light of the State of Connecticut's concern over economic development and industrial and commercial rates, one important aspect of the Decision was that industrial and manufacturing rates will rise only about 1.1 percent anually over the three-year period.
Other significant aspects of the Decision include the reduction of CL&P's return on equity (ROE) from 12.9 percent (CL&P had sought to continue its ROE at that level) to 11.5 percent for the first year of the multi-year plan, 11.6 percent for the second year and 11.7 percent for the third year; recognition in CL&P's rates, by 1998, of non-pension, post-retirement benefit cost accruals required under Statement of Financial Accounting Standards (SFAS) No. 106; the identification of $49 million of prior fuel overrecoveries and the use of that amount to offset a similar amount of the unrecovered balance in CL&P's generation utilization adjustment clause (GUAC); the reduction of CL&P's projected operating and maintenance expense for contingency funding by approximately $53.6 million spread over three years; and the deferral of cogeneration expenses projected for 1994 and 1995 and the future recovery of those deferred amounts (approximately $63 million in total) plus carrying costs over five years beginning July 1, 1996.
The Decision also required CL&P to allocate to customers $10 million of after tax earnings from a $47.7 million property tax accounting change made in the first quarter of 1993. CL&P recorded this $10 million adjustment as a reduction to second quarter net income.
On August 2, 1993, two appeals were filed from the Decision. CL&P filed an appeal on four issues. The second appeal was filed by the Connecticut Office of Consumer Counsel (OCC) and the City of Hartford, challenging the legality of the multi-year plan approved by the DPUC. The two appeals were consolidated. CL&P moved to dismiss the appeal by the City of Hartford and the OCC on jurisdictional grounds. Oral arguments were held on October 15, 1993 and February 14, 1994 on CL&P's motion to dismiss the appeals challenging the multi-year rate plan. It is not known when a decision on CL&P's motion will be issued. In addition, the Court rejected (without prejudice to renewal) the City of Hartford's and the OCC's motion to stay implementation of the second and third year of the rate plan pending the outcome of their appeal. The City of Hartford and the OCC could renew a request for a stay following the outcome of their appeal.
CL&P ADJUSTMENT CLAUSES
CL&P has a fossil fuel adjustment clause and a GUAC applicable to its retail electric rates. In Connecticut, the DPUC is required to approve each month the charges or credits proposed for the following month under the fossil fuel adjustment clause. These charges and credits are designed to recover or refund changes in purchased power (energy) and fossil fuel prices from those set in base rates. Monthly fossil fuel charges or credits are also subject to review and appropriate adjustment by the DPUC each quarter after full public hearings. The Connecticut clause allows CL&P to recover substantially all prudently incurred fossil fuel expenses.
CL&P's current retail electric base rate schedules assume that the nuclear units in which CL&P has entitlements will operate at a 72 percent composite capacity factor. The GUAC levels the effect on rates of fuel costs incurred or avoided due to variations in nuclear generation above and below that performance level. 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 a twelve-month period ending July 31 of each year, with DPUC approval, these net variations from the costs reflected in base rates are generally refunded to or collected from customers over the subsequent eleven-month period beginning September 1. This clause, however, does not permit automatic collection from customers to the extent the capacity factor is less than 55 percent for the twelve-month period. When and to the extent the annual nuclear capacity factor is less than 55 percent, it is necessary for CL&P to apply to the DPUC for permission to recover the additional fuel expense.
In the Decision, the DPUC disallowed recovery of $41.5 million, the GUAC deferral balance associated with operation at a nuclear capacity factor below 55 percent during the 12-month GUAC period ending July 31, 1992. In the same Decision, the DPUC also disallowed $7.5 million of the $96 million deferral balance, representing operation at a nuclear capacity factor above 55 percent for that period, which had already been approved for collection from customers through December 31, 1993. The reason given for the disallowances was CL&P's $49 million overrecovery of fuel costs through base rates and the fuel adjustment clauses for the period August 1991 to July 1992.
The Decision also cut short the previously allowed recovery of $96 million in GUAC deferrals by four months. The DPUC ordered the remaining unrecovered GUAC balance of $24.6 million to be "trued-up" against the deferral for the 1992-93 GUAC year. As result of two previous prudence decisions imposing disallowances for outages at the nuclear unit (CY) operated by the Connecticut Yankee Atomic Power Company (CYAPC) and Millstone I, the DPUC also ordered CL&P to refund to customers a total of $5.1 million in the GUAC billing period beginning September 1, 1993.
In the most recent GUAC period, which ended July 31, 1993, the actual level of nuclear generating performance was 72.6 percent, resulting in a GUAC deferral of $4.0 million to be credited to customers beginning in September 1993. The GUAC rate filed by CL&P for the September 1993 - August 1994 GUAC billing period had five components: the $7.5 million disallowance from the rate case, the $5.1 million of prudence disallowances, the $4.0 million credit deferral for the most recent GUAC period, and the $24.6 million debit of previously unrecovered GUAC deferrals, for a total of $7.9 million.
On September 1, 1993, the DPUC issued an interim order setting a GUAC rate of zero beginning September 1, 1993, subject to a proceeding to consider further CL&P's GUAC rate for the period September 1, 1993 to July 31, 1994. On January 5, 1994, the DPUC issued a decision fixing the GUAC rate at zero through August 31, 1994 and disallowing recovery of $7.9 million through the GUAC. The disallowance was based on a comparison of fuel revenues with fuel expenses, in the August 1992 - July 1993 period. On January 24, 1994, CL&P requested the DPUC to clarify its January 5, 1994 decision with respect to future application of the GUAC. Based on management's interpretation of the January 5, 1994 decision, CL&P does not expect that any future DPUC review using this methodology will have a material adverse impact on its future earnings. On March 4, 1994, CL&P appealed the January 5 GUAC decision to Connecticut Superior Court.
For the 1984-1991 GUAC periods, CL&P refunded more than $112 million to its customers through the GUAC mechanism. For the five months ended December 31, 1993, the composite nuclear generation capacity factor was 66.7 percent. For the full twelve-month period ending July 31, 1994, the factor is projected to be approximately 74.7 percent.
The DPUC has opened a docket to review the prudence of the 1992 outage related to the Millstone 2 steam generator replacement project. Discovery and filing of testimony is expected to continue through May 1994 and hearings, if required, will be held in the summer of 1994.
CL&P incurred approximately $88 million in replacement power costs associated with Millstone outages that occurred during the period October 1990 - February 1992. These outages were the subject of several separate prudence reviews conducted by the DPUC, three of which are either on appeal or still pending at the DPUC.
On May 19, 1993, the DPUC issued a final decision allowing recovery of costs related to the July 1991 shutdown of Millstone 3 caused by mussel- fouling of the heat exchangers. Approximately $0.9 million of replacement power costs are at issue. The OCC has appealed that decision to the Connecticut Superior Court.
On September 1, 1993, the DPUC issued a final decision in the prudence investigation of outages at all four Connecticut nuclear plants resulting from an erosion/corrosion-induced pipe rupture at Millstone 2 on November 6, 1991. The decision concluded that CL&P's management of its erosion/corrosion program was reasonable and prudent and that expenses incurred as a result of the outages, which total approximately $65 million ($51 million of which represents replacement power costs) for CL&P, should be allowed. The OCC has also appealed this decision to the Connecticut Superior Court.
The third ongoing prudence investigation involves a Millstone 3 outage caused by repairs to the service water piping in the fall of 1991. The OCC's witness filed testimony that, as a result of the DPUC's decision finding that the concurrent mussel-fouling outage was prudent, and the fact that the mussel-fouling outage continued at least as long as the service water outage, there was no economic impact on ratepayers from the service water outage. On September 23, 1993, the DPUC suspended the service water docket pending the outcome of OCC's appeal of the decision on the mussel- fouling outage. Approximately $26 million of replacement power costs are at issue. For further information on the shutdowns of Millstone units currently under review by the DPUC, see "Electric Operations -- Nuclear Generation -- Millstone Units."
Some portion of the replacement power costs reflected in the three Millstone outages, as to which the DPUC has not completed its review or as to which the DPUC's decision has been appealed, may be disallowed. However, management believes that its actions with respect to these outages have been prudent, and it does not expect the outcome of the prudence reviews to result in material disallowances.
CL&P has recognized that it will not recover in rates approximately $9.4 million in replacement power costs resulting from two other shutdowns at Millstone 1: one related to the unit's licensed operators failing requalification exams and the other related to seaweed blockage at the intake structure.
CL&P owns 34.5 percent of the common stock of CYAPC, a regional nuclear generating company. During the 1987-1988 refueling outage, repairs were made to CY's thermal shield. During an extended 1989-1990 refueling outage, the thermal shield was removed due to continued degradation.
The DPUC reviewed these outages. In a report issued in 1990, the DPUC's auditors concluded that the actions of CYAPC's personnel and its contractors were reasonable with respect to the thermal shield's repair and removal. However, the auditors also concluded that the failure to clean the entire refueling cavity during the 1987-1988 outage was the most likely cause of debris left in the cavity that subsequently resulted in the additional damage that was repaired during the 1989-1990 outage.
In October 1992, the DPUC disallowed CL&P's recovery of $3 million in replacement power costs and $230,000 of related operating and maintenance costs resulting from CY's 1989-1990 extended outage. CL&P appealed the DPUC's decision. On December 2, 1993, the Connecticut Superior Court issued a decision reversing the DPUC, in part, and upholding it in part. The court ruled in favor of CL&P by reversing the $230,000 disallowance and in favor of the DPUC by upholding the $3 million disallowance of replacement power costs.
The partial reversal in favor of CL&P was based on the principle of federal preemption and is an important legal precedent for future CYAPC matters.
CONSERVATION AND LOAD MANAGEMENT
CL&P participates in a collaborative process for the development and implementation of C&LM programs for its residential, commercial and industrial customers.
In September 1992, the DPUC approved a Conservation Adjustment Mechanism (CAM) that allows CL&P to recover C&LM costs to the extent not recovered through current base rates. The CAM authorized continued recovery of C&LM costs over a ten-year period with a return on the unrecovered costs. In December 1992, CL&P filed an application with the DPUC for approval of budgeted C&LM expenditures for 1993 of $47.5 million and a proposed CAM for 1993. On April 14, 1993, the DPUC issued an order approving a new CAM rate, which allows CL&P to recover $24 million of its budgeted $47 million C&LM expenditures during 1993 and associated true-ups of past C&LM expenditures. The order also provided that any unrecovered expenditures would be recovered over eight years. CL&P's actual 1993 C&LM expenditures were approximately $42.8 million. The unrecovered C&LM costs at December 31, 1993 excluding carrying costs were $116.2 million.
On December 30, 1993, CL&P and the other participants in the collaborative process filed an offer of settlement with the DPUC regarding CL&P's 1994 C&LM expenditures, program designs, performance incentive and lost fixed cost revenue recovery. The settlement proposed a budget level of $39 million for 1994 C&LM and a reduction in the amortization period for new expenditures from eight to 3.85 years. CL&P expects additional 1994 C&LM expenditures of approximately $1 million for state facilities. The DPUC began hearings on the proposed settlement during March 1994.
NEW HAMPSHIRE RETAIL RATES
RATE AGREEMENT AND FPPAC
NU acquired PSNH, the largest electric utility in New Hampshire, in June 1992. See "The Northeast Utilities System." PSNH's 1989 Rate Agreement (Rate Agreement) provides the financial basis for the plan under which PSNH was reorganized and became an NU subsidiary. The Rate Agreement sets out a comprehensive plan of retail rates for PSNH, providing for seven base rate increases of 5.5 percent per year and a comprehensive fuel and purchased power adjustment clause (FPPAC). The first of these base retail rate increases was put into effect in January 1990. The second rate increase took place on May 16, 1991, when PSNH reorganized as an interim, stand-alone company; the third rate increase occurred on June 1, 1992, just before NU's acquisition of PSNH; and the fourth rate increase went into effect on June 1, 1993. The remaining three increases are to be placed in effect by the NHPUC annually beginning June 1, 1994, concurrently with a semi-annual adjustment in the FPPAC.
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 PSNH's non-Seabrook assets and the value assigned to Seabrook. In accordance with the Rate Agreement, approximately $265 million of the remaining regulatory asset is scheduled to be amortized and recovered through rates by 1998, and the remaining amount, approximately $504 million, is scheduled to be amortized and recovered through rates by 2011. PSNH is entitled to a return each year on the unamortized portion of the asset. The unrecovered balance of the regulatory asset at December 31, 1993 was approximately $769.5 million. In order to provide protection from significant variations from the costs assumed in the base rates over the period of the seven base rate increases (Fixed Rate Period), the Rate Agreement established a return on equity (ROE) collar to prevent PSNH from earning an ROE in excess of an upper limit or below a lower limit. To date, PSNH's ROE has been within the limits of the ROE collar.
The FPPAC provides for the recovery or refund by PSNH, for the ten- year period beginning on May 16, 1991, of the difference between the actual prudent energy and purchased power costs and the costs included in base rates. The rate is calculated for a six-month period based on forecasted data and is reconciled to actual data in subsequent FPPAC billing periods. PSNH costs included in the FPPAC calculation are the cost of fuel used at its generating plants and purchased power, energy savings and support payments associated with PSNH's participation in the Hydro-Quebec arrangements, the Seabrook Power Contract costs billed to PSNH from NAEC, NEPOOL Interchange expense and savings, fifty percent of the joint dispatch energy expense savings resulting from the combination of PSNH and the System companies as a single pool participant, purchased capacity costs associated with other System power and unit contract capacity purchases excluding the Yankee nuclear companies and the cost to amortize capital expenditures for, and to operate, environmental or safety backfits or fuel switching. The FPPAC also provides for the recovery of a portion of the payments made currently to qualifying facilities and a portion of the costs associated with the PSNH buyback of the New Hampshire Electric Cooperative, Inc. (NHEC) entitlement in Seabrook. For information on NHEC's 1991 filing for bankruptcy and its subsequent reorganization, see "Rates - Wholesale Rates." The balance of the current payments to qualifying facilities, representing a part of the payments made currently to eight specific small power producers (SPPs), are deferred each year and amortized and recovered over the succeeding ten years.
A portion of the current payments to NHEC is also deferred and will be recovered either through the FPPAC during the fixed rate period or through base rates after the fixed rate period. Recovery of the NHEC deferral through the FPPAC occurs only if the FPPAC rate is negative; in such instance, deferred NHEC costs would be recovered to the extent required to bring the FPPAC rate to zero. From June to November 1992, the FPPAC rate, which would otherwise have been negative, was set at zero, and some NHEC deferrals were amortized. The operation of the FPPAC during this period resulted in an overrecovery, which was also netted against NHEC deferrals in December 1992 and March 1993. As of December 31, 1993, SPP and NHEC deferrals totaled approximately $107.6 and $14.8 million, respectively.
Under the Rate Agreement, PSNH has an obligation to use its best efforts to renegotiate the purchase power arrangements with 13 specified SPPs that were selling their output to PSNH under long term rate orders. Agreements have been reached with all five of the hydroelectric facilities under which the rates PSNH pays for their output would be reduced but the term of years for sales from the hydro producers would be extended by five years. The NHPUC held a hearing concerning these agreements on February 25, 1994. PSNH has also reached agreements with three of the eight wood-fired qualifying facilities with long term rate orders. Under each agreement, PSNH would pay each operator a lump sum in exchange for canceling the operator's right to sell its output to PSNH under rate orders. The total payment to the three operators would be approximately $91.8 million (covering approximately 35 MW of capacity). The three wood operators' agreements will be considered in hearings before the NHPUC in late spring 1994. PSNH is unable to predict if any or all of these agreements will be consummated.
Although the Rate Agreement provides an unusually high degree of certainty about PSNH's future retail rates, it also entails a risk if sales are lower than anticipated, as they were in 1991 and 1992, or if PSNH should experience unexpected increases in its costs other than those for fuel and purchased power, since PSNH has agreed that it will not seek additional rate relief before 1997, except in limited circumstances. Even if allowed under the Rate Agreement, any additional increases above 5.5 percent per year are subject to political and economic pressures that tend to limit overall retail rate increases, including FPPAC increases.
In accordance with the Rate Agreement, PSNH increased its average retail electric rates by about 4.5 percent in June 1993 and by 1.8 percent on December 1, 1993. The 4.5 percent increase in June resulted from the combined effect of decreasing to $.00110 per kilowatthour the FPPAC charge at the same time that (1) the fourth of the seven increases in base electric rates of 5.5 percent and (2) a temporary increase associated with recently enacted legislation associated with the settlement of the Seabrook tax suit described below took effect. The decrease in the FPPAC charge also reflected lower costs paid by PSNH through the Seabrook Power Contract for Seabrook property tax imposed on NAEC. The December 1993 increase resulted from an increase in the FPPAC rate.
In its decision on the June 1, 1993 increase, the NHPUC disallowed replacement power costs for three Seabrook outages totalling about $0.4 million. On August 16, 1993, the NHPUC affirmed its decision to disallow that amount. In the August 16 decision, the NHPUC also rejected a request by the New Hampshire Office of Consumer Advocate (OCA) to allow access to certain confidential, self-critical documents generated at Seabrook station by plant personnel following outages and power reductions. PSNH has been providing summary analyses of the circumstances surrounding outages; however, it declined to provide the original self-critical documents in an effort to maintain an atmosphere in which employees would be encouraged to report and comment on all possible problems. The OCA filed an appeal of the NHPUC's decision on its request for access to these documents with the New Hampshire Supreme Court on November 16, 1993. On February 8, 1994, the court accepted the appeal.
On September 14, 1993, PSNH filed a request for an increase in its FPPAC rate for the period December 1, 1993 through May 31, 1994. The increase of one percent of the average retail rate was expected to produce less than the revenues necessary to cover PSNH's FPPAC costs over these six months, a period during which Seabrook will undergo a two-month refueling outage. PSNH waived its right to immediate collection and proposed to defer about $13 million of FPPAC costs for later collection in order to limit its total rate increases for 1993 to 5.5 percent. Hearings on the FPPAC rate request were held on November 9 and 10, 1993. On November 29, 1993, the NHPUC approved a higher FPPAC rate than the rate requested by PSNH. The increase was 1.8 percent higher than rates previously in effect and allowed PSNH to recover a deferral of $10.5 million over a twelve month period beginning June 1, 1994, which ends prior to the next scheduled Seabrook refueling outage.
In its June 1992 decision concerning PSNH's FPPAC rate, the NHPUC had determined that PSNH should not be entitled to recover approximately $1.3 million with respect to wholesale power agreements with two New England utilities. Also, the NHPUC had questioned the prudence of a series of short term contractual agreements (SWAP Agreements) for energy and capacity exchanges entered into between the System and PSNH prior to the merger and the allocation of savings resulting from the SWAP Agreements. In November 1992, PSNH entered into proposed settlements with the NHPUC staff and the OCA to settle these issues. The settlements proposed disallowances of approximately $500,000 for the two wholesale power agreements and $250,000 for the SWAP Agreements. On March 23, 1993, the NHPUC approved the settlements.
SETTLEMENT OF THE SEABROOK TAX SUIT
On April 16, 1993, the Governor of New Hampshire signed into law legislation that implemented the settlement of a suit concerning property tax on Seabrook station (the Seabrook Tax) that was filed with the United States Supreme Court by Attorneys General of Connecticut, Massachusetts and Rhode Island. The legislation made various changes to New Hampshire tax laws, resulting in taxes of approximately $5.8 million to be paid by NU on a consolidated basis in each of 1993 and 1994 and $3.0 million in 1995, a reduction from the $9.5 million paid by NU on a consolidated basis in 1992. Of such amounts to be paid, CL&P's portion will be approximately $0.6 million in each of 1993 and 1994 and approximately $0.3 million in 1995 and NAEC's portion will be approximately $5.2 million in each of 1993 and 1994 and approximately $2.7 million in 1995.
MEMORANDUM OF UNDERSTANDING
On May 6, 1993, PSNH, NAEC, NUSCO and the Attorney General of the State of New Hampshire entered into a Memorandum of Understanding (Memorandum) relating to certain issues which had arisen under the Rate Agreement. In part, the issues addressed relate to the enactment of the legislation implementing the settlement of the Seabrook Tax lawsuit. Pursuant to the Memorandum, tax changes imposed by the legislation will not increase PSNH's overall ratepayer charges, but will be reflected in PSNH rates pursuant to the Rate Agreement through offsetting adjustments to PSNH's base rates and FPPAC charges. On June 1, 1993, PSNH put into effect a temporary increase of $0.00074 per kilowatthour in base rates designed to recover the increased costs associated with the enactment of the legislation.
A corresponding decrease in the FPPAC costs collected after June 1, 1993 offset the base rate increase. The FPPAC decrease reflected the reduction of the Seabrook property tax resulting from the legislation.
The Memorandum also addresses the implementation of new accounting standards imposed by SFAS 106 and SFAS 109. The Memorandum establishes the method of accounting under SFAS 106 for employees' post-retirement benefits other than pensions for PSNH ratemaking purposes. Under SFAS 109, companies may recognize as a deferred tax asset the value of certain tax attributes. The Memorandum provides for the establishment of a regulatory liability attributable to significant net operating loss carryforwards and establishes that such liability should be amortized over a six-year period beginning on May 1, 1993.
Other provisions of the Memorandum cover:
NAEC's acquisition of the Vermont Electric Generation and Transmission Cooperative's (VEG&T) 0.41259% interest in Seabrook for approximately $6.4 million and NAEC's sale of the output to PSNH. All necessary regulatory approvals for NAEC's acquisition have been received and NAEC acquired VEG&T's interest on February 15, 1994. The Rate Agreement will be amended to ensure that this acquisition will not impact PSNH rates during the fixed rate period.
The Rate Agreement's ROE collar floor provisions were amended to provide for the adjustment by PSNH of its revenue received from James River Corporation and Wausau Papers of New Hampshire by the amount of the demand charge discount previously approved by the NHPUC.
The Rate Agreement was also amended to provide that any adjustments to the amount of PSNH's liability under the Seabrook Power Contract to reimburse NAEC for payments to the Seabrook Nuclear Decommissioning Financing Fund (a fund administered by the State of New Hampshire to finance decommissioning of Seabrook) will be recovered through adjustments to PSNH's base rates; however, such adjustments will not be subject to the annual 5.5 percent increases established under the Rate Agreement. See "Electric Operations - Nuclear Generation - Decommissioning" for further information on decommissioning costs for Seabrook station and other nuclear units that the System owns or participates in.
On May 11, 1993, PSNH and the State of New Hampshire filed a petition with the NHPUC seeking approval of the Memorandum. As required for implementation, PSNH's lenders approved the Memorandum. The NHPUC hearing on the petition seeking approval of the Memorandum and a request to make the June 1, 1993, temporary base rate increase permanent was held on December 2, 1993. PSNH entered into a stipulation with the NHPUC staff and the OCA which modified the Memorandum slightly, clarifying terms of the NAEC power contract applicable to the VEG&T interest in Seabrook. The NHPUC approved the Memorandum as modified by the stipulation, the permanent base rate increase and the Third Amendment to the Rate Agreement on January 3, 1994.
As a result of the approval of the Memorandum, PSNH's earnings in 1993 increased by $10 million. The cumulative impact of the issues resolved by the Memorandum is not expected to have a significant impact on PSNH's future earnings.
SEABROOK POWER CONTRACT
PSNH and NAEC entered into the Seabrook Power Contract (Contract) on June 5, 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-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.
If Seabrook 1 is retired prior to the expiration of the Nuclear Regulatory Commission (NRC) operating license term, NAEC will continue to be entitled under the Contract to recover its remaining Seabrook investment and a return of that investment and its other Seabrook-related costs for 39 years, less the period during which Seabrook 1 has operated. At December 31, 1993, NAEC's net utility plant investment in Seabrook 1 was $732 million.
The Contract provides that NAEC's return on its "allowed investment" in Seabrook 1 (its investment in working capital, fuel, capital additions after the date of commercial operation of Seabrook 1 and a portion of the initial investment) is calculated based on NAEC's actual capitalization from time to time over the term of the Contract, 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" was 20 percent for the twelve months commencing May 16, 1991, increasing by 20 percent in the second year and by 15 percent in each of the next four years, resulting in 100 percent in the sixth and each succeeding year. As of December 31, 1993, 55 percent of the 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 will be recovered, together with a return on it, beginning in the first year after PSNH's Fixed Rate Period, and will be fully recovered prior to the tenth anniversary of PSNH's reorganization date.
Effective February 15, 1994, NAEC also owns the 0.41259% share of capacity and output of Seabrook it purchased from VEG&T. NAEC sells that share to PSNH under an agreement that has been approved by FERC and is substantially similar to the Contract; however, the agreement does not provide for a phase-in of allowed investment and associated deferrals of capital recovery.
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. Massachusetts law allows the DPU to suspend a proposed rate increase for up to six months. If the DPU does not act within the suspension period, the proposed rates may be put into effect.
Under present rate-making standards, the DPU allows few adjustments to historic test year expenses to reflect the conditions anticipated by a company during the first year amended rate schedules are to be in effect. The principal adjustments that are permitted are inflation adjustments to historic test year non-fuel operation and maintenance expenses. Rate base is based on test year-end levels, and capital structure is based on test year-end levels adjusted for known and measurable changes. Current DPU practices permit WMECO to normalize most income tax timing differences.
In Holyoke, Massachusetts, where HWP and Holyoke Gas and Electric Department, a municipal utility, operate side-by-side, approximately 30 HWP industrial customers sought bids as a group in 1993 for future electric service. HWP retained the load and has a 10-year contract, at substantially lower rates than in the past, to supply the group.
WMECO REGULATORY ACTIVITY
In December 1991, WMECO filed an application with the DPU for a retail rate increase of approximately $36 million or 9.1 percent. In April 1992, WMECO and the Massachusetts Attorney General filed a partial settlement agreement for approval by the DPU. Also in April 1992, a settlement agreement on WMECO's C&LM program budget was filed with the DPU jointly by WMECO, the Massachusetts Attorney General, Massachusetts Division of Energy Resources (DOER), the Conservation Law Foundation, Inc. (CLF) and the DPU's Settlement Intervention Staff. The settlement agreement covered WMECO's C&LM program through 1993 and included an annual budget of $17 million for both years. The parties also agreed that all expenditures and other charges relating to C&LM would be collected through a conservation charge (CC).
In May 1992, the DPU accepted the WMECO retail rate case and the C&LM settlement agreements. As a result, WMECO's annual retail rates increased by $12 million, or three percent, on July 1, 1992, and by a further $11 million, or 2.7 percent, on July 1, 1993. In June 1992, the DPU resolved the remaining issues in the rate case filed in December 1991, when it issued an order on WMECO's rate design. The DPU order required the first and second year base revenue increases to be allocated so that all classes contribute the same percentage increase.
In July 1992, the DPU approved an amended settlement agreement for 1992 and 1993 C&LM programs that established a CC that promoted rate stability by spreading the costs and subsequent recovery of 1992 and 1993 C&LM programs over the 18-month period from July 1, 1992 through December 31, 1993. The CC includes incremental C&LM program costs above or below base rate recovery levels, C&LM fixed cost recovery adjustments, and the provision for a C&LM incentive mechanism. In January 1993, WMECO filed with the DPU a request to reduce the CC rate by an aggregate of $3 million in 1993. On February 5, 1993, the DPU directed WMECO to file a revised CC to be effective on March 1, 1993 based on actual 1992 expenditures and the preapproved 1993 budget. The DPU approved the new CC on February 26, 1993. A motion for reconsideration was filed by certain of the parties to the original settlement. The DPU rejected that motion on July 9, 1993. WMECO filed for approval of a new CC on February 2, 1994. The DPU held a hearing on the proposed new CC on February 18, 1994.
In October 1992, the DPU approved an Integrated Resource Management (IRM) settlement agreement that had been proposed by WMECO, the Attorney General, CLF, DOER and the Massachusetts Public Interest Research Group (MASSPIRG) concerning WMECO's IRM. The settlement required WMECO to submit its C&LM programs for 1994, 1995 and a portion of 1996 for approval by the DPU prior to October 1993, and to file its next IRM draft initial filing on January 3, 1994. The settlement also requires WMECO to prepare a competitive resource solicitation at least six months before its C&LM filing for any new C&LM programs it proposes.
On March 16, 1993 WMECO filed a motion with the DPU to request authority to eliminate the separate (and higher) rates for residential electric heating customers by placing those customers on the same rates as the residential non-electric heating customers. WMECO proposed this change in order to be more competitive and to stem its losses of electric heating customers. On April 30, 1993, the DPU denied WMECO's request to eliminate the separate rates for residential electric heating customers but reduced the customer and energy charges for the electric heating customers to equal the comparable charges for non-electric heating customers.
In November 1993, WMECO submitted its C&LM filing required in the settlement of the IRM proceeding, along with a settlement offer from WMECO, the Attorney General, DOER, CLF and MASSPIRG. The settlement offer incorporated preapproved C&LM funding levels for 1994 and 1995 of $14.2 million and $15.8 million, respectively. The settlement also provides for the recovery of lost fixed revenue and a bonus incentive if certain implementation objectives are met. On January 21, 1994, the DPU approved the settlement.
On January 3, 1994, WMECO submitted its next draft initial IRM filing required by the October 1992 settlement to the DPU. The filing indicates the System does not need additional resources until at least the year 2007 and, therefore, WMECO does not intend to issue any solicitation for additional resources anytime in the foreseeable future. WMECO is presently participating in settlement discussions concerning this IRM filing. Should no settlement be reached, WMECO is scheduled to submit its initial IRM filing to the DPU in April 1994.
WMECO ADJUSTMENT CLAUSE
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 of system-wide 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. Goals are established for equivalent availability factor, availability factor, capacity factor, forced outage rate and heat rate. 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.
Currently pending before the DPU are investigations into the performance of WMECO's generating units for the 12-month periods ending May 31, 1992 and May 31, 1993. The DPU held a hearing on February 1, 1994 on WMECO's non-nuclear performance for the 12-month period ending May 31, 1992. Except for the order concerning CYAPC discussed below, the DPU has completed investigations of, but not yet issued decisions reviewing WMECO's actual generating unit performance for the program years between June 1987 and May 1991.
The DPU has consistently set performance goals for generating units that are not wholly-owned and operated by the company whose goals are being set. 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 generating units (the Yankee plants) in which WMECO has minority ownership interests.
The total amount of WMECO retail replacement power costs attributable to the major outages in the 1991 performance year -- the Millstone 3 July 1991 outage (mussel-fouling and service water), the Millstone 1 October 1991 outage (operator requalification examinations) and the November 1991 outages to perform pipe inspections, analysis and repair -- is approximately $17 million. In December 1992, WMECO notified the DPU that it will forego recovery of $1.2 million in replacement power costs associated with the October 1991 Millstone 1 operator requalification examination outage. The total amount of WMECO retail replacement power costs attributable to outages in the 1992-1993 performance year is approximately $17 million. Management believes that some portion of these replacement power costs may be subject to refund upon completion of the DPU's performance program reviews. However, management believes that its actions with respect to these outages have been prudent and does not expect the outcome of the DPU review to have a material adverse impact on WMECO's future earnings.
In September 1992, the DPU issued a partial order pertaining to CY's extended 1989-1990 refueling outage (discussed above), disallowing the recovery of $0.6 million of incremental replacement power costs that could be attributable to the outage. WMECO filed a motion for reconsideration with the DPU in the same month, which motion is pending before the DPU.
WHOLESALE RATES
CL&P currently furnishes firm wholesale electric service to one Connecticut municipal electric system. PSNH serves NHEC, three New Hampshire municipal electric systems and one investor-owned utility in Vermont. HWP and its wholly-owned subsidiary, Holyoke Power and Electric Company, serve one Massachusetts municipal electric system. WMECO serves one New York investor-owned electric utility. The System's 1993 firm wholesale load was approximately 275 megawatts (MW). In 1993, firm wholesale electric service accounted for approximately 2.5 percent of the System's consolidated electric operating revenues (approximately 1.2 percent of CL&P's operating revenue, 6.0 percent of PSNH's operating revenue, 0.1 percent of WMECO's operating revenue and 21.5 percent of HWP's operating revenue).
NHEC, PSNH's largest customer, representing 5.9 percent of its revenues for 1993, filed a petition for reorganization in 1991 under Chapter 11 of the United States Bankruptcy Code. A plan of reorganization for NHEC, which was confirmed by the Bankruptcy Court in March 1992 and became effective on December 1, 1993, resolves a series of disputes between PSNH and NHEC and provides for PSNH to continue to serve NHEC. The contract covering this continued service has been filed with and accepted by FERC.
In addition to firm service, the System engages in numerous other bulk supply transactions that reduce retail customer costs, at rates that are subject to FERC jurisdiction, and it transmits power for other utilities at FERC-regulated rates. See "Electric Operations - Generation and Transmission" for further information on those 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." For a discussion of the effects of competition on the System, see "Competition and Marketing."
RESOURCE PLANS
CONSTRUCTION
The System's construction program expenditures, including allowance for funds used during construction (AFUDC), in the period 1994 through 1998 are estimated to be as follows:
1994 1995 1996 1997 1998 (Millions of Dollars) PRODUCTION CL&P . . . . . $ 60.9 $54.5 $44.3 $41.5 $39.6 PSNH . . . . . 10.5 7.0 13.3 8.7 15.8 WMECO . . . . 17.3 13.5 10.1 9.3 17.4 NAEC . . . . . 8.2 8.5 8.3 7.0 5.8 Other . . . . 16.2 3.0 2.0 0.7 0.5 System Total . 113.1 86.5 78.0 67.2 79.1
SUBSTATIONS AND TRANSMISSION LINES CL&P . . . . . 12.2 9.4 11.6 12.3 14.6 PSNH . . . . . 3.0 6.9 9.9 6.1 6.7 WMECO. . . . . 0.8 0.4 0.5 0.8 1.3 NAEC . . . . . 0.0 0.0 0.0 0.0 0.0 Other . . . . 0.0 0.0 0.0 0.0 0.0 System Total 16.0 16.7 22.0 19.2 22.6
DISTRIBUTION OPERATIONS CL&P . . . . . 76.1 78.8 80.9 84.1 85.5 PSNH . . . . . 22.0 11.7 10.6 14.5 14.2 WMECO. . . . . 17.4 19.3 17.3 17.2 18.7 NAEC . . . . . 0.0 0.0 0.0 0.0 0.0 Other . . . . 0.4 0.2 0.2 0.2 0.2 System Total 115.9 110.0 109.0 116.0 118.6
GENERAL CL&P . . . . . 8.6 8.8 7.2 5.8 5.1 PSNH . . . . . 2.0 3.3 1.9 2.4 2.0 WMECO . . . . 2.0 2.1 1.9 1.5 1.3 NAEC . . . . . 0.0 0.0 0.0 0.0 0.0 Other . . . . 9.9 7.4 7.8 9.8 9.8 System Total 22.5 21.6 18.8 19.5 18.2
TOTAL CONSTRUCTION CL&P . . . . . 157.8 151.5 144.0 143.7 144.8 PSNH . . . . . 37.5 28.9 35.7 31.7 38.7 WMECO . . . . 37.5 35.3 29.8 28.8 38.7 NAEC . . . . . 8.2 8.5 8.3 7.0 5.8 Other . . . . 26.5 10.6 10.0 10.7 10.5 System Total $267.5 $234.8 $227.8 $221.9 $238.5
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 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's integrated demand and supply planning process is the means by which the System periodically updates its long-range resource needs. The current resource plan identifies a need for new resources beginning in 2007.
Because New England and the System have surplus generating capacity and are forecasting low load growth over the next several years, the System has no current plans to construct or to contract for any new generating units. Additional capacity beyond 2007, the projected System year of need, can come from a variety of sources. The design and implementation of new C&LM programs, the timely development of economic, reliable and efficient qualifying cogeneration and small power production facilities (QFs) or independent power producer (IPP) capacity through state-sanctioned resource acquisition processes, economic utility-sponsored generating resources (including the possibility of repowering retired power plants) and purchases from other utilities will all receive consideration in the System's integrated resource planning process.
With respect to demand-side management measures, the System's long- term plans rely, in part, on encouraging additional C&LM by customers. These measures, including installations to date, are projected to lower the System summer peak load in 2007 by over 1000 MW. In addition, System companies have long-term arrangements to purchase the output from QFs and IPPs under federal and state laws, regulations and orders mandating such purchases. CL&P's, PSNH's and WMECO's plans anticipate the development of QFs and IPPs supplying 710 MW of firm capacity by 1995, of which approximately 695 MW was operational in 1993. See "New Hampshire Retail Rates -- Rate Agreement and FPPAC" for information concerning PSNH's efforts to renegotiate its agreements with thirteen QFs.
CL&P and WMECO filed applications with the U.S. Environmental Protection Agency to receive 203 SO2 allowances for C&LM activity as authorized by the Clean Air Act Amendments. See "Regulatory and Environmental Matters - Environmental Regulation - Air Quality Requirements."
The DPUC has issued regulations establishing competitive bidding systems for future purchases by Connecticut electric utilities from QFs and IPPs and from C&LM vendors. The regulations also implement a state law which provides that a utility may seek a premium of between one and five percentage points above its most recently authorized rate of return for each multi-year C&LM program requiring capital investment by the utility. In April 1993, CL&P submitted its eighth annual filing to the DPUC on private power production, C&LM, projected avoided costs and related matters. CL&P stated that the
System's existing and committed resources are expected to be sufficient to meet System capacity requirements until 2007, and therefore, CL&P did not solicit new capacity from QFs or C&LM vendors in 1993. In December 1993, the DPUC issued its final decision approving CL&P's avoided cost estimates as filed.
In 1993, regulatory preapproval was obtained for all 1993 C&LM expenditures in each of the three retail jurisdictions. In addition, the DPUC authorized a maximum of 3 percent premium rate of return (after tax) on CL&P C&LM investment in 1993. WMECO is currently projected to earn $1.2 million of incentive (after tax) based on 1993 program savings. See "Rates - Connecticut Retail Rates - Conservation and Load Management" and "Rates - Massachusetts Retail Rates -WMECO Regulatory Activity" for information about rate treatment of C&LM costs.
In 1988, the DPU adopted regulations requiring preapproval of Massachusetts utilities' major investments in electric generating facilities, including life extensions. In 1990, the DPU adopted new IRM regulations, which established procedures by which additional resources are planned, solicited and processed to provide for reliable electric service in a least- cost manner. The regulations provide a mechanism for preapproval (rather than after-the-fact review) of utility plant construction, procurement of non-utility generation (QFs and IPPs), and C&LM programs. The regulations specifically require that environmental externalities be considered in the evaluation of resource alternatives.
In January 1994, WMECO filed its initial draft IRM filing, stating that WMECO's year of need is estimated to be 2007, and that no new capacity need be solicited at this time. WMECO is presently in settlement discussions. See "Rates-Massachusetts Retail Rates - WMECO Regulatory Activity" for further information relating to WMECO C&LM issues.
In 1993, the NHPUC approved a settlement agreement related to PSNH's 1992 least cost planning filing, which defers various planning issues to PSNH's April 1, 1994 filing.
In addition to the contributions from C&LM, QFs and IPPs, the System's long-term resource plan includes consideration of continued operation of certain of the System's fossil generating units beyond their current book retirement dates to the extent that it is economic, and possibly repowering certain of the System's older fossil plants. Continued operation of existing fossil units past their book retirement dates (and replacing certain critically located peaking units if they fail) is expected by 2007 to provide approximately 1,400 MW of resources that would otherwise have been retired. Repowering of some of the System's retired generating plants could make available an additional 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 any additional retirements of the System's existing generating units.
The System companies periodically study the economics of their generating units as part of their overall resource planning process. In 1992, the DPUC ordered CL&P to submit economic analyses of the continued operation of 11 fossil steam units by April 1, 1993, and of Millstone Units 1 and 2 and CY, of which the System companies own 49 percent) by April 1, 1994. In 1993, the DPUC reviewed the continued unit operation (CUO) studies submitted by CL&P for the eleven fossil units in Connecticut and
Massachusetts in its annual review of Integrated Resource Planning. The DPUC concluded that a decision was inappropriate at that time and that it would review the issue again in its management audit of CL&P and in CL&P's 1994 integrated resource planning docket. For Millstone 1 and 2 and CY, the CUO studies are in progress. Preliminary indications are that the operation of the units continues to be economic for customers. Final analyses for CY and the Millstone units will be filed with the DPUC in 1994.
For planning and budgetary purposes, the System assumes that CL&P's Montville Station (497.5 MW) will be deactivated from November 1994 through October 1998. A final decision is expected to be made in 1994. Since reactivation is expected to occur in 1998, the System year of need of 2007 is unaffected. The System year of need of 2007 assumes PSNH's Merrimack 2 continues to operate. However, Merrimack 2's continued operation is in question because Merrimack 2 produces significant NOx emissions. The concern has been raised as to whether the emissions can be lowered to acceptable levels in the short and long term. In 1993, PSNH worked successfully with local, state and federal interests to arrive at a solution for Merrimack 2 NOx compliance by 1995, while deferring a decision on continued unit operation beyond 1999 to the future. For information regarding the agreement concerning NOX emissions at the Merrimack units, see "Regulatory and Environmental Matters - Environmental Regulation - Air Quality Requirements."
See "Regulatory and Environmental Matters -- NRC Nuclear Plant Licensing" 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 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.
FINANCING PROGRAM
1993 FINANCINGS
In January 1993, WMECO issued $60 million in principal amount of 6 7/8 percent first mortgage bonds due in 2000. In July 1993, CL&P issued $200 million and $100 million, respectively, of 5 3/4 percent and 7 1/2 percent first mortgage bonds due in 2000 and 2023, respectively. In December 1993, CL&P issued $125 million of 7 3/8 percent first mortgage bonds due in 2025. The proceeds from the foregoing issues were used to redeem outstanding bonds with interest rates ranging from 8 3/4 percent to 9 3/4 percent.
In October 1993, CL&P issued $80 million of 5.30 percent preferred stock, $50 par value. The proceeds of this issuance, together with $30 million of short-term debt, were used to redeem $110 million of preferred stock with dividend rates ranging from 7.6 percent to 9.1 percent.
In September 1993, the Connecticut Development Authority (CDA) issued, on behalf of CL&P, two tax-exempt variable rate pollution control revenue bonds (PCRBs) in the amounts of $245.5 million and $70 million, respectively. At the same time, the CDA issued, on behalf of WMECO, $53.8 million of tax-exempt variable rate PCRBs. The proceeds of these issues were used to redeem like amounts of tax-exempt PCRBs having less favorable structures. These refinancings will result in savings from the extension of maturities, the redemption of two issues of fixed-rate bonds with proceeds of the issuance of variable-rate bonds, the improved credit ratings of new supporting letter of credit banks and associated administrative savings. In December 1993, the New Hampshire Business Finance Authority (BFA) issued, on behalf of PSNH, $44.8 million of tax-exempt variable rate PCRBs. The proceeds of this issue were used to redeem a like amount of taxable PCRBs. Taxable BFA bonds issued on behalf of PSNH in the amount of $109.2 million are outstanding and may be refinanced with tax-exempt bonds upon the receipt of an allocation of the state's private activity volume allocation.
In January 1993, CL&P, PSNH and WMECO purchased $340 million, $75 million and $52 million, respectively, of three-year variable rate debt caps. The caps were purchased to hedge the interest rate risk of the companies' respective variable rate PCRBs and were sized to approximate each respective company's then-current tax-exempt variable rate PCRB issuances. If the interest rate, based on the J. J. Kenny index, exceeds 4.5 percent (the strike rate), each company will receive payments under the terms of its respective interest rate cap agreement. In June 1993, PSNH purchased a $50 million six-month interest rate cap, a $50 million 12 month cap and a $100 million 18 month cap to hedge its interest rate exposure on its variable rate term note. The six-month and 12 month caps have a strike rate of 4.5 percent and the 18 month cap has a strike rate of 5.0 percent, all based on 90 day LIBOR. These caps were sized to approximate portions of a PSNH term note which has a quarterly sinking fund of $23.5 million.
In February 1993, NU, CL&P, WMECO and the Niantic Bay Fuel Trust (NBFT) began a co-managed commercial paper program with two commercial paper dealers. Prior to this time, each company's commercial paper program was managed by one commercial paper dealer. The co-managed program was implemented to promote competition between commercial paper dealers, to increase the investor universe and to increase the range of maturities available to the issuers. On December 31, 1993, $113.0 million commercial paper was outstanding under these programs.
In December 1993, NNECO issued $25 million of 7.17 percent unsecured amortizing notes maturing in 2019. The proceeds of this issuance are being used to finance the construction of a new building at Millstone station to house various administrative and technical support functions.
FINANCING NUCLEAR FUEL
The System requires nuclear fuel for the three Millstone units and for Seabrook 1. The requirements for the Millstone 1, Millstone 2 and CL&P's and WMECO's share of the Millstone 3 units are financed through a third party trust financing arrangement described below. All nuclear fuel for NAEC's and CL&P's shares of Seabrook 1 and PSNH's share of Millstone 3 is owned and financed directly by the respective companies. For the period 1994 through 1998, NAEC's and CL&P's shares of the cost of nuclear fuel for Seabrook 1 are estimated at $56.8 million and $6.4 million, respectively, excluding AFUDC. For the same period, PSNH's share of the cost of nuclear fuel for Millstone 3 is estimated at $6 million, excluding AFUDC.
In 1982, CL&P and WMECO entered into arrangements under which NBFT owns and finances the nuclear fuel for Millstone 1 and 2 and CL&P's and WMECO's share of the nuclear fuel for Millstone 3. NBFT finances the fuel from the time uranium is acquired, during the off-site processing stages and through its use in the units' reactors. NBFT obtains funds from bank loans, the sale of commercial paper and the sale of intermediate term notes. The fuel is leased to CL&P and WMECO by the trust while it is used in the reactors, and ownership of the fuel is transferred to CL&P and WMECO when it is permanently discharged from the reactors. CL&P and WMECO are severally obligated to make quarterly lease payments, to pay all expenses incurred by NBFT in connection with the fuel and the financing arrangements, to purchase the fuel under certain circumstances and to indemnify all the parties to the transactions.
The trust arrangements presently allow up to $530 million to be financed by NBFT with bank loans and commercial paper (up to $230 million) and with intermediate term notes (up to $300 million). The arrangements with the banks are in effect until February 19, 1996, and can be extended for an additional three years if the parties so agree. On December 31, 1993, NBFT had $80 million of intermediate term notes and $113 million of commercial paper outstanding.
As of December 31, 1993, NBFT's investment in nuclear fuel, net of the fourth quarter 1993 lease payment made on January 31, 1994, for all three Millstone units was $172.1 million, as follows:
Total CL&P WMECO System
(Millions of Dollars)
In process.......... $20.3 $4.7 $25.0 In stock............ 8.0 1.9 9.9 In reactor.......... 111.2 26.0 137.2 Total.......... $139.5 $32.6 $172.1
For the period 1994 through 1998, CL&P and WMECO's share of the cost of nuclear fuel for the three Millstone units that will be acquired through NBFT will be $313.5 million and $73.2 million, respectively, excluding AFUDC.
Nuclear fuel costs and a provision for spent fuel disposal costs are being recovered through rates as the fuel is consumed in reactors.
1994 FINANCING REQUIREMENTS
In addition to financing the construction requirements described under "Resource Plans - Construction," the System companies are obligated to meet $1,373.8 million of long-term debt maturities and cash sinking fund requirements and $76.4 million of preferred stock cash sinking fund requirements in 1994 through 1998. In 1994, long-term debt maturity and cash sinking fund requirements will be $295.3 million, consisting of $182 million of long-term debt maturities and $7 million of debt cash sinking fund requirements to be met by CL&P, $94 million of cash sinking fund requirements to be met by PSNH, $1.5 million of cash sinking funds to be met by WMECO and $10.7 million of cash sinking fund requirements to be met by other subsidiaries. These figures do not include $125 million of long-term debt redeemed by CL&P on January 7, 1994 with the proceeds of its issuance of $125 million mortgage bonds in December 1993. See "Financing Program - 1993 Financings."
See "Electric Operations -- Nuclear Generation -- Operations -- Seabrook" for information on CL&P's commitment to advance funds to cover payments that a 12 percent Seabrook owner might be unable to pay with respect to Seabrook project costs.
The System's aggregate capital requirements for 1994, exclusive of requirements under NBFT, are as follows:
Total CL&P PSNH WMECO NAEC Other System (Millions of Dollars) Construction (including AFUDC)..... $157.8 $37.5 $37.5 $ 8.2 $26.5 $267.5 Nuclear Fuel (excluding AFUDC). (.3) 1.8 (.2) 5.8 - 7.1 Maturities......... 182.0 - - - - 182.0 Cash Sinking Funds. 7.0 94.0 1.5 - 10.7 113.2 Total.......... $346.5 $133.3 $38.8 $14.0 $37.2 $569.8
1994 FINANCING PLANS
The System companies, other than CL&P, currently expect to finance their 1994 requirements through internally generated funds. CL&P may issue up to $200 million of long-term debt, primarily to finance maturing securities. This estimate excludes the nuclear fuel requirements financed through the NBFT. See "Financing Nuclear Fuel" above for information on the NBFT. In addition to financing their 1994 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 February 17, 1994, CL&P issued $140 million in principal amount of 5 1/2 percent first mortgage bonds due in 1999 and $140 million in principal amount of 6 1/2 percent first mortgage bonds due in 2004. The net proceeds were used to redeem higher cost first mortgage bonds.
On March 8, 1994, WMECO contracted to issue $40 million principal amount of 6 1/4 percent first mortgage bonds due in 1999 and $50 million in principal amount of 7 3/4 percent first mortgage bonds due in 2024. The net proceeds will be used to redeem higher cost first mortgage bonds.
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 Public Utility Holding Company Act of 1935 (1935 Act).
The following table shows the amount of short-term borrowings authorized by the SEC for each company and the amounts of outstanding short term debt of those companies at the end of 1993.
Maximum Authorized Short-Term Debt Short-Term Debt Outstanding at 12/31/93* (Millions of Dollars) NU.................. $ 175.0 $ 72.5 CL&P ............... 375.0 96.2 PSNH ............... 125.0 2.5 WMECO............... 75.0 6.0 HWP................. 8.0 - NAEC................ 50.0 - NNECO............... 65.0 - RRR................. 25.0 16.5 Quinnehtuk.......... 8.0 4.3 HEC................. 11.0 2.9 ______ $200.9 _________________ * 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 $173.5 million at December 31, 1993.
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, 1994, 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, 1993, CL&P's charter would permit CL&P to incur an additional $570 million of unsecured debt and WMECO's charter would permit it to incur an additional $141.1 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, 1993, CL&P's common equity ratio was 39.1 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, 1993, NU's common equity ratio was 30.9 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 21 percent of total capitalization (as defined) through June 30, 1994, 23 percent 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 1.5 to 1 for each period of four fiscal quarters ending after June 30, 1993 through June 30, 1994 and 1.75 to 1 thereafter. At December 31, 1993, PSNH's common equity ratio was 28.2 percent and its operating income to interest expense ratio was 2.27 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, WMECO's and PSNH'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.
Beginning with the dividends paid on NU common shares by NU in June 1990, NU's Dividend Reinvestment Plan (DRP) was amended to authorize the dividends and optional cash purchases of participating shareholders to be reinvested in NU common shares purchased either in the open market or directly from NU. NU received approximately $42.4 million in 1991 and approximately $35.6 million in 1992 of new common shareholders' equity from the reinvestment of dividends and voluntary cash investments. No funds have been raised by NU through DRP since August 1992, when management ended direct purchases and caused shares to be purchased for DRP participants in the open market.
As part of the PSNH acquisition in June 1992, NU issued warrants for the purchase of NU common stock at a price of $24 per share. In 1993, NU received $8.3 million from the exercise of these warrants. As of December 31, 1993, warrants for 7,975,516 shares of NU common stock remained unexercised.
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, 1993, 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, PSNH and NAEC did not pay dividends to permit them to build up the common equity portion of their capitalizations. Until PSNH and NAEC can begin to fund a part of NU's dividend requirements, NU expects to fund that portion of its dividend requirements with the proceeds of borrowings.
The supplemental indentures under which CL&P's and WMECO's first mortgage bonds and the indenture under which PSNH's first mortgage bonds have been issued limit the amount of cash dividends and other distributions these subsidiaries can make to NU out of their retained earnings. As of December 31, 1993, CL&P had $210.6 million, WMECO had $26.5 million and PSNH had $60.8 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, 1993, $48.7 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.
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 operating 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 3.7 million (2.5 million in Connecticut, 780,000 in New Hampshire and 450,000 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 1993, CL&P furnished retail electric service to approximately 1.085 million customers in Connecticut, PSNH provided retail electric service to approximately 397,000 customers in New Hampshire and WMECO served approximately 193,000 retail electric customers in Massachusetts. HWP serves approximately 25 customers in a portion of the town of Holyoke, Massachusetts.
The following table shows the sources of 1993 electric revenues based on categories of customers:
CL&P PSNH WMECO NAEC Total System
Residential........... 39% 35% 38% - 39% Commercial............ 33 17 30 - 29 Industrial ........... 14 28 20 - 18 Wholesale* ........... 11 17 8 100% 11 Other ................ 3 3 4 - 3 ____ ____ ____ ____ ____ Total ................ 100% 100% 100% 100% 100%
______________________ * Includes capacity sales.
NAEC's 1993 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, 1993, the all-time maximum demand on the System was 6,191 MW, which occurred on July 8, 1993. At the time of the peak, the System's generating capacity, including capacity purchases, was 8,965 MW. The System was also selling approximately 1,431 MW of capacity to other utilities at that time.
In 1993, System energy requirements were met 62 percent by nuclear units, nine percent by oil burning units, 10 percent by coal burning units, three percent by hydroelectric units, two percent by natural gas burning units and 14 percent by cogenerators and small power producers. By comparison, in 1992 the System's energy requirements were met 48 percent by nuclear units, 24 percent by oil burning units, 10 percent by coal burning units, four percent by hydroelectric units, one percent by natural gas burning units and 13 percent by cogenerators and small power producers. See "Electric Operations-Generation and Transmission" for further information.
The actual changes in kWh sales for the last two years and the forecasted sales growth estimates for the 10-year period 1993 through 2003, in each case exclusive of bulk power sales, for the System, CL&P, PSNH and WMECO are set forth below:
1993 over 1992 over Forecast 1993-2003 (under) 1992 (under) 1991 Compound Rate of Growth
System......... 10.9%(1) 15.3%(1) 1.4% CL&P........... (0.3)% 0.2% 1.3% PSNH........... 1.0% 1.1% 1.7% WMECO....... 0.1% (1.6)% 1.1% ___________________ (1) The percent increase in System 1992 sales over 1991 sales and 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 the 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 kWh 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:
1993 over (under) 1992 1992 over (under) 1991 System ................... 11.8%(1) 19.7%(1) CL&P ..................... 1.2% 3.3% PSNH ..................... (9.3)% 6.7% WMECO .................... 13.5% 9.9%
__________________ (1) System sales percentages reflect the inclusion of PSNH sales beginning in June 1992.
Despite a warmer than normal summer that added to cooling requirements, sales showed negligible growth in 1993. Widespread economic recovery throughout the System's service territory did not occur in 1993, but there were mixed pockets of regional economic growth aided by very favorable interest rates. Curtailments in defense spending continue to affect the Connecticut, New Hampshire and western Massachusetts economies, which are heavily dependent on defense-related industries. Competition in various forms may also adversely affect the projected growth rate of sales over the next ten years. 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 further information on the effect of competition on sales growth rates, see "Marketing and Competition."
The forecasted load growth for the System as a whole is significantly below historic rates in part because of forecasted savings from NU-sponsored C&LM programs, which are designed to minimize operating expenses for System customers and postpone the need for new capacity on the System. The forecasted ten-year growth rate of System sales would be approximately 1.8 percent instead of 1.4 percent if the System did not pursue C&LM savings. See "Resource Plans - Future Needs" for an estimate of the impact of C&LM programs on the System's need for new generating resources and for information about C&LM cost impacts and cost recovery. See "Rates - Connecticut Retail Rates" and "Rates - Massachusetts Retail Rates" for information about rate treatment of C&LM costs.
With the System's generating capacity of 8,268 MW as of January 1, 1994 (including the net of capacity sales to and purchases from other utilities, and approximately 690 MW of capacity to be purchased from QFs and IPPs under existing contracts and contracts under negotiation), the System expects to meet its projected annual peak load growth of 1.3 percent reliably until at least the year 2007.
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. The principal resource changes were Seabrook 1's commercial operation, the full operation of the second phase of the Hydro-Quebec project, and increased availability of power from QF and IPP projects. As a consequence, the competition from capacity-long utilities as sellers and the loss of utilities that are no longer capacity- short as buyers have adversely affected the System companies' efforts to sell additional surplus capacity at the price levels that prevailed in the late 1980s. 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 that are not subject to firm commitments, the System's surplus capacity is expected to be approximately 1,000 MW in 1994.
For further information on the effect of competition on sales of surplus capacity, see "Competition and Marketing."
The System operating companies operate and dispatch their generation as provided in the New England Power Pool (NEPOOL) Agreement. In 1993, the peak demand on the NEPOOL system was 19,570 MW, which occurred in July, above the 1992 peak load of 18,853 MW in January of that year. NEPOOL has projected that there will be an increase in demand in 1994 and estimates that the summer 1994 peak load could reach 19,800 MW. NEPOOL projects that sufficient capacity will be available to meet this anticipated demand.
GENERATION AND TRANSMISSION
The System operating companies and most other New England utilities with electric generating facilities are parties to the NEPOOL Agreement. Under the NEPOOL Agreement, the region's generation and transmission facilities are planned and operated as part of the regional New England bulk power system. 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. Pool dispatch results in substantial purchases and sales of electric energy by pool participants, including the System companies, at prices determined in accordance with the NEPOOL Agreement.
The System operating companies, except PSNH, pool their electric production costs and the costs of their principal transmission facilities under the NUG&T agreement. In addition, a ten-year agreement 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 connection with NU's acquisition of PSNH, the System proposed a comprehensive plan for opening up a transmission corridor between northern and southern New England for use in "wheeling" power of other utilities. The plan was designed to accomplish a level of access to transmission resources of the PSNH and New England Electric System (NEES) systems that could formerly be accomplished only after a series of multilateral negotiations. The plan includes provisions to (i) make 452 MW of long term transmission service available across the PSNH system from Maine to Massachusetts, Rhode Island, Connecticut and Vermont at embedded cost rates, (ii) make 200 MW of long term transmission service available by NEES for those utilities requiring deliveries across NEES's system in order to make use of access to the PSNH system, and (iii) construct new facilities as needed to expand the corridor from Maine to Massachusetts, if the cost of expansion is supported and if regulatory approvals for the expansion are received. Further, NU committed to make access to the combined NU-PSNH transmission system available for third-party wheeling transactions whenever capacity is available, and to expand the system when expansion is feasible. The principal constraints are that NU and PSNH have reserved a priority on the use of their transmission systems to serve the reliability needs of their own native load customers, and the commitment to expand would be subject to obtaining all necessary approvals. This plan became effective in October 1992, subject to the outcome of a hearing ordered by FERC in this proceeding, and the Commission's final decision in the compliance phase of the merger proceeding discussed below. NU and NEES filed offers of settlement in this proceeding in May and June 1993, respectively, and the Presiding Administrative Law Judge certified both settlement offers to the Commission in July 1993. The only contested issue was the refund and surcharge provision that was included in both offers of settlement. The Commission has not yet acted on these settlement offers.
These commitments, and the entire issue of access to the NU and PSNH transmission systems by other utilities and non-utility generators, were the subject of extensive controversy in New England. On January 29, 1992, FERC issued a decision approving the acquisition and allowing NU and PSNH customers to be held harmless if other utilities and non-utility generators need to use the NU-PSNH transmission to buy or sell electricity. In accordance with the January 29 decision, on April 23, 1992 and August 4, 1992, NU made compliance filings, including transmission tariffs implementing the FERC's conditions. All tariffs have been accepted by FERC and were effective as of the merger date. FERC has issued summary determinations (without hearing) and NU has 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.
FERC's approval of NU's acquisition of PSNH was appealed to the United States Court of Appeals for the First Circuit. On May 19, 1993, the First Circuit Court affirmed FERC's decision approving the merger but remanded to FERC one issue brought by NU related to FERC's ability to change the terms of the Seabrook Power Contract. FERC filed for en banc (full court) review by the First Circuit Court on the Seabrook Power Contract issue, which was denied. No petitions for review were filed in the U.S. Supreme Court, therefore, the First Circuit Court's decision is final. FERC has yet to initiate any proceeding on the court's remand, which would address whether FERC could modify the Seabrook Power Contract under a more stringent "public interest standard."
On December 21, 1993, NU filed an appeal in the United States Court of Appeals for the District of Columbia Circuit of a FERC order directing NU to put itself on its own transmission tariffs in connection with all NU sales of wholesale power. NU had committed, as part of the PSNH merger, to place itself on its tariff when it was competing with other wholesale power suppliers to make a sale in order to "level the playing field." In its order, FERC expanded NU's merger commitment to include all transactions, regardless of whether or not NU's competitors need to use the NU transmission system.
The controversy about the terms on which wheeling transactions are to be effected in New England has stimulated a series of negotiations among utilities, regulators and non-utility generators, directed at the possible development of new regional transmission arrangements. While an original draft regional transmission arrangement was not supported by all parties, there have been negotiations on a less comprehensive arrangement. Any arrangement would be subject to approval by NEPOOL members and FERC.
HYDRO-QUEBEC
Along with other New England utility companies, CL&P, PSNH, WMECO and HWP is each a participant in agreements to finance, construct, and operate the United States portion of direct current transmission circuits between New England and Quebec, Canada. The project was built in two phases, and now provides 2,000 MW of rated transfer capacity with Canadian facilities constructed and owned by Hydro-Quebec, a Canadian utility system. Phase 1, which entered into commercial operation in 1986, initially provided 690 MW of North-South transfer capacity. In Phase 2, the transmission line was extended to a new converter station in eastern Massachusetts. Phase 2 entered into full operation in 1991. The actual transfers over the interconnection to date have averaged in the 1,400 to 1,800 MW range.
The interconnection permits a reduction in oil consumption in New England and has the potential to produce cost savings to customers through the purchase of power from Hydro-Quebec's hydroelectric generating facilities. The interconnection also reduces the level of reserves New England utilities must carry to assure that pool reliability criteria are met.
The System companies are obligated to pay 34.22 percent of the annual costs of the Phase 1 facilities and 32.78 percent of the annual cost of the Phase 2 facilities. They are entitled, on the basis of a composite of these percentages, to use the capacity of the facilities for their own transactions and to share in the savings from pool energy transactions with Hydro-Quebec. The Phase 1 total project cost was $141 million and the Phase 2 total project cost was approximately $495 million. Phase 2 was constructed and is owned and operated by two companies in which NU has a 22.66 percent equity ownership interest. As an equity participant, NU guarantees certain obligations in connection with the debt financing of certain other participants that have lower credit ratings, and it receives compensation for such undertakings.
When the Phase 2 facilities became fully operational in 1991, a contract covering the purchase by the New England utilities of 70 terawatthours of energy from Hydro-Quebec over a period of approximately ten years came into effect. While transactions under this contract are expected to constitute the principal use of the interconnection during the 1990s, the interconnection is also available for other energy transactions and for the "banking" of energy in Canada during off-peak hours in New England, with equivalent amounts of energy available to New England during peak hours.
FOSSIL FUELS
OIL
The System's residual oil-fired generation stations used approximately 5.89 million barrels of oil in 1993. The System obtained the majority of its oil requirements in 1993 through contracts with three large, independent oil companies. Those contracts allow for some spot purchases when market conditions warrant, but spot purchases represented less than 15 percent of the System's fuel oil purchases in 1993. The contracts expire annually or biennially.
The average 1993 price paid for fuel oil used for electric generation was approximately $14 per barrel, which was the same as the average 1992 price. No. 6 fuel oil prices were high during the first quarter of 1993 due to increased demand and firm crude oil prices. Fuel oil prices declined slightly during the second and third quarters, weakened in the fourth quarter due to weak crude prices associated with OPEC over-production and then firmed in the first quarter of 1994 due to severe weather in the Northeast. On February 1, 1994, the weighted average price being paid for the System's fuel oil had increased to $17 per barrel.
The System-wide fuel oil storage capacity is approximately 2.5 million barrels. In 1993, inventories were maintained at levels between 40 - 60 percent of capacity. This inventory constitutes approximately 13 days of full load operation.
GAS
Currently, three system generating units, PSNH's Newington unit, WMECO's West Springfield Unit 3 and CL&P's Montville 5, can burn either residual oil or natural gas as economics dictate. The System is currently in the process of converting CL&P's Devon Units 7 & 8 into oil and gas dual-fuel generating units. Devon Unit 8's boiler conversion, which gave it gas burning capability, was completed in December 1993. Devon Unit 7's boiler conversion is scheduled for completion during its upcoming April 1994 outage. The System plans to have both units operational by the end of July 1994.
Annual gas consumption depends on factors such as oil prices, gas prices and unit availability. In 1993, gas was used sparingly at the System's dual-fuel units because of the attractiveness of oil prices relative to those for natural gas. CL&P, PSNH and WMECO all have contracts with the local gas distribution companies where the Montville, Newington and West Springfield units are located, under which natural gas is made available by those companies on an interruptible basis. While WMECO and PSNH meet all of their gas supply needs for the West Springfield and Newington units through purchases from the local gas distribution company, CL&P can supply its Montville unit either by purchasing gas from the local gas distribution company at a DPUC-approved rate or by purchasing gas directly from producers or brokers and transporting that gas through the interstate pipeline system and the local gas distribution system. In 1993, all of the gas burned at Montville Unit 5 was purchased from a local gas distribution company. It is expected that gas for the Devon units will be purchased directly from producers or 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 and will continue to supplement fuel oil requirements. The Iroquois Gas Transportation System, which became fully operational in November 1992, is expected to increase New England's gas supplies by at least 35 percent by November 1994. The increased availability of gas may make the option of converting other oil- burning electric generating units to gas on an interruptible dual-fuel basis more attractive to the System.
COAL
Currently, coal is purchased for HWP's Mt. Tom Station and for PSNH's Merrimack Units 1 and 2 and its coal-oil Schiller Units 4, 5 and 6. Mt. Tom Station received approximately 314,000 tons of coal in 1993 at an average delivered coal price of $ 43.40 per ton, which is down from the average 1992 coal price of $44.25 per ton. In 1993, HWP extended an existing contract for the majority of the coal to be supplied to Mt. Tom Station. This contract provides the System with assurance of coal supply and the flexibility to purchase some coal on the spot market. In the future, the System will evaluate whether to continue to purchase coal by contract or return to the spot market.
The coal inventory for Mt. Tom Station varies between a minimum level of 30 days fuel and a maximum of approximately 100 days fuel. Typically, the higher level is achieved in December, when deliveries are suspended for the winter. The stockpile provides the plant's operating fuel until deliveries are resumed in March. Because of changes in federal and state air quality requirements, by 1995 HWP will need to change the kinds of coal that it purchases for use at Mt. Tom Station. The potential impact of changing air quality requirements on coal supplies is being evaluated, and HWP is testing various types of coal to meet these requirements. See "Regulatory and Environmental Matters - Environmental Regulation-Air Quality Requirements."
In December 1991, PSNH executed a contract for the purchase of up to 100 percent of the coal requirements for PSNH's Merrimack Units 1 and 2 through December 31, 1993. This contract has been extended through December 31, 1994. Under this agreement, PSNH may also purchase coal on the spot market. In 1993, Merrimack Station received approximately 1.1 million tons of coal. The average delivered coal price in 1993 was $43.00 per ton. The coal inventory at Merrimack Station varies between a minimum of 60 days and a maximum of 90 days of fuel.
Schiller Units 4, 5 and 6, PSNH's dual-fuel coal and oil fired units, are dispatched on the most economical fuel in accordance with the provisions of the NEPOOL Agreement. Schiller Station consumed approximately 236,000 tons of coal in 1993 at an average delivered price of $39.40 per ton. Schiller's 1993 coal requirements were fulfilled through three primary contracts, pursuant to which 77 percent was provided by foreign suppliers and the remaining 23 percent by a domestic supplier.
FOSSIL PLANT RETIREMENTS
In 1991, the System retired seven of the System's oldest, least used, and most costly oil-fired steam generating units. In 1992, five oil-burning combustion turbines were retired. The decision to retire these units reflected both the surplus of generating capacity in New England and the System's continuing efforts to reduce operation and maintenance costs. There were no significant fossil plant retirements in 1993, but the System's plan calls for deactivating, by the end of 1994 Montville Units 5 and 6, which have a capacity of 82 MW and 410 MW, respectively. A final decision on the future of these units will be made following the completion of further economic evaluations and consideration of possible alternatives.
NUCLEAR GENERATION
GENERAL
The System companies have interests in seven operating nuclear units: Millstone 1, 2 and 3, Seabrook 1 and three other units owned by regional nuclear generating companies (the Yankee companies). System companies operate the three Millstone units, Seabrook 1 and CY. The System companies also have interests in the owned by the Yankee Atomic Electric Company (Yankee Rowe), 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 52.9330 percent (608 MW), PSNH's ownership interest in the unit is 2.8475 percent (32.7 MW) and WMECO's interest is 12.2385 percent (140.6 MW). NAEC and CL&P are parties to an agreement, similar to the Millstone 3 agreements, with respect to their 35.98201 percent (413.8 MW) and 4.05985 percent (46.7 MW) interests, respectively, in Seabrook. The agreements all provide for pro rata sharing of the construction and operating costs and the electrical output of each unit by the owners, as well as associated transmission costs.
CL&P, PSNH, WMECO and other New England electric utilities are the stockholders of the Yankee companies. Each Yankee company owns a single nuclear generating unit. The stockholder-sponsors of 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 and approximate MW entitlements in each are set forth below:
CL&P PSNH WMECO System % MW % MW % MW % MW
Connecticut Yankee Atomic Power Company (CYAPC) ...... 34.5 204 5.0 29 9.5 56 49.0 289 Maine Yankee Atomic Power Company (MYAPC) ............ 12.0 95 5.0 39 3.0 24 20.0 158 Vermont Yankee Nuclear Power Corporation (VYNPC)... 9.5 44 4.0 19 2.5 12 16.0 75 Yankee Atomic Electric Company (YAEC)* ............ 24.5 - 7.0 - 7.0 - 38.5 -
_____________________________ * See "Yankee Units" for information about the permanent shutdown of the unit owned and operated by YAEC.
CL&P, PSNH and WMECO are obligated to provide their percentages of any additional equity capital necessary for the Yankee companies. CL&P, PSNH and WMECO believe that the Yankee companies, excluding YAEC, will require additional external financing in the next several years to finance construction expenditures and nuclear fuel and for other purposes. Although the ways in which each Yankee company will attempt to finance these expenditures 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.
OPERATIONS
Capacity factor is a ratio that compares a unit's actual generating output for a period with the unit's maximum potential output. In 1993, the nuclear units in which the System companies have entitlements achieved an actual composite (weighted by entitlement) capacity factor of 79.9 percent. The five nuclear units operated by the System had a composite capacity factor of 80.3 percent based on normal winter claimed capability. The average capacity factor for operating nuclear units in the United States was 73.2 percent for January through September 1993 and 80.4 percent for the five System nuclear units operated in 1993, in each case using the design electrical rating method rather than normal winter claimed capability.
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 prudently incurred replacement power costs is permitted, with limitations, through the GUAC for CL&P, through a retail fuel adjustment clause for WMECO and through a comprehensive fuel and purchased power adjustment clause (FPPAC) for PSNH. 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-Massachusetts Retail Rates" and "Rates - New Hampshire Retail Rates."
MILLSTONE UNITS
The 1993 overall performance of the three nuclear electric generating units located at Millstone station and operated by the System was substantially better than in 1992. For the twelve months ended December 31, 1993, the three units' composite capacity factor was 79.3 percent, compared with a composite capacity factor of 53.1 percent for the twelve months ended December 31, 1992 and 38.4 percent for the same period in 1991.
In 1993 Millstone 1 operated at a 92.4 percent capacity factor with no extended outages. The unit began a planned refueling and maintenance outage on January 15, 1994 that is expected to last seventy-one days. Major work includes replacement of the main condenser tubes and installation of a new low pressure turbine. These modifications are intended to reduce the number of unplanned outages and improve the overall plant efficiency.
In 1993 Millstone 2 operated at a 82.5 percent capacity factor. On January 13, 1993, the plant returned to service following a refueling outage that commenced on May 29, 1992. During that outage, both steam generators were replaced. The DPUC has opened a docket to review CL&P's performance in replacing Millstone 2's steam generators. See "Rates-Connecticut Retail Rates" for further information on the steam generator replacement docket. In addition to several short outages during 1993, Millstone 2 was shut down for two unplanned outages of significant duration. The first such outage began on August 5, 1993, to replace a leaking primary system valve. That outage lasted ten days. For more information on this outage, see "Electric Operations - Nuclear Generation - Operations - NRC Regulation." The second significant unplanned outage lasted twenty-six days, commencing on September 15, 1993, and was necessary to upgrade the motor-operated feedwater isolation valves. Millstone 2 is scheduled to begin a refueling and maintenance outage on July 30, 1994. The outage is currently planned for a 63-day duration. Major work activities will include a reactor vessel in-service inspection, erosion/corrosion piping inspections, motor-operated valve testing and service water piping replacement.
In 1993 Millstone 3 operated at a 64.8 percent capacity factor. The unit began a refueling and maintenance outage on July 31, 1993 and completed it in 99 days. During the outage two significant issues were identified and resolved. Each of these issues resulted in an outage extension beyond original plans. The first issue required replacement of all four reactor coolant pumps due to concerns over turning vane cap screw and locking cup integrity. The second issue related to problems identified during inspection and testing of the supplementary leak collection and release system (SLCRS) and the auxiliary building ventilation system (ABVS), which provide secondary protection against radiological releases to the atmosphere. For more information on this issue, see "Electric Operations - Nuclear Generation - Operations - NRC Regulation." Resolution of these problems necessitated various modifications to these systems. No refueling or maintenance outages are planned for Millstone 3 during 1994. NUCLEAR PERFORMANCE IMPROVEMENT INITIATIVES
The System's nuclear organization is taking major steps to correct identified performance weaknesses. For instance, on a 1992 to 1995 cumulative basis, NU anticipates total expenditures of approximately $2.3 billion for operation and maintenance and $440 million in capital improvements for the five plants that it operates.
In addition, the comprehensive Performance Enhancement Program (PEP), authorized in 1992, continues to be one of the major initiatives that the nuclear organization is implementing to improve its overall performance. The program, in conjunction with other actions to address the long-term performance of the nuclear group, is designed to correct the root causes of the declining performance trend noted in the early 1990's. The PEP is organized into four major areas of activities, each focusing on a particular aspect of nuclear operations. The areas are management practices, programs and processes, performance assessments and functional programs. These areas were established based on an internal self-assessment completed in 1992. Detailed action plans have been prepared to address the specific activities. At the end of 1992, six of the forty-two action plans were completed and validated. An additional fourteen action plans were completed in 1993 and are awaiting validation. Seven action plans are to be completed in 1994, leaving fifteen action plans to complete during the remainder of the program. The 1993 PEP budget was $32.9 million.
The System also announced a major reorganization of its Connecticut-based nuclear organization on November 8, 1993. The primary focus was realignment of engineering services along unit lines. The changes also included the appointment of a new senior vice president for Millstone station, some management consolidation, and a reorganization of the nuclear plant maintenance staff. See "Employees." In addition, most of the nuclear support staff currently located in Berlin, Connecticut will be centralized at the generating stations by the summer of 1994. To support these efforts, the System is constructing a five-story office building at Millstone station. This building will replace several temporary modular buildings and will house most of the nuclear technical support staff that is now located at various System locations. The prudence of this construction project is the subject of an ongoing inquiry by the DPUC.
SEABROOK
In 1993 Seabrook 1 operated at a capacity factor of 89.8 percent. The unit is currently in an 18-month operating cycle that began in November 1992.
The unit is scheduled to begin a 57-day refueling and maintenance outage on April 16, 1994. During this outage, the main plant computer will be replaced.
CL&P, PSNH and NAEC could be affected by the ability of 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, has been in bankruptcy since February 1991. The Bankruptcy Court confirmed GBPC's reorganization plan on March 5, 1993 and approvals are required from NRC, FERC and NHPUC to consummate the plan. CL&P has committed to advance GBPC up to $12 million, secured by a high priority lien on GBPC's share of Seabrook, to cover GBPC's shortfalls in funding its share of the operation of Seabrook through June 30, 1994. As of March 1, 1994, CL&P was lending approximately $2 million to GBPC under this arrangement. GBPC has advised CL&P that it expects to consummate its reorganization plan, emerge from bankruptcy and repay CL&P for all advances by June 30, 1994. CL&P is unable to predict what impact, if any, failure of the reorganization plan to become effective will have on the operating license for Seabrook or what actions CL&P and the other joint owners of the unit may be required to take.
On May 6, 1991, NHEC, PSNH's largest customer and one of the joint owners of Seabrook, filed a petition for reorganization under Chapter 11 of the Federal Bankruptcy Code. The plan of reorganization for NHEC was confirmed by the United States Bankruptcy Court on March 20, 1992 and wholesale power arrangements were accepted by FERC on July 22, 1992. On October 5, 1992, the NHPUC released an order approving NHEC's plan of reorganization. Under the plan of reorganization, NHEC will remain a customer of PSNH. The plan also provides that PSNH will purchase the capacity and energy of NHEC's 2.2 percent ownership interest in Seabrook 1 and pay all of NHEC's Seabrook costs for a ten-year period, which began July 1, 1990. On December 1, 1993, the United States Bankruptcy Court for the District of New Hampshire declared the NHEC reorganization plan effective as of that date. See "Rates--Wholesale Rates" for further information on the bankruptcy and subsequent reorganization of NHEC.
At certain times, VEG&T failed to pay its share of Seabrook costs. Certain joint owners, including PSNH and CL&P, provided funds against future payments due from VEG&T to assure that funds were available to meet its ownership share of Seabrook costs. PSNH initially participated in such payments, but ceased providing such funds in January 1988, when it commenced bankruptcy proceedings under Chapter 11 of the Bankruptcy Code. The total amount contributed by PSNH until then was $976,000. The total amount contributed by CL&P was $265,000.
As part of an agreement to resolve issues raised during the bankruptcy of PSNH, PSNH agreed that it or its designee would purchase the VEG&T 0.41259 percent interest in Seabrook for approximately $6.4 million. NAEC, the current owner of PSNH's ownership share in Seabrook, agreed to purchase the interest and to enter into a separate power contract with PSNH, under which PSNH would be obligated to buy from NAEC all of the capacity and output of Seabrook attributable to such interest for a period equal to the length of the NRC full power operating license for Seabrook. On January 7, 1994, the NRC approved the transfer of VEG&T's ownership share of Seabrook to NAEC. All other regulatory approvals for NAEC's purchase were received and the acquisition became effective on February 15, 1994. In settlement of their claims against VEG&T for advances, PSNH and CL&P received payment of the amounts advanced, $1.78 million and $390,000, respectively, out of proceeds of the sale, with interest thereon, for the period each advance was outstanding at the prime rate. See "Rates-New Hampshire Retail Rates-Memorandum of Understanding" and "Rates-New Hampshire Retail Rates-Seabrook Power Contract" for further information on NAEC's acquisition of VEG&T's share of Seabrook.
In 1989, as part of a comprehensive settlement of Seabrook issues, PSNH agreed to make certain payments totaling $16 million to Massachusetts Municipal Wholesale Electric Company during the first eight years of Seabrook operation. As of December 31, 1993, PSNH had made approximately $7.2 million of these payments.
YANKEE UNITS
CY, the nuclear unit owned by MYAPC (MY) and the nuclear unit owned by VYAPC (VY) operated in 1993 at capacity factors of 73.1 percent, 74.3 percent and 74.1 percent, respectively, based on normal winter claimed capability. Yankee Rowe has not operated since October 1991.
CY. As of December 31, 1993, CY, since it began commercial operation in 1968, had generated over 99 billion kWh (gross) of electricity, making it one of the most productive nuclear generating units in the United States.
The unit completed, on schedule, a 66-day refueling and maintenance outage that began on May 15, 1993. The second reload of fuel clad with zircalloy was installed during this outage to replace the stainless steel clad fuel. There is one more phase to this upgrade project that, when completed, will make the operation of the reactor core more economical by allowing longer operating cycles. CY's next refueling and maintenance outage is scheduled to begin on November 12, 1994 and is expected to last 54 days. Major work activities will include auxiliary feedwater system modifications and motor-operated valve testing. The start date and length of this refueling outage may be impacted by an unplanned shutdown which occurred on February 12, 1994, when the plant was required to come off line to address integrity concerns in the safety-related service water system. CYAPC is reviewing the scope of work required and schedule for returning the unit to service from the unplanned outage.
In October 1992, CYAPC filed an application with the FERC for wholesale rate relief. CYAPC requested the increase to become effective on January 1, 1993. The filing requested an increase in estimated decommissioning cost collections from $130 million to $309.1 million (in July 1992 dollars) and also proposed to adjust decommissioning accruals automatically on an annual basis beginning January 1, 1993. In December 1992, FERC accepted CYAPC's increased rates for filing, to become effective on June 1, 1993, subject to refund, and rejected the proposal to automatically adjust decommissioning accruals. A settlement between all the parties was reached in 1992 and was accepted by FERC in 1993. This included an accrual level for decommissioning of $294.2 million in 1992 dollars and an automatic increase of 5.5% annually in the decommissioning accrual for each of the next five years.
MY. MY began a refueling and maintenance outage on July 31, 1993 and completed it in 75 days. During the outage, repairs were made to the reactor vessel thermal shield.
VY. VY began a refueling and maintenance outage on August 27, 1993, and completed it in 59 days, including recovery from a dropped fuel bundle that suspended fuel movement for approximately 20 days.
Yankee Rowe. In February 1992, YAEC's owners voted to shut down Yankee Rowe permanently and to begin preparations for an orderly decommissioning of the facility. The decision to close the generating plant eight years before the end of its operating license was 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 the regulatory requirements that the unit would need to meet in order to restart.
See "Electric Operations-Nuclear Generation-Operations-Decommissioning" for information on YAEC's filing with FERC to collect for shutdown and decommissioning costs and the recovery of the remaining investment in the Yankee Rowe plant.
The power contracts between CL&P, PSNH and WMECO and YAEC permit YAEC to recover from each its proportional share of these costs from CL&P, PSNH and WMECO. Management believes that, although Yankee Rowe was shut down eight years before the end of the unit's current license, CL&P, PSNH and WMECO will recover their investments in YAEC, along with any other costs associated with the shutdown and decommissioning of Yankee Rowe. Accordingly,
the System has recognized these costs as a regulatory asset on its consolidated balance sheet and as a corresponding obligation to YAEC.
NRC REGULATION
As holders of licenses to operate nuclear reactors, CL&P, PSNH, WMECO, NAEC, North Atlantic, 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.
In its latest Systematic Assessment of Licensee Performance Report (SALP report) issued on October 19, 1993, the NRC gave the three Millstone nuclear plants a Category 1 rating in the area of radiological controls and a Category 2 rating in five of the seven areas rated: plant operations, maintenance/surveillance, emergency preparedness, security and engineering/technical support. The Millstone units received a Category 3 rating in the area of safety assessment/quality verification. Category 1 indicates "a superior level of performance," Category 2 indicates "a good level of performance" and Category 3 denotes "an acceptable level of performance." The evaluation covered plant activities for the period February 16, 1992 through April 3, 1993. Management expects to continue to improve performance, thereby raising these scores.
The NRC issued its latest SALP report for Seabrook 1 on November 18, 1993. The report covered the interval from March 1, 1992 through August 28, 1993. This report reflects the recent revisions to the SALP program in which the number of functional evaluation areas has been reduced from seven to four: plant operations, maintenance, engineering and plant support. The evaluation rated Seabrook 1 a Category 1 in the engineering and plant support areas. In the areas of plant operations and maintenance, the unit was rated a Category 2.
The NRC issued its latest SALP report for CY on May 21, 1993. The report covered the interval from July 14, 1991 through January 9, 1993. This evaluation recognized the superior performance of CY by awarding the unit a Category 1 in six of the seven areas rated: plant operations, emergency preparedness, security, engineering/technical support, safety assessment/quality verification and radiological controls. In the final area, maintenance/surveillance, CY was rated as a Category 2.
Despite the overall improved performance of the Millstone units, there were a number of regulatory enforcement actions taken by the NRC in 1993. On May 4, 1993, the NRC issued to NNECO a Notice of Violation (NOV) identifying two potential violations. The first violation concerned NRC findings that a former employee was subjected to harassment and intimidation in 1989 for raising a nuclear safety concern and that senior management was not effective in dealing with the situation. The second violation involved NRC concerns that an employee may have deliberately delayed the processing of a contemplated substantial safety hazard evaluation conducted to fulfill the requirements of federal law. Following NNECO's response to the NOV, the NRC withdrew the second violation. To resolve this matter, NNECO paid a fine of $100,000 in connection with the first violation.
On August 5, 1993, Millstone Unit 2 was shut down by plant personnel after extensive efforts to repair a leaking primary system valve proved unsuccessful, and a sudden increase in the leak rate was experienced. Following replacement of the damaged valve, the unit was returned to service on August 16, 1993. Recognizing the seriousness of this event and the potentially severe consequences of the failed repair efforts, NNECO performed a detailed evaluation of this event to consider potential deficiencies and identify the actions needed to prevent recurrence. The NRC also conducted a special investigation of this event and on September 22, 1993, identified to NNECO three apparent violations, related to work control planning and implementation, which were being considered for escalated enforcement. On December 3, 1993, the NRC informed NNECO that it was imposing a civil penalty of $237,500 for the three violations. NNECO has since paid the fine.
On September 10, 1993, NNECO was informed by the NRC that, as a result of an investigation by the NRC Office of Investigation and a routine safety inspection of the Millstone Unit 1 nuclear power plant, two apparent violations arising from 1989 events were being considered for possible civil monetary penalties. The first issue concerned the alleged failure to initiate and perform a required engineering analysis to determine the operability of safety-related system in a timely manner. The second issue relates to allegations that the engineer who identified the system as being potentially inoperable was harassed and discriminated against in retaliation for the findings of his technical evaluations. These matters were investigated between early 1992 and June 1993 by a grand jury acting under the direction of the U.S. Attorney's Office in Bridgeport, Connecticut. The U.S. Attorney's office issued a letter on June 30, 1993, stating that no prosecutorial action would be initiated. On March 17, 1994, the NRC informed NNECO that further enforcement action with respect to this matter was not planned, because their review had determined that there was insufficient evidence to support the apparent violations.
On September 20, 1993, the NRC issued to NNECO an NOV concerning two violations at the Millstone Station identified during its evaluation of the licensed operator requalification training (LORT) program. The first violation concerned an inspection finding that various licensed operators at Millstone 1 and 2 did not fully complete the LORT program for the 1991 and 1992 training periods. The second violation cited the failure of NNECO's internal nuclear review board to perform comprehensive audits of the training, retaining, requalification, and performance of the operations staff at Millstone 2 and 3. NNECO chose not to contest the violations nor the imposition of a $50,000 civil penalty.
On December 15, 1993, the NRC issued an inspection report concerning the SLCRS and ABVS systems deficiencies that were identified during the 1993 Millstone 3 refueling outage. The report identified two apparent violations that are being considered for escalated enforcement. The apparent violations involve the inability of the systems to provide the necessary drawdown of secondary containment following a postulated accident and NNECO's failure to fully resolve these problems earlier, as a result of previous similar violations identified in September 1992. On March 11, 1994, the NRC notified NNECO that it proposed to impose a civil penalty of $50,000 in respect of these violations. NNECO has 30 days to respond to the NRC.
In January 1994, the NRC issued a report finding that the overall Millstone 1 operator requalification training program was satisfactory. The NRC had previously found the program to be unsatisfactory. The recent conclusion was based on the results of a number of NRC inspections and the operator examinations conducted in September 1993. The NRC reviewed NNECO's corrective actions and determined that all actions necessary to obtain and maintain a satisfactory requalification training program had been completed and verified.
INDUSTRY-WIDE NUCLEAR ISSUES
The NRC regularly conducts generic reviews of technical and other issues, a number of which may affect the nuclear plants in which System companies have interests. Issues currently under review include individual plant examination programs to evaluate the likelihood and effects of severe accidents at operating nuclear plants, pipe crack phenomena, post-accident measures for controlling hydrogen, reactor vessel embrittlement, upgrading of emergency response facilities and communications, the ability of plants to cope with a total loss of power, emergency response planning, fitness for duty policies, operator requalification training, reactor containment suitability, maintenance adequacy, motor-operated valve testing, design basis reconstitution, diesel generator reliability, life extension, equipment procurement, electrical distribution system adequacy, reactor coolant pump seal integrity, plant risk during shutdown and low power operation, technical specification improvements, accident management, component aging, steam generator degradation phenomena, service water system adequacy, seismic qualification of equipment and other issues. At present, the outcome of the NRC's reviews of these and other technical issues, and the ways in which the different nuclear plants in which System companies have interests may be affected, cannot be determined. 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. Further, the NRC is currently evaluating a staff report on the reporting of nuclear safety concerns, which may result in changes in the way such concerns are addressed. The NRC has authorized the conduct of various regulatory activities designed to lower costs to its licensees while maintaining or improving public safety.
Public controversy concerning nuclear power could affect the nuclear units in which System companies have ownership interests. Over the past decade, proposals to force the premature shutdown of nuclear units have become issues of serious and recurring attention in Maine, Massachusetts, Vermont and New Hampshire. States' efforts to deal with the siting of low level radioactive waste repositories have also stimulated negative reactions in communities being considered for those facilities. The continuing controversy about nuclear power may affect the cost of operating the nuclear units in which System companies have interests.
While much of the public policy debate about nuclear power has been critical in the past, some trends in the energy environment have stimulated renewed support for nuclear power in the northeastern United States. Among these trends are the growing national environmental concerns and legislation about acid rain, air quality and global warming associated with fossil fuels.
These concerns particularly affect the densely populated areas in the Northeast, downwind of coal-burning regions like the Midwest and mid-Atlantic states. In addition, at times when the price and availability of fuel oil have been volatile, the System's commitment to nuclear power has allowed it to minimize the oil-related rise in customers' bills. While the public controversy about nuclear power is not expected to disappear, recent trends suggest a more balanced public policy debate about the impacts of fossil fuel generation as well.
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.
The Price-Anderson Act currently limits public liability from a single incident at a nuclear power plant to $9.4 billion. The first $200 million of liability would be provided by purchasing the maximum amount of commercially available insurance. Additional coverage of up to $8.8 billion would be provided by an assessment of $75.5 million per incident, levied on each of the 116 United States nuclear units that are currently subject to the secondary financial protection program, subject to a maximum assessment of $10 million per incident per nuclear unit in any year. In addition, if the sum of all public liability claims and legal costs arising from any nuclear incident exceeds the maximum amount of financial protection, each reactor operator can be assessed an additional five percent, up to $3.8 million or $437.9 million in total for all 116 reactors. The maximum assessment is to be adjusted for inflation at least every five years.
Based on CL&P's, PSNH's and WMECO's ownership interests in the three Millstone units and CL&P's and NAEC's interests in Seabrook 1, the System's current maximum direct liability would be $244.2 million per incident. In addition, through CL&P's, PSNH's and WMECO's power purchase contracts with the four Yankee regional nuclear electric generating companies, the System would be responsible for up to an additional $97.9 million per incident. These payments would be limited to a maximum in any year of $43.2 million per incident.
Insurance has been purchased from Nuclear Electric Insurance Limited (NEIL) to cover: (1) certain extra costs incurred in obtaining replacement power during prolonged accidental outages with respect to CL&P's and WMECO's ownership interests in Millstone 1, 2, 3, and CY, CL&P's ownership interest in Seabrook, and PSNH's Seabrook Power Contract with NAEC; and (2) the cost of repair, replacement, or decontamination or premature decommissioning of utility property resulting from insured occurrences with respect to CL&P's ownership interests in Millstone 1, 2, 3, CY, MY, VY, and Seabrook 1; WMECO's ownership interests in Millstone 1, 2, 3, CY, MY, and VY; PSNH's ownership interest in Millstone 3, CY, MY and VY; and NAEC's ownership interest in Seabrook 1. All companies insured with NEIL are subject to retroactive assessments if losses exceed the accumulated funds available to NEIL. The maximum potential assessments against CL&P, PSNH, WMECO, and NAEC with respect to losses arising during current policy years are approximately $13.9 million under the replacement power policies and $29.9 million under the property damage, decontamination, and decommissioning policies. Although CL&P, PSNH, WMECO, and NAEC have purchased the limits of coverage currently available from the conventional nuclear insurance pools, the cost of a nuclear incident could exceed available insurance proceeds.
Insurance has been purchased from American Nuclear Insurers/Mutual Atomic Energy Liability Underwriters, aggregating $200 million on an industry basis, for coverage of worker claims. All companies insured under this coverage are subject to retrospective assessments of $3.2 million per reactor. The maximum potential assessments against CL&P, PSNH, WMECO, and NAEC with respect to losses arising during the current policy period are approximately $13.9 million.
CYAPC expects that it will receive an insurance recovery for costs related to the CY thermal shield repair which occurred during the 1987 outage, and the removal which occurred during the 1989 outage, but the amount and time of payment are not certain. See "Rates-Connecticut Retail Rates-Adjustment Clauses."
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. These materials and services are available from a number of domestic and foreign sources. The System companies have predominantly relied on long term contracts with both domestic and foreign suppliers, supplemented with short term contracts and market purchases, to satisfy the units' requirements. Although the System has increased the use of foreign suppliers, domestic suppliers still provide the majority of the materials and services. The System companies have maintained diversified sources of supply, relying on no single source of supply for any one component of the fuel cycle, with the exception of enrichment services of which the majority of the System companies' requirements are provided under a long term contract with the U.S. Enrichment Corporation, a wholly-owned government corporation, established on July 1, 1993, in accordance with the Energy Policy Act and the successor to the U.S. DOE Uranium Enrichment Enterprise. 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. utility industry is required to pay to the DOE, via a special assessment for the costs of the decontamination and decommissioning of uranium enrichment plants operated by the DOE, $150 million each U.S. Government fiscal year for 15 years beginning in 1993. Each domestic utility will make a payment proportioned on its past purchases from the DOE's Uranium Enrichment Enterprise. Each year, the DOE will adjust the annual assessment using the Consumer Price Index. The Energy Policy Act provides that the assessments are to be treated as reasonable and necessary current costs of fuel, which costs shall be fully recoverable in rates in all jurisdictions. The System's total share of the estimated assessment was approximately $56.7 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 regulatory asset, with corresponding obligation on its balance sheet.
Costs associated with nuclear plant operations include amounts for disposal of nuclear wastes, 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 wholesale charges. Such provisions include amortization and recovery in rates of previously unrecovered disposal costs of accumulated spent nuclear fuel.
HIGH-LEVEL RADIOACTIVE WASTES
Under the Nuclear Waste Policy Act of 1982, the DOE is required to design, license, construct and operate a permanent repository for high level
radioactive wastes and spent nuclear fuel. The act requires the DOE to provide, beginning in 1998, for the disposal of spent nuclear fuel and high level radioactive waste from commercial nuclear plants through contracts with the owners and generators of such waste. The System companies have entered into such contracts with the DOE with respect to Millstone 1, 2 and 3 and Seabrook 1, and have been advised that the Yankee companies have entered into similar contracts.
The DOE has established disposal fees to be paid to the federal government by electric utilities owning or operating nuclear generating units. The System companies have been paying for such services for fuel burned starting in April 1983 on a quarterly basis since July 1983 in accordance with the contracts; the DPUC, the NHPUC and the DPU permit the fee to be recovered through rates.
The disposal fee for fuel burned before April 1983 (previously burned fuel) is determined in accordance with a fee structure based on fuel burnup. Under the contract payment option selected, the System companies anticipate making payment to the DOE for disposal of previously burned fuel just before the first delivery of spent fuel to the DOE. That payment obligation is not a funded obligation. The liability under the selected payment option for previously burned fuel, including interest, through December 31, 1993, and the amounts recovered through rates for previously burned fuel through the end of 1993 for Millstone 1 and 2, are as follows:
Previously Burned Fuel Liability, Amounts Recovered for Previously Including Interest, Thru 12/31/93 Burned Fuel Thru 12/31/93 (Millions)
CL&P $136.1 $134.5 WMECO 31.9 32.3 Total $168.0 $166.8
Because Millstone 3 and Seabrook 1 went into service after 1983, there is no previously burned fuel liability for those units.
In return for payment of the fees prescribed by the Nuclear Waste Policy Act, the federal government is to take title to and dispose of the utilities' high level wastes and spent nuclear fuel beginning no later than 1998. Until the federal government begins receiving such materials, 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. With 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.
Under the terms of a license amendment approved by the NRC in 1984, 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 and, on January 25, 1993, filed with the NRC seeking authorization to implement the plan. MYAPC believes that the replacement of the fuel racks, if approved, will provide adequate storage capacity through the unit's licensed operating life. While no intervention has occurred, MYAPC cannot predict with certainty whether the NRC authorization will be granted or whether or to what extent the storage capacity limitation at the unit will affect the operation of the unit or the future cost of disposal.
Under the terms of a license amendment approved by the NRC in 1991, the storage capacity of the spent fuel pool at VY is expected to be reached in 2003, and the available capacity of the pool is not expected to be able to accommodate a full-core removal after 1998.
Because the Yankee Rowe plant was permanently shut down effective February 26, 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 WASTES
Disposal costs for low-level radioactive wastes (LLRW) have continued to rise in recent years despite significant reductions in volume. Approximately $7.65 million was spent on LLRW disposal for the Millstone units and CY in 1993.
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 LLRW from outside its compact region. During 1992, the Barnwell, South Carolina site announced its intention to remain open for disposal of out-of-region LLRW until June 30, 1994. In November 1992, the Northeast Compact commission entered into an agreement with the Southeast Interstate Low-Level Radioactive Waste Management Compact (the Southeast Compact) commission providing for continued access to the Barnwell facility until June 30, 1994 by Connecticut LLRW generators, and the System agreed to pay, in addition to disposal fees, an access fee of $220 per cubic foot, with a minimum of $4.73 million, for the right to dispose of LLRW at Barnwell during this period.
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. In June 1991, the Service announced that it had selected three potential sites in north-central Connecticut for further study. The Service's announcement provoked intense controversy in the affected municipalities and resulted in legislative action to stop the selection process. On February 1, 1993, the Service presented the legislature with a new 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 in 1994. The Service's activities in this regard are funded by assessments on Connecticut's LLRW generators. The System was assessed approximately $1.8 million for the state's 1992-1993 fiscal year. Due to the change to a volunteer process, there was no assessment for the 1993-1994 fiscal year and the state projects no assessment for the 1994-1995 and 1995-1996 fiscal years.
The System has plans to acquire or construct additional LLRW storage capacity at the Millstone and CY sites to provide for temporary storage of LLRW should that become necessary. The System can manage its Connecticut LLRW by volume reduction, storage or shipment at least through 1999. Management cannot predict whether and when a disposal site will be designated in Connecticut.
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 $1.3 million in off-site disposal costs in 1993. New Hampshire is pursuing options for out-of-state disposal of LLRW generated at Seabrook.
Massachusetts and Vermont have arranged for continued access to the Barnwell facility until mid-1994 for the nuclear waste generators in their states. YAEC is currently disposing of its LLRW at the Barnwell facility. 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 finalizing an agreement with the state of Texas to provide access to a facility that will be developed in that state.
DECOMMISSIONING
The System's most recent comprehensive site-specific updates of the decommissioning costs for each of the three Millstone units were completed in 1992 and for Seabrook was completed in 1991. The recommended decommissioning method reflected in the cost estimates 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, 1993 dollars, and include costs allocable to NAEC's share of Seabrook recently acquired from VEG&T.
CL&P PSNH WMECO NAEC NU System (Millions) Millstone 1 $312.5 $ - $ 73.3 $ - $385.8 Millstone 2 251.0 - 58.9 - $309.9 Millstone 3 223.0 12.0 51.6 - 286.6 Seabrook 1 14.9 - - 131.7 146.6 Total $801.4 $12.0 $183.8 $131.7 $1,128.9
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 cost of decommissioning the Millstone units is $1.1 billion in December 1993 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, ratepayers in future years will need to increase their payments 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 New Hampshire Nuclear Decommissioning Financing Committee (NDFC) established approximately $323 million (in 1991 dollars) as the decommissioning cost estimate for immediate and complete dismantlement of Seabrook 1 upon its retirement. On March 10, 1993, FERC approved this estimate. The estimated total decommissioning cost for Seabrook 1 is $366 million in December 1993 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.
North Atlantic submitted its annual update of the 1991 Decommissioning Study and Funding Schedule to the NDFC on March 31, 1993. It included an updated estimate for the prompt removal and dismantling of Seabrook station in 2026 at the end of licensed life and a review of the assumptions on inflation and rate-of-return on fund investments used to develop the joint owner contribution schedule. North Atlantic concluded that the 1991 estimate, escalated in accordance with these assumptions to 1993 dollars, is still valid. Although a schedule has not been set by the NDFC, public hearings on the decommissioning estimate and funding schedule will probably be held in the third quarter of 1994.
The new Investment Guidelines for the Seabrook Nuclear Decommissioning Financing Fund, which were approved by the New Hampshire State Treasurer and would have gone into effect on November 1, 1993, have been put on hold by a recent decision of FERC. The October 20, 1993 FERC order effectively reinstated the so-called "black lung" investment restrictions on decommissioning funds subject to its jurisdiction, although Congress, in the Energy Policy Act, had repealed the IRS regulation which mandated them. Under these restrictions, investments are limited to public debt securities that are fully backed by the U.S. government, tax exempt obligations of state or local governments and time deposits with a bank or insured credit union. The new guidelines would allow equity holdings by the joint owners of Seabrook, beginning with a limit of 10 percent in 1994 and gradually increasing to a limit of 40 percent in 1997. The strategies also call for a gradual reduction in the equity position as the plant approaches the end of its licensed life. Implementation of new investment guidelines for the Millstone units and CY have also been delayed because of the FERC decision. The System is party to petitions filed with FERC in November 1993, seeking reconsideration of the FERC decision.
As of December 31, 1993, the balances (at cost) in the external decommissioning trust funds were as follows:
Millstone 1 Millstone 2 Millstone 3 Seabrook 1 (Millions of Dollars)
CL&P........... $70.4 $45.5 $30.9 $ .9 PSNH........... * * 1.5 * WMECO.......... 24.0 16.5 8.6 * NAEC........... * * * 7.9 _____ _____ _____ ____ Total........ $94.4 $62.0 $41.0 $8.8
*PSNH has no ownership interest in the Millstone 1 and 2 units. WMECO has no ownership interest in Seabrook 1. NAEC's only ownership interest is in Seabrook 1.
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, 1993 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 NU System (Millions)
CY $117.3 $17.0 $32.3 $166.6 MY 38.8 16.2 9.7 64.7 VY * * * * Yankee Rowe 68.7 19.6 19.6 107.9 ______ _____ _____ ______ Total $255.3 $65.6 $69.6 $390.5
*VYNPC is currently reestimating the cost of decommissioning VY. Based on recent estimates for comparable units, the projected cost is expected to fall into the $300 - $350 million range. The System's share of these costs is expected to be between $48 million and $56 million. The results of the VYNPC study are expected to be available in the spring of 1994.
In June 1992, YAEC filed a rate filing to obtain FERC authorization for an increase in rates to cover the costs of closing and decommissioning the Yankee Rowe plant and for the recovery of the remaining investment in the unit over the remaining period of its NRC operating license. At December 31, 1993, the System's share of these estimated costs was approximately $132.8 million. A settlement agreement among YAEC, the FERC staff and intervenors to the FERC proceeding addressing all issues has been filed with and accepted by FERC. YAEC has submitted its decommissioning plan to the NRC for approval.
Due to the unexpected continued availability of the low level waste disposal facility in Barnwell, South Carolina, YAEC requested NRC permission to use decommissioning funds prior to final NRC approval of the complete plan. On April 16, 1993, the NRC approved YAEC's request to use funds for removal of the steam generators, pressurizer and reactor internals. By December 31, 1993, all major components were successfully disposed of at Barnwell and only a small number of internals shipments remain to be made.
YAEC will continue its dismantling of the plant in 1994. The NRC's review of the decommissioning plan is expected to be completed by December
31, 1994 at which time YAEC will, depending upon the availability of a low level waste site, move to completely dismantle the facility.
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 $339.9 million in year-end 1993 dollars. As a result of a 1987 study approved by FERC, CYAPC has been accruing expenses based on an estimated decommissioning level of $130 million. On October 30, 1992, CYAPC filed with FERC a proposed change in rates to recover the increase in estimated decommissioning costs. On May 11, 1993, FERC approved a settlement agreement allowing a decommissioning estimate of $294.2 million (in July 1992 dollars) to be recovered in rates effective June 1, 1993. See "Electric Operations - Nuclear Generation - Operations - Yankee Units."
In 1984, CYAPC established an independent irrevocable decommissioning trust fund, which was modified for tax purposes in 1987 to create two trusts.
Each month, CYAPC's sponsors are billed for their proportionate share of decommissioning expense as allowed by FERC and payments are made directly to the trust. The combined balance of the trusts at December 31, 1993 was $137.8 million. The trust balances must be used exclusively to discharge decommissioning costs as incurred.
MYAPC estimates the cost of decommissioning MY at $323.7 million in December 31, 1993 dollars based on a study completed in July 1993.
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 new 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 cogeneration and small power production (SPP) facilities anywhere in the world. This legislation also expands Charter Oak's permissible involvement in exempt wholesale generators (EWGs) to include development, construction and ownership. 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. For a discussion of certain highlights of the Energy Policy Act relating to EWGs, see "Regulatory and Environmental Matters - - Public Utility Regulation." Under the Public Utility Regulatory Policies Act of 1978 (PURPA), as a subsidiary of an electric utility holding company, Charter Oak is effectively limited to no more than 50 percent ownership in a QF within the United States. To work within this constraint, Charter Oak has made strategic alliances with several experienced developers to pursue development opportunities. Through these relationships, Charter Oak is pursuing development opportunities nationwide and internationally.
Although Charter Oak has no full-time employees, eight NUSCO employees are dedicated to Charter Oak activities on a full-time basis. Other NUSCO employees provide services as required.
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 which provides steam to Campbell Soup Company's Paris, Texas manufacturing facility and electricity to Texas Utilities Electric Company. 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, the Midwest, Latin America and the Pacific Rim.
NU's total investment in Charter Oak was approximately $23.0 million as of December 31, 1993. NU, Charter Oak and its subsidiary, Charter Oak Energy Development, have received approval from the SEC to increase NU's authorized investment in Charter Oak to up to $100 million and to increase Charter Oak's authorized investment in COE Development to up to $100 million for preliminary development activities in QFs, IPPs, EWGs and foreign utility companies.
ENERGY MANAGEMENT SERVICES
In 1990, NU organized a new subsidiary corporation, HEC, which acquired 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' overall energy consumption and reduce energy costs and/or conserve energy 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, although the SEC's order under the 1935 Act that authorized NU to operate HEC also permits HEC to serve customers outside that area, so long as over half of its revenues are attributable to customers 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 March 1, 1994. Under the SEC order authorizing HEC's participation in the Money Pool, HEC may borrow up to $11 million from the Money Pool. At December 31, 1993, HEC had $2.9 million outstanding from its borrowings from the Money Pool.
REGULATORY AND ENVIRONMENTAL MATTERS
PUBLIC UTILITY REGULATION
NU is registered with the SEC as an electric utility holding company under the 1935 Act. Under the 1935 Act, the 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 Energy Policy Act amended the 1935 Act to give registered holding companies, like NU, broadened authority to invest in small power production facilities qualifying under PURPA and to own a new class of IPPs known as EWGs. An EWG is an entity exclusively in the business of owning and/or operating generating facilities that sell electricity at wholesale. EWGs are exempt from most regulation under the 1935 Act. A registered holding company may also invest in foreign utility companies with SEC approval. EWGs, however, are subject to state regulation with respect to siting and financial regulation to prevent cross-subsidies and self-dealing among utilities and affiliated EWGs.
The Energy Policy Act also amended the Federal Power Act to authorize FERC to order wholesale transmission wheeling services, including the enlargement of transmission capacity necessary to provide such services, unless such transmission would unreasonably impair the reliability of the electric systems affected or the utility ordered to provide transmission is unable to obtain necessary governmental approvals or property rights. Rates for transmission ordered under the Energy Policy Act are to be designed to protect the wheeling utilities' existing customers. 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 franchise laws.
CL&P is subject to regulation by the DPUC, which has jurisdiction over, among other things, retail rates, accounting procedures, certain dispositions of property and plant, mergers and consolidations, securities issues, standards of service, management efficiency and construction and operation of generation, transmission and distribution facilities. Because of their ownership interests in the Millstone units, PSNH and WMECO are also subject to the jurisdiction of the DPUC with respect to their activities in Connecticut and their securities issues.
PSNH and NAEC are subject to regulation by the NHPUC, which has jurisdiction over retail rates, accounting procedures, certain dispositions of property and plant, quality of service, securities issues, acquisitions of securities of other utilities, mortgages of property, declaration of dividends, contracts with affiliates, management efficiency, construction and operation of generation, transmission and distribution facilities, integrated resource planning and other matters. Although the Seabrook Power Contract between PSNH and NAEC is a wholesale contract subject to the jurisdiction of FERC, pursuant to the terms of the Rate Agreement, the NHPUC has the right to review the prudence of costs incurred by NAEC to determine whether they should be passed on to ratepayers through FPPAC, and the NHPUC and the State of New Hampshire have additional rights and limited jurisdiction over certain other Seabrook Power Contract issues.
NU and its subsidiaries are subject to the general supervision of the NHPUC with respect to all dealings with PSNH and NAEC. Based upon PSNH's ownership of generating and transmission facilities in Maine and transmission and hydroelectric facilities in Vermont, PSNH is also subject to limited regulatory jurisdiction in those states.
WMECO is subject to regulation by the DPU, which has jurisdiction over retail rates, accounting procedures, quality of service, contracts for the purchase of electricity, mergers, securities issues and other matters. The DPU has adopted regulations that provide for DPU preapproval of utility plant construction, procurement of non-utility generation (QFs and IPPs), and C&LM programs. HWP is subject to regulation by the DPU with respect to certain contracts and quality of service. NU and its subsidiaries are subject to the general supervision of the DPU with respect to all dealings with WMECO and HWP.
CL&P is subject to the jurisdiction of the NHPUC for limited purposes in connection with its ownership interest in Seabrook.
CL&P, PSNH, WMECO, NAEC and HWP are public utilities under Part II of the Federal Power Act and are subject to regulation by the FERC with respect to, among other things, interconnection and coordination of facilities, wholesale rates and accounting procedures.
The System incurs substantial capital expenditures and operating expenses to identify and comply with environmental, energy, licensing and other regulatory requirements, including those described in the following subsections, and it expects to incur additional costs to satisfy further requirements in these and other areas of regulation. Because of the continually changing nature of regulations affecting the System, the total amount of these costs is not determinable.
The System has active auditing programs addressing a variety of legal and regulatory areas, including an environmental auditing program. To the extent it is determined that a System operation or facility is not in full compliance with applicable environmental or other laws or regulations, the System attempts to resolve non-compliance through the auditing response process or other management processes. Compliance with existing and proposed regulations also affects the time needed to complete new facilities or to modify present facilities, and it affects System companies' rates, sales, revenues and net income, all in ways that may be substantial but are not readily calculable.
NRC NUCLEAR PLANT LICENSING
The operators of the Millstone 1, 2 and 3 units, the CY, MY and VY and Seabrook 1 all have full term full power operating licenses from the NRC. The following table sets forth the current license expiration dates for each unit:
Operating License Unit Expiration Date (*)
Millstone 1 October 6, 2010 Millstone 2 July 31, 2015 Millstone 3 November 25, 2025 Seabrook 1 October 17, 2026 CY June 29, 2007 MY October 21, 2008 VY March 21, 2012 _________________________ (*) For all units except Seabrook 1 and MY, the current operating license expires 40 years from the date the operating licensee was issued. The Seabrook license expires 40 years from the date on which the NRC issued a license for the unit to load nuclear fuel, which was about 3 1/2 years before the full power operating license was issued. MY's operating license expires 40 years from the date the construction license was issued, which was about four years before the operating license was issued. The System will determine at the appropriate time whether to seek to recapture these periods and add them to the operating license terms for those units.
YAEC had been working with the NRC on a preliminary analysis to extend the license expiration date for Yankee Rowe from 2000 to 2020, but that effort was suspended when the unit was shut down for evaluation. YAEC received a "possession only" license from the NRC in August 1992. See "Electric Operations - Nuclear Generation - Operations - Yankee Units" for further information on the decision to shut down the Yankee Rowe unit permanently.
Currently the NRC issues 40-year operating licenses to nuclear units. In December 1991, the NRC issued a final rule that establishes the requirements that must be met by an applicant for renewal of a nuclear power plant operating license, the information that must be submitted to the NRC for review, so that the agency can determine whether those requirements have in fact been met, and the application procedures that must be used to obtain an extension of a nuclear plant operating license beyond 40 years. A renewal license may be granted for not more than 20 years beyond the current licensed life. The licensing requirements for a nuclear plant during the renewal term will consist of the plant's current licensing requirements and new commitments to monitor, manage, and correct age-related degradation of plant systems, structures, and components that is unique to the license renewal term but will not encompass the higher licensing standards imposed on new plants. An opportunity for a formal public hearing is provided to permit interested persons to raise contentions on the adequacy of the renewal applicant's proposals to address age-related degradation and compliance with applicable requirements relating to an environmental impact statement. The NRC rule was challenged on antitrust grounds and upheld in the District of Columbia Court of Appeals.
ENVIRONMENTAL REGULATION
GENERAL
The National Environmental Policy Act (NEPA) requires that detailed statements of the environmental effects of major federal actions be prepared by federal agencies. Major federal actions can include licenses or permits issued to the System by FERC, NRC and other federal agencies for construction or operation of generation and transmission facilities. NEPA requires that federal licensing agencies make an independent evaluation of the alternatives and environmental impacts of the proposed actions.
Under Connecticut law, major generation or transmission facilities may not be constructed or significantly modified without a certificate of environmental compatibility and public need from the Connecticut Siting Council (CSC). After public hearings, CSC may issue the certificate, which addresses the public need for the facility and probable environmental impact of the facility and may impose specific conditions for protection of the environment.
In New Hampshire, construction of major new generation or transmission facilities, or sizeable additions to existing facilities, requires a certificate of site and facility from the New Hampshire Site Evaluation Committee (NHSEC) and NHPUC under the state's energy facility siting law. In addition to review by all state agencies having jurisdiction over any aspect of the construction or operation of the proposed facility, the law requires full review by NHSEC of the environmental impact of the proposed site or route after allowing for public comment and conducting public hearings. Issuance of a certificate requires, among other findings, a finding that the proposed site and facility will not have an unreasonable adverse effect on environmental values.
Massachusetts law requires all state agencies to determine the environmental impact of any projects proposed by private companies requiring state permits, or involving state funding or participation. Massachusetts state agencies are required to make a finding that all feasible measures have been taken to avoid or minimize the environmental impact of the project. In certain instances, Massachusetts law also requires the preparation and dissemination, among various state agencies, of an environmental impact report for the proposed project. Major generation or transmission facilities may not be constructed or significantly modified without approval by the Massachusetts Energy Facilities Siting Board; new transmission facilities also require approval by the DPU.
The System anticipates that additional environmental legislation will be seriously considered by Congress and state legislatures in the coming years. The issues of global warming, air pollution, hazardous waste handling and disposal and water pollution control are receiving a significant amount of public and political attention and are likely areas for federal or state legislative activity in the near future. Until and unless any such legislation is enacted and implementing regulations are issued, the effects on the System cannot be determined. 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. Such laws and regulations may also require substantial investments that are not included in the estimated construction budget set forth herein. 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 EPA specifying the allowable quantity and characteristics of its effluent. To obtain an NPDES permit, a discharger must meet technology-based and biologically-based effluent standards and must also demonstrate that its effluent will not cause a violation of established standards for the quality of the receiving waters. Connecticut, Massachusetts and New Hampshire regulations contain similar permit requirements and these states can impose more stringent requirements.
All of the System's steam-electric generating plants have NPDES permits in effect. Any of the permits may be reopened to incorporate more stringent regulations adopted by EPA or state environmental agencies. Compliance with NPDES and state water discharge permit requirements 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, 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. This study was submitted to CDEP in January 1993 and includes analyses of the costs and benefits of each alternative considered. The costs ranged from $1.8 million to $519 million. The study concluded that the substantial incremental costs of each of the alternatives studied are not justified by the small benefits to the winter flounder population. In a letter dated January 14, 1994, CDEP approved the report requiring only 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 NHDES discharge 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 new permit may require PSNH to perform further biological studies because significant numbers of migratory fish are being restored to lower reaches of the Merrimack River. Should the studies 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 to be 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 certain facilities. The requirements apply to 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 non-transportation-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. EPA and the Coast Guard have reviewed these plans and accepted the information provided in them as certification of contracted resources for response to a worst case discharge. The Coast Guard expects to complete its review process by February 17, 1995, and EPA by August 18, 1995. Both agencies have authorized continued operation pending 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
Under the federal Clean Air Act, EPA has promulgated national ambient air quality standards for certain air pollutants, including sulfur dioxide, particulate matter, nitrogen oxides and ozone. EPA has approved a Connecticut implementation plan prepared by CDEP, a New Hampshire plan prepared by NHDES and a Massachusetts plan prepared by MDEP for the achievement and maintenance of these standards. The Connecticut, New Hampshire and Massachusetts plans impose limits on the amounts of various airborne pollutants that can be emitted from utility boilers.
Under the Clean Air Act, emissions from new or substantially modified sources are limited by new source performance standards and very strict technology-based emission limits.
The Clean Air Act Amendments of 1990 (CAAA) made extensive revisions and additions to the 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.
NOX. The CAAA identifies NOX emissions as a precursor of ambient ozone for the northeastern region of the United States, much of which is in violation of the ambient air quality standard for ozone. Pursuant to the CAAA, Connecticut, New Hampshire and Massachusetts must implement plans to address ozone nonattainment. Probable actions include additional NOX controls that could impose costs on the System's generating units. The capital cost to comply with 1995's anticipated Phase I requirements is expected to approximate $10 million for CL&P, $11 million for PSNH, $1 million for WMECO and $3 million for HWP, while compliance costs for Phase II, effective in 1999, could be substantially higher depending on the level of NOX reductions required. Costs for meeting the 1999 NOX emission reduction requirements cannot be estimated at this time.
Connecticut and New Hampshire have not as yet issued final regulations to implement NOX reduction requirements, although both have previously indicated that they will attempt to achieve NOX reduction requirements at the lowest possible costs. The System companies are in the process of reviewing compliance strategies and costs and of providing input to state environmental regulators. Massachusetts issued final NOX Reasonably Available Control Technology (RACT) rules in September, 1993.
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 has been 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, however more stringent emission rate limits equivalent to the range of 0.1 to 0.4 pounds of NOX per million Btu are required for the unit by that date.
PSNH recently received an amendment to its Permit to Operate for Merrimack Unit 1 from NHARD to allow the testing of wood chips as a fuel. Testing has begun and if it is successful it may assist PSNH in compliance with the CAAA.
SO2. The CAAA mandates reductions in sulfur dioxide (SO2) emissions to control acid rain. These reductions are to occur in two phases. First, 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. Management plans to meet the requirements of both Phase I and Phase II by burning low sulfur fuels and substituting (i.e. adding) Newington and Mt. Tom stations as Phase I units, if allowed by EPA regulations.
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. These allowances are freely tradable. One allowance entitles a source to emit one ton of SO2 in a year. No unit may emit more SO2 in a particular year than the amount for which it has allowances. The System expects to be allocated allowances by EPA that substantially exceed its expected SO2 emissions for 2000 and subsequent years. In 1993, the System agreed to donate, subject to regulatory approval, 10,000 of its surplus SO2 allowances to the American Lung Association thereby effectively preventing 10,000 tons of SO2 from being emitted into the atmosphere. The System expects to be able to sell some of its surplus allowances. The price of allowances depends on the market. The amount of surplus allowances and the allocation of the revenues received from such sales between ratepayers and shareholders have not been determined.
On February 15, 1993, as required by the CAAA, PSNH filed Phase I Acid Rain Permit Applications for Merrimack Station. In addition, as allowed by the CAAA, PSNH designated its Newington station unit, and HWP designated its Mt. Tom unit, as conditional Phase I substitution units. EPA is currently reviewing whether it will accept Newington and Mt. Tom as substitution units and the number of allowances each will be awarded. All Phase I units, including substitution units accepted by EPA, will be allocated SO2 allowances for the period 1995-1999.
On December 31, 1992, pursuant to Connecticut Public Act 92-106, CL&P filed a report with the Energy and Public Utilities Committee of the Connecticut General Assembly and the DPUC describing its plan for allocation of revenues from sale of SO2 allowances. CL&P proposed that its shareholders receive 20 percent of the proceeds from sales of allowances to compensate for the risks they have taken to reduce CL&P's SO2 emissions and to provide appropriate incentive to CL&P to sell allowances at the maximum price. In 1993 the DPUC approved a proposal by The United Illuminating Company (UI) to grant an option to another utility for the purchase of SO2 allowances, and ruled that shareholders would receive 15 percent of the proceeds from the eventual sale. The DPUC opened a docket and held hearings to review the reports filed by CL&P and UI. This review is addressing development of a policy on allocation between shareholders and ratepayers of SO2 allowance proceeds as well as CL&P's allowance donation.
CDEP's air quality regulations permit CL&P to burn 1.0 percent sulfur oil at oil-fired generating stations in Connecticut, except that 0.5 percent sulfur oil must be burned at Middletown station. Current CDEP policy requires CL&P to use 0.5 percent or lower sulfur oil when replacing older (1.0 percent sulfur oil fueled) plant auxiliary boilers needed for unit start-up and plant space heating. The regulations also permit the burning of coal with a sulfur content of up to 0.7 percent at CL&P's plants, or up to 1.0 percent if a special permit is obtained.
New Hampshire air quality regulations permit PSNH to emit 55,150 tons of SO2 annually. The New Hampshire acid rain control law required a 25 percent reduction in SO2 emissions from the 1979-1982 baseline emissions at PSNH's units, which has been achieved. Compliance with New Hampshire's acid rain control law has brought PSNH very close to compliance with the SO2 emission limits of Phase I of the CAAA. PSNH may need to install additional pollution control equipment or use fuel with lower sulfur content in order to meet the requirements of the CAAA.
The EPA has issued an order requiring modeling of the impact on ambient air quality of SO2 emissions from Merrimack Station. Work on this study has begun and the final results of the modeling are expected to be available in mid-1995. If the modeling study indicates that compliance with the primary ambient air quality standards for SO2 is not being achieved, additional control strategies, possibly including the addition of emission control devices or a higher stack, will be required. Management cannot at this time predict the results of the modeling or estimate the cost of any additional control strategies that may be required.
The Massachusetts air quality regulations permit HWP to burn 1.5 percent sulfur coal with an ash content up to 9 percent at Mt. Tom Station. Coal with a higher ash content can be burned with MDEP approval. Mt. Tom Station is required to reduce sulfur emissions to the equivalent of 1.0 percent sulfur oil if certain air quality monitors show levels of SO2 approaching ambient air quality limits. WMECO's West Springfield station currently burns 1.0 percent sulfur oil or natural gas.
The Massachusetts acid rain control law requires MDEP to adopt regulations to limit future sulfur dioxide emissions. These regulations limit the allowable SO2 emissions from utility power plants and other major fuel burning sources to 1.2 pounds per million BTUs averaged over all of the System's Massachusetts plants, effective January 1, 1995. The System's generating plants in Massachusetts on average emit approximately 1.9 pounds of SO2 per million BTUs. The System expects to meet the new sulfur dioxide limitation by using natural gas and lower sulfur oil and 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 and on NOX limitations imposed by Connecticut and New Hampshire.
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.
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.
Connecticut and New Hampshire have enacted, and Massachusetts is considering, toxic air pollution regulations limiting emissions of numerous substances that may extend beyond those regulated under federal law.
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. One disposal measure involves the System's burning of some waste oil with a low level of PCB contamination (up to 500 parts per million (ppm)) as supplemental fuel at CL&P's Middletown station Unit 3. EPA and CDEP have approved this disposal method.
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. Currently, there are only four such approved incinerators operating in the United States, which has resulted in a sharp rise in the price of disposal through these facilities. The System disposes of solid wastes containing PCBs in secure chemical waste landfills. In 1993, the System incurred costs of approximately $450,000 for disposal of materials at these facilities.
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. Areas of the System currently undergoing removal of asbestos include nuclear, fossil/hydro production, transmission and distribution and facilities operations. The System expects to expend approximately $3.4 million in 1994 on the removal of asbestos in nuclear units, fossil and hydro generating stations and buildings. Even greater costs are likely to be incurred annually in the future if federal and state asbestos regulations become more stringent and the System's need to remove asbestos grows.
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. A change in interpretation of RCRA by EPA now requires that nuclear facilities obtain EPA permits to handle radioactive wastes that are also hazardous under RCRA (so-called mixed wastes). The notifications and applications required by these regulations have been made by all units to which these regulations apply. 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 has discontinued operation of surface impoundments in its four Connecticut wastewater treatment facilities used to treat hazardous waste. This is because CL&P was unable to obtain variances from EPA to exempt the facilities from the double lining requirement under the 1984 RCRA amendments.
CL&P has constructed replacement above-ground concrete tanks at an estimated cost of approximately $22 million. It is expected that in early 1994, EPA and DEP will approve clean closure for CL&P's Montville Station's impoundment. Accordingly, CL&P will no longer be required to maintain liability insurance or financial assurance for closure and post-closure for this former impoundment site. EPA's final approval of the closure of the remaining three surface impoundments is pending. The System estimates that it will incur approximately $2 million in costs of 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. The System has about 130 underground storage tanks that are used primarily for gasoline, diesel, house-heating and fuel oil. To reduce its environmental and financial liabilities, the System has begun implementing a policy calling for the permanent removal of 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 and oils 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 harm. The System 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.
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 recent 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. Management believes that the System companies are in compliance with these reporting and notification requirements.
The System is or has recently been involved in eight Superfund sites. Three of these sites are in Connecticut, one is in Kentucky, one is in West Virginia and three are 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 Statement No. 5, 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.
At two Connecticut sites, the Beacon Heights and Laurel Park landfills, the major parties formed coalitions to clean the sites and settled their suits with EPA and CDEP. The coalitions then attempted to join as defendants a large number of potential contributors, including "Northeast Utilities (Connecticut Light and Power)." Litigation on both sites was consolidated in a single case in the federal district court. In January 1993, Judge Dorsey denied the motion of the Laurel Park Coalition to join NU (CL&P). In December 1993, Judge Dorsey dismissed the claims of Beacon Heights Coalition against many of the defendants and directed the coalition to indicate which remaining defendants it intended to pursue claims against. In January 1994, the Beacon Heights Coalition filed a response listing NU (CL&P) as a defendant they would not continue to pursue. As a result of Judge Dorsey's rulings and the coalition's actions, it is not likely that CL&P will incur any cleanup costs for these sites.
In June, 1993, EPA notified the System that it was a Potentially Responsible Party (PRP) at the Solvents Recovery Service of New England site in Southington, Connecticut. PSNH is a de minimis PRP at this site and does not expect its cost to be substantial.
At the Maxey Flats nuclear waste disposal site in Fleming County, Kentucky, EPA has issued a notice of potential liability to NNECO and CYAPC. The System had sent a substantial volume of LLRW from Millstone 1, Millstone 2 and CY to this site. CL&P and WMECO had previously recorded a liability for future remediation costs for this site based on System estimates. To date, the costs have not been material with respect to their earnings or financial positions.
In September 1991, EPA issued its record of decision for the Maxey Flats nuclear waste disposal site. The EPA-approved remedy requires pumping and treatment of leachate, installing of an initial cap, allowing materials in the trenches to settle and ultimately constructing a permanent cap. EPA estimated that the cost of the remedy is approximately $33.5 million. Based on that estimate and the volume contributed, the System's share would be approximately $0.5 million. However, the System believes that the cost of the remedy could be substantially higher. The System estimates that its total cost for cleanup could be approximately $1-$2 million. EPA provided an opportunity for PRPs, including certain System companies, to enter into a consent decree with EPA under which each PRP would reimburse EPA for its past costs and would undertake remedial action at the site or pay the costs of EPA undertaking remedial action.
On October 20, 1992, 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, made a settlement offer to EPA involving a commitment to perform a substantial portion of the remedial work required by EPA in its record of decision. On that same date, the Commonwealth of Kentucky made a settlement offer. EPA rejected the settlement offers in December 1992, but gave the parties an additional 60 days to make a "good faith" offer. On March 16, 1993, the PRP Steering Committee and the federal government agencies made a revised offer to EPA. Since then all parties have been actively involved in settlement negotiations.
PSNH has settled with EPA and other PRPs at sites in West Virginia and Kingston, New Hampshire. PSNH paid approximately $33,700 to cash out of these sites.
PSNH has committed approximately $280,000 as its share of the costs to clean up municipal landfills in Dover and North Hampton, New Hampshire. Some additional costs may be incurred at these sites but they are not expected to be significant.
Other New Hampshire sites include municipal landfills in Somersworth and Peterborough, and the Dover Point site owned by PSNH in Dover, New Hampshire.
PSNH's liability at the landfills is not expected to be significant and its liability at the Dover Point site cannot be estimated at this time.
PSNH contacted NHDES in December 1993 concerning possible coal tar contamination in the headwater of Lake Winnipesaukee near an area where PSNH formerly owned and operated a coal gasification plant which was sold in 1945. PSNH agreed to conduct an historical review and provide a report to NHDES in February 1994. PSNH, along with two other identified PRPs, most likely will be conducting a site investigation in the spring of 1994.
In 1987, CDEP published a list of 567 hazardous waste disposal sites in Connecticut. The System owns two sites on this list. The System has spent approximately $0.5 million 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. Should future site remediation become necessary, the level of cleanup will be established in cooperation with CDEP. Connecticut 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; however, CL&P is focusing on institutional and engineering controls, such as capping and paving, which would reduce the potential health risks and secure the site. The estimated costs of institutional controls range from $2 million to $3 million.
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). As a result of those investigations, ten properties were identified for which negative declarations under the Property Transfer Act could not be filed. A negative declaration is a statement that there has been no discharge of hazardous wastes at the site, or that if there was such a discharge, it has been cleaned up or determined to pose no threat to health, safety or the environment and is being managed lawfully. Of the ten sites, CL&P agreed to accept liability for required cleanup for the three sites it retained. At one location, CL&P and Yankee Gas share the site and any liability for any required cleanup. Yankee Gas accepted liability for any required cleanup of the other sites. 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.
In Massachusetts, System companies have been designated by MDEP as PRPs for ten sites under MDEP's hazardous waste and spill remediation program. The System does not expect that its share of the remaining remediation costs for any of these sites will be material. At some of these sites, the System is responsible for only a small portion or none of the hazardous wastes. For some of these and for other sites, the total remediation costs are not expected to be material. At one of the sites, the System has spent approximately $2 million for cleanup and it expects to incur approximately $250,000 for the remaining remediation costs.
HWP has been identified by MDEP as a PRP in a coal tar site in Holyoke, Massachusetts. HWP owned and operated the Holyoke Gas Works from 1859 to 1902. It was sold to the city of Holyoke and operated by its Gas and Electric Department (HG&E) from 1902 to 1951. Currently, one third of the two acre property is owned by HG&E, with the remaining portion owned by a construction company. 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 classified both the land and river deposit areas as Tier I 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. Although HWP denies that it is a PRP, it has cooperated with the agencies in investigating this problem. 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 $200,000 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 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 expects to 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. On the basis of scientific reviews of these reports conducted by various state, federal and international panels, management does not believe that a causal relationship has been established or that significant capital expenditures are appropriate to minimize unsubstantiated risks. 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.
Epidemiological studies, rather than laboratory studies, have been primarily responsible for increased scientific interest in and public concern over EMF exposures in the past decade. New epidemiological study results from international researchers were released and publicized in late-1992 and in 1993, but these only added to a picture of inconsistency from previous studies. Researchers from Sweden and Denmark concluded that their statistical results support the hypothesis that EMF may be a causative factor in certain types of cancer (although they disagreed on which types), while researchers from Finland and Greece found no evidence to support such a hypothesis. These researchers, as well as scientific review panels considering all significant EMF epidemiological and laboratory research to date, all agree that current information remains inconclusive, inconsistent and insufficient for risk assessment of EMF exposures. NU is closely monitoring research and government policy developments.
In 1993, there were several notable events on the federal government level regarding EMF. The EPA has indefinitely postponed completion of a report on EMF, citing as its reasons high costs and the unlikelihood of shedding new light on the issue. Instead, it now plans to issue a 30-page "summary of science" in early 1994. In a related development, the Department of Energy has initiated a scientific review of EMF research by the National Academy of Sciences. Also on the federal level, the National EMF Research and Public Information Dissemination Program (created by the Energy Policy Act) moved forward in 1993 by establishing a federal interagency committee and an advisory committee, and by soliciting the required non-federal matching funds (through The Edison Electric Institute, NU will be making a voluntary contribution of approximately $62,000 for each year of the five-year program).
The Connecticut Interagency EMF Task Force (Task Force) provided reports to the state legislature in March 1993 and in January 1994. The Task Force recognizes and supports the need for more research, and has suggested 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. Finally, the Connecticut Siting Council adopted a set of EMF "best management practices" in February 1993, which must now be considered in the justification, siting and design of new transmission lines and substations. EMF has become increasingly important as a factor in facility siting decisions in many states.
Several bills were introduced in Massachusetts in January 1993, and were last reported to be pending before various legislative committees. It is not known whether there will be further action on the bills, which would require certain disclosures to real estate purchasers and utility employees, a scientific literature review, establishment of a fund to reduce certain field exposures, identification of schools and day care centers within 500 feet of transmission lines and development of EMF regulations. No action was taken on EMF bills previously pending in 1992.
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, is 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. Any hydroelectric project so licensed is subject to recapture by the United States for licensing to others after expiration of the license 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. Licenses are customarily conditioned on the licensee's development of recreational and other non-power uses at each licensed project. Conditions may be imposed with respect to low flow augmentation of streams and fish passage facilities.
On September 28, 1993, the United States Fish and Wildlife Service (FWS) was petitioned to list the anadromous Atlantic salmon (Salmo salar) as an endangered species in the United States. After a 90-day review, the petition was found to be complete and was accepted. The National Marine Fisheries Service and FWS were given joint jurisdiction over this petition. Within the next 12 months, these agencies will decide if the petition is warranted. If salmon are listed as an endangered species, the System may be required to take a number of actions including increasing spillage over some dams during the salmon migration period resulting in loss of generation capacity at the affected hydroelectric facilities; modifying spillways to accommodate safe fish passage; curtailing pumping at Northfield Mountain during the salmon migration period; improving upstream and downstream passage facilities at all hydroelectric dams on the Connecticut and Merrimack Rivers; and modifying intake structures and curtailing operations during salmon migration periods at certain of the System's thermal structures. Although these are all possible implications of a listing, the System cannot estimate the impact on System facilities at this time.
The System is continuing to conduct studies on the Connecticut River in fulfillment of the Memorandum of Agreement (MOA) concerning downstream passage of anadromous fishes (Atlantic salmon, American shad and blueback herring). The MOA was signed by the System and the Connecticut River Atlantic Salmon Commission and its member agencies in 1990. The System conducted studies in 1991 and 1992 of the entrainment of salmon smolts and juvenile shad and herring in water pumped to the upper reservoir of the Northfield Mountain Pumped Storage Project. Studies of entrainment of shad and herring indicated that Northfield's impact on these species is low, and further studies have not been conducted.
Studies of salmon smolts, however, indicated the potential for unacceptable losses of smolts due to entrainment, but the results also indicated that firm conclusions could not be drawn. Accordingly, the System conducted a more definitive study indicating that about 10 percent of the 1993 smolt run was entrained at Northfield. The System will continue to pursue practical techniques to reduce salmon smolt entrainment at Northfield and has agreed to alter its 1994 maintenance schedule to reduce the amount of time when all four pump/turbine units will be pumping simultaneously during the smolt migration period. Should the system be unable to reduce smolt entrainment through operational changes or practical exclusion techniques, substantial additional costs are possible. The total cost cannot be determined at this time.
The System operating companies hold licenses granted under Part I of the Federal Power Act for the operation and maintenance of thirteen existing hydroelectric projects, four of which are in Massachusetts (Northfield, Turners Falls, Gardners Falls and Holyoke [river and canal units]), three of which are in Connecticut (Scotland, Housatonic [encompassing Bulls Bridge, Rocky River, Shepaug and Stevenson] and Falls Village) and six of which are in New Hampshire (Merrimack [encompassing Garvins Falls, Hooksett and Amoskeag], Smith, Ayers Island, Eastman Falls, Canaan and Gorham).
In 1992, FERC issued orders exempting from licensing WMECO's four Chicopee River projects: Dwight, Indian Orchard, Putts Bridge and Red Bridge. To date, FERC has not claimed jurisdiction over CL&P's Bantam, Robertsville, Taftville and Tunnel Projects or PSNH's Jackman project.
Four of the System's FERC licenses expired at the end of 1993 (Gardners Falls, Ayers Island, Gorham and Smith). Relicensing efforts have been under way for these projects for several years. As no third parties have filed competing license applications with FERC for these projects, it is highly likely that FERC will grant renewal licenses for these projects to the System.
However, certain operating, environmental and/or recreational conditions may be placed on these licenses. Because FERC was unable to complete its relicensing process prior to the December 31, 1993 expiration of these licenses, under the provision of section 15 of the Federal Power Act, FERC has issued one-year extensions to each of these licensees. FERC will continue to issue annual licenses until it completes the relicensing process.
EMPLOYEES
As of December 31, 1993, the System companies had approximately 9,697 full and part time employees on their payrolls, of which approximately 2,697 were employed by CL&P, approximately 1,452 by PSNH, approximately 656 by WMECO, approximately 119 by HWP, approximately 1,252 by NNECO, approximately 2,584 by NUSCO and approximately 937 by North Atlantic. NU and NAEC have no employees. Approximately 2,242 employees of CL&P, PSNH, WMECO and HWP are covered by union agreements, which expire between October 1994 and May 1996. Certain employees of North Atlantic negotiated a union contract in 1993.
On August 3, 1993, the System announced that it intended to reduce its total workforce by 600 to 700 positions and offered a voluntary early retirement program to about 800 eligible employees. The program was available generally to all nonbargaining unit employees of NU's subsidiaries, NUSCO, CL&P, WMECO, HWP, PSNH and NAESCO, who would be at least age 55 with ten years of service as of November 1, 1993. Most nuclear-related job classifications at NUSCO and NAESCO were not eligible. The program enhanced pension benefits by adding an additional three years to age and service for the purpose of calculating pension benefits and early retirement reduction factors, as well as providing a supplemental payment to employees who retired prior to becoming eligible for social security benefits. Each program participant has retired or will retire on a date to be established by the employer between November 1, 1993 and November 1, 1994. A similar program was offered to approximately 300 bargaining unit employees working for System companies and 12 employees of NEPOOL/NEPEX. The workforce reduction affected approximately 811 employees, of which 498 individuals accepted the early retirement program and another 313 individuals who were involuntarily terminated. Involuntarily terminated employees were eligible to receive a lump sum severance payment of up to a maximum of 52 weeks salary, depending on years of credited service. In addition, as part of the System's reorganization of its Connecticut-based nuclear organization, 32 employees were involuntarily terminated through January 12, 1994. For more information on the reorganization see "Nuclear Generation - Operations - Nuclear Performance Improvement Initiatives." The total cost of the workforce reduction program and the nuclear reorganization was approximately $38 million, including pension, severance and other benefits.
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 35.98201 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's companies' lines are located on or under streets or highways, or on properties either owned, leased, or in which the company has appropriate rights, easements, or permits from the owners.
CL&P's properties are subject to the liens of CL&P's first mortgage indenture and, with respect to properties formerly owned by The Hartford Electric Light Company (HELCO), to the lien of HELCO's 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 Bond 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 ones 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' properties are well maintained and are in good operating condition.
Notes:
1. Until 1991, awards under the short-term programs of the Northeast tilities Executive Incentive Compensation Program (EICP) were made in restricted stock. In 1991, the Northeast Utilities Executive Incentive Plan (EIP) was adopted, which did not require restricted stock awards. Awards under the 1991 and 1992 short-term programs under the EIP were paid in 1992 and 1993, respectively, in the form of unrestricted stock and, in accordance with the requirements of the SEC, are included as "bonus" in the years earned.
2. The five executive officers listed in the table above each received an award of restricted stock in May, 1991 (which vested in January, 1993), under the EICP. The number of shares in each such award is shown below. All restricted stock awards under the EICP vested prior to December 31, 1993.
Name Shares
B. M. Fox 1,807 W. B. Ellis 2,585 J. F. Opeka 1,349 R. E. Busch 1,090 J. P. Cagnetta 847
3. "All Other Compensation" consists of employer matching contributions under the Northeast Utilities Service Company Supplemental Retirement and Savings Plan (401(k) Plan), generally available to all eligible employees. In 1993, the employer match for non-union employees was 100 percent of the first three percent of compensation contributed on a before-tax basis.
4. Awards under the short-term program of the EIP have typically been made by NU's 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. Opeka, Busch and Cagnetta 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 - $180,780; Mr. Ellis - $160,693; Mr. Busch - $64,946; Mr. Opeka - $64,946; and Dr. Cagnetta - $43,828.
5. Mr. Fox served as President and Chief Operating Officer of CL&P, NAEC and WMECO and Vice Chairman and Chief Operating Officers of PSNH until July 1, 1993, when he became President and Chief Executive Officer of CL&P, NAEC and WMECO and Vice Chairman and Chief Executive Officer of PSNH. Mr. Ellis served as Chairman and Chief Executive Officer of these companies until July 1, 1993, when he became Chairman. Amounts listed in the "Long Term Incentive Program" column of the Summary Compensation Table for 1993 were received by these individuals prior to their change in responsibilities. $267,500 of Mr. Ellis's 1993 salary was paid prior to July 1, 1993, while he was Chief Executive Officer, and $253,750 was paid after July 1, 1993. $217,500 of Mr. Fox's 1993 salary was paid prior to July 1, 1993, and $261,275 was paid after Mr. Fox became Chief Executive Officer on July 1, 1993.
PENSION BENEFITS
The following table shows the estimated annual retirement benefits payable to an executive officer of NU, CL&P, WMECO, PSNH and NAEC 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 NU Board of Trustees to participate in the target benefit and who remain in the employ of NU companies until at least age 60 (unless the NU Board of Trustees sets an earlier age). Each of the executive officers of NU, CL&P, WMECO, PSNH and NAEC 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.
Years of Credited Service Final Average ------------------------------------------------------ Compensation 15 20 25 30 35 - ------------------ ------------------------------------------------------ $ 125,000 $ 45,000 $ 60,000 $ 75,000 $ 75,000 $ 75,000 $ 150,000 $ 54,000 $ 72,000 $ 90,000 $ 90,000 $ 90,000 $ 175,000 $ 63,000 $ 84,000 $105,000 $105,000 $105,000 $ 200,000 $ 72,000 $ 96,000 $120,000 $120,000 $120,000 $ 225,000 $ 81,000 $108,000 $135,000 $135,000 $135,000 $ 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
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 Northeast Utilities Service Company Supplemental Retirement and Savings Plan (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 NU and its subsidiaries under long term disability plans and policies.
As of December 31, 1993, the five executive officers named in the Summary Compensation Table above had the following years of credited service for retirement compensation purposes: Mr. Fox - 29, Mr. Ellis - 17, Mr. Opeka - 23, Mr. Busch - 20 and Dr. Cagnetta - 21. Assuming that retirement were to occur at age 65 for these officers, retirement would occur with 43, 29, 35, 38 and 25 years of credited service, respectively.
NU has entered into agreements with Messrs. Ellis and Fox to provide for an orderly management succession. The agreement with Mr. Ellis calls for him to work with the NU Board of Trustees 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 of NU, CL&P, WMECO, PSNH and NAEC 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 NU 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 NU 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 NU's Committee on Organization, Compensation and Board Affairs and the NU Board of Trustees in accordance with their customary practices.
Item 12. Security Ownership of Certain Beneficial Owners and Management
NU.
Incorporated herein by reference are pages 5 through 12 of the definitive proxy statement for solicitation of proxies by NU's Board of Trustees, dated April 1, 1994 and filed with the Commission pursuant to Rule 14a-6 under the Act.
CL&P, PSNH, WMECO and NAEC.
As of February 28, 1994, the Directors of CL&P, PSNH, WMECO and NAEC, beneficially owned the following number of shares of each class of equity securities of NU. No equity securities of CL&P, PSNH or WMECO are owned by the Directors and Executive Officers.
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) (621) 4,271 shares NU Common Robert E. Busch (772) 6,054 shares NU Common John P. Cagnetta (4) (581) 3,979 shares NU Common John C. Collins (5) 0 shares NU Common William B. Ellis (6) (1,259) 14,837 shares NU Common Ted C. Feigenbaum(7) 151 shares NU Common Bernard M. Fox (8) (1,072) 17,428 shares NU Common William T. Frain, Jr. 885 shares NU Common Cheryl W. Grise (221) 1,349 shares NU Common John B. Keane (9) (368) 1,146 shares NU Common Francis L. Kinney (10) (303) 3,781 shares NU Common Gerald Letendre (5) 0 shares NU Common Hugh C. MacKenzie (4)(11) (779) 4,277 shares NU Common Jane E. Newman (5) 0 shares NU Common Dale F. Nitzschke (5) 0 shares NU Common John W. Noyes (658) 2,789 shares NU Common John F. Opeka (4)(12) (1,075) 16,463 shares NU Common Robert P. Wax (5) (651) 1,436 shares
Amount beneficially owned by Directors and Executive Officers as a group - CL&P (7,709) 77,259 shares - PSNH (6,790) 69,299 shares - WMECO (7,709) 77,259 shares - NAEC (7,088) 73,139 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, 1994 there were 134,208,461 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) Mr. Opeka and Dr. Cagnetta are not officers of PSNH, but each in his capacity as an officer (with the stated title) of NUSCO, an affiliate of PSNH, performs policy-making functions for PSNH.
(5) Messrs. Collins, Letendre, Nitzschke and Wax and Ms. Newman areDirectors of PSNH only.
(6) Mr. Ellis shares voting and investment power with his wife for 1,117 shares.
(7) Mr. Feigenbaum is a Director and an Executive Officer of NAEC only.
(8) Mr. Fox shares voting and investment power with his wife for 3,031 of these shares. In addition, Mr. Fox's wife has sole voting and investment power for 140 shares, as to which Mr. Fox disclaims beneficial ownership.
(9) Mr. Keane is a Director of CL&P, WMECO and NAEC only.
(10) Mr. Kinney shares voting and investment power with his wife for 2,155 shares.
(11) Mr. MacKenzie shares voting and investment power with his wife for 1,259 shares.
(12) Mr. Opeka shares voting and investment power with his wife for 1,718 shares.
Item 13. Certain Relationships and Related Transactions
NU.
Incorporated herein by reference is page 14 of the definitive proxy statement for solicitation of proxies by NU's Board of Trustees, dated April 1, 1994 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 1993 with respect to CL&P, PSNH, WMECO and NAEC.
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K
(a) 1. Financial Statements:
The Report of Independent Public Accountants and financial statements of NU, CL&P, PSNH, WMECO, and NAEC are hereby incorporated by reference and made a part of this report (see "Item 8. Financial Statements and Supplementary Data").
Reports of Independent Public Accountants on Schedules S-1
Consents of Independent Public Accountants S-3
2. Schedules:
Financial Statement Schedules for NU (Parent), NU and Subsidiaries, CL&P, PSNH, WMECO, and NAEC are listed in the Index to Financial Statement Schedules S-5
3. Exhibits Index E-1
(b) Reports on Form 8-K:
During the fourth quarter of 1993, the companies filed Form 8-Ks dated December 2, 1993 disclosing the following:
o On December 2, 1993, the Northeast Utilities system announced a reorganization of its corporate structure.
o On December 3, 1993, NNECO was informed by the NRC that it was being assessed a civil penalty in response to repair activities at Millstone 2.
In addition, the Form 8-K dated December 2, 1993 which was filed by PSNH also discussed the following:
o On June 8, 1992, PSNH changed its independent public accountant.
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 18, 1994 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 18, 1994 Trustee and Chairman /s/ William B. Ellis - -------------- of the Board ------------------------- William B. Ellis
March 18, 1994 Trustee, President /s/ Bernard M. Fox - -------------- and Chief Executive ------------------------- Officer Bernard M. Fox
March 18, 1994 Executive Vice /s/ Robert E. Busch - -------------- President and Chief ------------------------- Financial Officer Robert E. Busch
March 18, 1994 Vice President and /s/ John B. Keane - -------------- Treasurer ------------------------- John B. Keane
March 18, 1994 Vice President and /s/ John W. Noyes - -------------- Controller ------------------------- John W. Noyes
NORTHEAST UTILITIES
SIGNATURES (CONT'D)
Date Title Signature ---- ----- ---------
March 18, 1994 Trustee /s/ Cotton Mather Cleveland - -------------- --------------------------- Cotton Mather Cleveland
March 18, 1994 Trustee /s/ George David - -------------- --------------------------- George David
March 18, 1994 Trustee /s/ Donald J. Donahue - -------------- --------------------------- Donald J. Donahue
March 18, 1994 Trustee /s/ Eugene D. Jones - -------------- --------------------------- Eugene D. Jones
March 18, 1994 Trustee /s/ Elizabeth T. Kennan - -------------- --------------------------- Elizabeth T. Kennan
Trustee - -------------- --------------------------- Denham C. Lunt, Jr.
March 18, 1994 Trustee /s/ William J. Pape II - -------------- --------------------------- William J. Pape II
March 18, 1994 Trustee /s/ Robert E. Patricelli - -------------- --------------------------- Robert E. Patricelli
Trustee - -------------- --------------------------- Norman C. Rasmussen
Trustee - -------------- --------------------------- 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 18, 1994 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 18, 1994 Chairman and Director /s/ William B. Ellis - -------------- -------------------------- William B. Ellis
March 18, 1994 Vice Chairman and /s/ Bernard M. Fox - -------------- Director -------------------------- Bernard M. Fox
March 18, 1994 President and Director /s/ Hugh C. MacKenzie - -------------- -------------------------- Hugh C. MacKenzie
March 18, 1994 Executive Vice /s/ Robert E. Busch - -------------- President, Chief -------------------------- Financial Officer Robert E. Busch and Director
March 18, 1994 Vice President and /s/ John W. Noyes - -------------- Controller -------------------------- John W. Noyes
THE CONNECTICUT LIGHT AND POWER COMPANY
SIGNATURES (CONT'D)
Date Title Signature ---- ----- ---------
- ------------------- Director -------------------------- Robert G. Abair
March 18, 1994 Director /s/ John P. Cagnetta - ------------------- -------------------------- John P. Cagnetta
March 18, 1994 Director /s/ William T. Frain, Jr. - ------------------- -------------------------- William T. Frain, Jr.
March 18, 1994 Director /s/ Cheryl W. Grise - ------------------- ----------------------- Cheryl W. Grise
March 18, 1994 Director /s/ John B. Keane - ------------------- ----------------------- John B. Keane
March 18, 1994 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 18, 1994 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 18, 1994 Chairman and Director /s/ William B. Ellis - -------------- -------------------------- William B. Ellis
March 18, 1994 Vice Chairman, Chief /s/ Bernard M. Fox - -------------- Executive Officer and -------------------------- Director Bernard M. Fox
March 18, 1994 President, Chief /s/ William T. Frain, Jr. - -------------- Operating Officer -------------------------- and Director William T. Frain, Jr.
March 18, 1994 Executive Vice /s/ Robert E. Busch - -------------- President, Chief -------------------------- Financial Officer Robert E. Busch and Director
March 18, 1994 Vice President and /s/ John W. Noyes - -------------- Controller -------------------------- John W. Noyes
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
SIGNATURES (CONT'D)
Date Title Signature ---- ----- ---------
March 18, 1994 Director /s/ John C. Collins - ------------------- -------------------------- John C. Collins
March 18, 1994 Director /s/ Gerald Letendre - ------------------- -------------------------- Gerald Letendre
March 18, 1994 Director /s/ Hugh C. MacKenzie - ------------------- -------------------------- Hugh C. MacKenzie
March 18, 1994 Director /s/ Jane E. Newman - ------------------- -------------------------- Jane E. Newman
March 18, 1994 Director /s/ Dale S. Nitzschke - ------------------- -------------------------- Dale S. Nitzschke
March 18, 1994 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 18, 1994 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 18, 1994 Chairman and Director /s/ William B. Ellis - -------------- -------------------------- William B. Ellis
March 18, 1994 Vice Chairman and /s/ Bernard M. Fox - -------------- Director -------------------------- Bernard M. Fox
March 18, 1994 President and Director /s/ Hugh C. MacKenzie - -------------- -------------------------- Hugh C. MacKenzie
March 18, 1994 Executive Vice /s/ Robert E. Busch - -------------- President, Chief -------------------------- Financial Officer Robert E. Busch and Director
March 18, 1994 Vice President and /s/ John W. Noyes - -------------- Controller -------------------------- John W. Noyes
WESTERN MASSACHUSETTS ELECTRIC COMPANY
SIGNATURES (CONT'D)
Date Title Signature ---- ----- ---------
- ------------------- Director -------------------------- Robert G. Abair
March 18, 1994 Director /s/ John P. Cagnetta - ------------------- -------------------------- John P. Cagnetta
March 18, 1994 Director /s/ William T. Frain, Jr. - ------------------- -------------------------- William T. Frain, Jr.
March 18, 1994 Director /s/ Cheryl W. Grise - ------------------- ----------------------- Cheryl W. Grise
March 18, 1994 Director /s/ John B. Keane - ------------------- ----------------------- John B. Keane
March 18, 1994 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 18, 1994 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 18, 1994 Chairman and Director /s/ William B. Ellis - -------------- -------------------------- William B. Ellis
March 18, 1994 Vice Chairman, Chief /s/ Bernard M. Fox - -------------- Executive Officer and -------------------------- Director Bernard M. Fox
March 18, 1994 President, Chief /s/ Robert E. Busch - -------------- Operating Officer -------------------------- and Director Robert E. Busch
March 18, 1994 Vice President and /s/ John W. Noyes - -------------- Controller -------------------------- John W. Noyes
NORTH ATLANTIC ENERGY CORPORATION
SIGNATURES (CONT'D)
Date Title Signature ---- ----- ---------
March 18, 1994 Director /s/ John P. Cagnetta - -------------- -------------------------- John P. Cagnetta
- -------------- Director -------------------------- Ted C. Feigenbaum
March 18, 1994 Director /s/ William T. Frain. Jr. - -------------- -------------------------- William T. Frain, Jr.
March 18, 1994 Director /s/ Cheryl W. Grise - -------------- -------------------------- Cheryl W. Grise
March 18, 1994 Director /s/ John B. Keane - -------------- -------------------------- John B. Keane
March 18, 1994 Director /s/ Hugh C. MacKenzie - -------------- -------------------------- Hugh C. MacKenzie
March 18, 1994 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 18, 1994. 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, income taxes, and employee stock ownership plans, as applicable to each company, as explained in Note 1 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 index to financial statement schedules are the responsibility of each company's management and 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. The 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 & CO.
ARTHUR ANDERSEN & CO.
Hartford, Connecticut February 18, 1994
S-1
INDEPENDENT AUDITORS' REPORT ON SCHEDULES
The Board of Directors Public Service Company of New Hampshire:
Under date of February 7, 1992, we reported on the balance sheet and statement of capitalization of Public Service Company of New Hampshire as of December 31, 1991 (not presented in the 1993 annual report to stockholders) and the related statements of income, cash flows and common stock equity for the periods January 1, 1991 to May 15, 1991 and May 16, 1991 to December 31, 1991, as contained in the annual report to stockholders of Public Service Company for the year 1993. These financial statements and our report thereon are incorporated by reference herein. In connection with our audits of the aforementioned financial statements, we have also audited the related financial statement schedules as listed in the accompanying index. These financial statement schedules are the responsibility of the Company's management. Our responsiblity is to express an opinion on these financial statement schedules based on our audit.
In our opinion, such financial statement schedules, when considered in relation to the basic financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
/s/ KPMG Peat Marwick
KPMG Peat Marwick
Boston, Massachusetts February 7, 1992
S-2
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. 33-13444, No. 33-46291 , No. 33-59430, and No. 33-50853 of The Connecticut Light and Power Company, No. 33-34886, No. 33-51185 and No. 33-25619 of Western Massachusetts Electric Company, and No. 33-34622 and No. 33-40156 of Northeast Utilities.
/s/ ARTHUR ANDERSEN & CO.
ARTHUR ANDERSEN & CO.
Hartford, Connecticut March 18, 1994
S-3
INDEPENDENT AUDITORS' CONSENT
The Board of Directors Public Service Company of New Hampshire:
We consent to the use of our reports included or incorporated by reference herein.
/s/ KPMG Peat Marwick
KPMG Peat Marwick
Boston, Massaschusetts March 18, 1994
S-4
INDEX TO FINANCIAL STATEMENT SCHEDULES
Schedule Page - -------- ----
III. Financial Information of Registrant:
Northeast Utilities (Parent) Balance Sheets 1993 and 1992 S-7
Northeast Utilities (Parent) Statements of Income 1993, 1992, and 1991 S-8
Northeast Utilities (Parent) Statements of Cash Flows 1993, 1992, and 1991 S-9
V. Utility Plant 1993, 1992, and 1991:
Northeast Utilities and Subsidiaries S-10 -- S-12 The Connecticut Light and Power Company S-13 -- S-15 Public Service Company of New Hampshire S-16 -- S-20 Western Massachusetts Electric Company S-21 -- S-23 North Atlantic Energy Corporation S-24 -- S-25
V. Nuclear Fuel 1993, 1992, and 1991:
Northeast Utilities and Subsidiaries S-26 -- S-28 The Connecticut Light and Power Company S-29 -- S-31 Public Service Company of New Hampshire S-32 -- S-36 Western Massachusetts Electric Company S-37 -- S-39 North Atlantic Energy Corporation S-40 -- S-41
VI. Accumulated Provision for Depreciation of Utility Plant 1993, 1992, and 1991:
Northeast Utilities and Subsidiaries S-42 -- S-44 The Connecticut Light and Power Company S-45 Public Service Company of New Hampshire S-46 -- S-48 Western Massachusetts Electric Company S-49 North Atlantic Energy Corporation S-50
VIII. Valuation and Qualifying Accounts and Reserves 1993, 1992, and 1991:
Northeast Utilities and Subsidiaries S-51 -- S-53 The Connecticut Light and Power Company S-54 -- S-56 Public Service Company of New Hampshire S-57 -- S-61 Western Massachusetts Electric Company S-62 -- S-64
S-5
Schedule Page - -------- ----
IX. Short-Term Borrowings 1993, 1992, and 1991:
Northeast Utilities and Subsidiaries S-65 The Connecticut Light and Power Company S-66 Public Service Company of New Hampshire S-67 Western Massachusetts Electric Company S-68 North Atlantic Energy Corporation S-69
X. Supplementary Income Statement Information 1993, 1992, and 1991:
Northeast Utilities and Subsidiaries S-70 The Connecticut Light and Power Company S-71 Public Service Company of New Hampshire S-72 Western Massachusetts Electric Company S-73 North Atlantic Energy Corporation S-74
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.
S-6
SCHEDULE III NORTHEAST UTILITIES (PARENT) ---------------------------- FINANCIAL INFORMATION OF REGISTRANT ----------------------------------- BALANCE SHEETS -------------- AT DECEMBER 31, 1993 AND 1992 ------------------------------ (Thousands of Dollars)
S-7
SCHEDULE III NORTHEAST UTILITIES (PARENT) ---------------------------- FINANCIAL INFORMATION OF REGISTRANT ----------------------------------- STATEMENTS OF INCOME -------------------- YEARS ENDED DECEMBER 31, 1993, 1992, AND 1991 --------------------------------------------- (Thousands of Dollars Except Share Information)
S-8
SCHEDULE III NORTHEAST UTILITIES (PARENT) FINANCIAL INFORMATION OF REGISTRANT STATEMENTS OF CASH FLOWS YEARS ENDED DECEMBER 31, 1993, 1992, AND 1991 (Thousands of Dollars)
S-9
S-10
S-11
S-12
S-13
S-14
S-15
S-16
S-17
S-18
S-19
S-20
S-21
S-22
S-23
S-24
S-25
S-26
S-27
S-28
S-29
S-30
S-31
S-32
S-33
S-34
S-35
S-36
S-37
S-38
S-39
S-40
S-41
S-42
S-43
S-44
S-45
S-46
S-47
S-48
S-49
S-50
S-51
S-52
S-53
S-54
S-55
S-56
S-57
S-58
S-59
S-60
S-61
S-62
S-63
S-64
S-65
S-66
S-67
S-68
S-69
S-70
S-71
S-72
S-73
S-74
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 1993 Annual Report on Form 10-K for NU and herein incorporated by reference from the 1993 NU Form 10-K, File No. 1-5324 into the 1993 Annual Reports on Form 10-K for CL&P, PSNH, WMECO and NAEC.
# - Filed with the 1993 Annual Report on Form 10-K for NU and herein incorporated by reference from the 1993 NU Form 10-K, File No. 1-5324 into the 1993 Annual Report on Form 10-K for CL&P.
@ - Filed with the 1993 Annual Report on Form 10-K for NU and herein incorporated by reference from the 1993 NU Form 10-K, File No. 1-5324 into the 1993 Annual Report on Form 10-K for PSNH.
** - Filed with the 1993 Annual Report on Form 10-K for NU and herein incorporated by reference from the 1993 NU Form 10-K, File No. 1-5324 into the 1993 Annual Report on Form 10-K for WMECO.
## - Filed with the 1993 Annual Report on Form 10-K for NU and herein incorporated by reference from the 1993 Form 10-K, File No. 1-5324 into the 1993 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.
# 3.2.2 By-laws of CL&P, as amended to March 1, 1982.
3.3 Public Service Company of New Hampshire
@ 3.3.1 Articles of Incorporation, as amended to May 16, 1991.
@ 3.3.2 By-laws of PSNH, as amended to November 1, 1993.
3.4 Western Massachusetts Electric Company
3.4.1 Certificate of Organization of WMECO, as amended, to August 31, 1954. (Exhibit 3.1, File No. 2-11114)
3.4.2 Amendments to Certificate of Organization of WMECO of May 19, 1966 and of December 5, 1967. (Exhibit 3.2, File No. 2-30534)
E-1
3.4.3 Articles of Amendment dated December 9, 1981. (Exhibit 3.1.2, 1981 WMECO Form 10-K, File No. 0-7624)
3.4.4 Certificate of Vote of Directors Establishing a Series of a Class of Stock, dated December 16, 1981. (Exhibit 3.1.3, 1981 WMECO Form 10-K, File No. 0-7624)
3.4.5 Articles of Amendment dated April 7, 1983. (Exhibit 3.3.5, 1983 NU Form 10-K, File No. 1-5324)
3.4.6 Certificate of Vote of Directors Establishing a Series of a Class of Stock, dated April 12, 1983. (Exhibit 3.3.6, 1983 NU Form 10-K, File No. 1-5324)
3.4.7 Articles of Amendment dated January 29, 1987. (Exhibit 3.3.7, 1986 NU Form 10-K, File No. 1-5324)
3.4.8 Articles of Amendment dated February 11, 1987. (Exhibit 3.3.8, 1986 NU Form 10-K, File No. 1-5324)
3.4.9 Articles of Amendment dated February 19, 1988. (Exhibit 3.3.9, 1987 NU Form 10-K, File No. 1-5324)
3.4.10 Certificate of Vote of Directors Establishing a Series of a Class of Stock, dated February 23, 1988. (Exhibit 3.3.10, 1987 NU Form 10-K, File No. 1-5324)
** 3.4.11 By-laws of WMECO, as amended to February 24, 1988.
3.5 North Atlantic Energy Corporation
## 3.5.1 Articles of Incorporation of NAEC dated September 20, 1991.
## 3.5.2 Articles of Amendment dated October 16, 1991 and June 2, 1992 to Articles of Incorporation of NAEC.
## 3.5.3 By-laws of NAEC, as amended to November 8, 1993.
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)
E-2 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 June 1, 1989. (Exhibit 4.1.24, 1989 NU Form 10-K, File No. 1-5324)
4.2.7 September 1, 1989. (Exhibit 4.1.25, 1989 NU Form 10-K, File No. 1-5324)
4.2.8 December 1, 1989. (Exhibit 4.1.26, 1989 NU Form 10-K, File No. 1-5324)
4.2.9 April 1, 1992. (Exhibit 4.30, File No. 33-59430)
4.2.10 July 1, 1992. (Exhibit 4.31, File No. 33-59430)
E-3 4.2.11 October 1, 1992. (Exhibit 4.32, File No. 33-59430)
4.2.12 July 1, 1993. (Exhibit A.10(b), File No. 70-8249)
4.2.13 July 1, 1993. (Exhibit A.10(b), File No. 70-8249)
# 4.2.14 December 1, 1993.
# 4.2.15 February 1, 1994.
# 4.2.16 February 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.
# 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.
# 4.2.23 Series A (Tax Exempt Refunding) PCRB Letter of Credit and Reimbursement Agreement (Pollution Control Bonds) dated as of September 1, 1993.
# 4.2.24 Series B (Tax Exempt Refunding) PCRB Letter of Credit and Reimbursement Agreement (Pollution Control Bonds) dated as of September 1, 1993.
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)
E-4 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.
@ 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.
@ 4.3.9.1 Amended and Restated Letter of Credit dated December 17, 1992.
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)
E-5 @ 4.3.10.1 Amended and Restated Letter of Credit dated December 15, 1993.
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.
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 December 1, 1968. (Exhibit 2.7, File No. 2-68808)
4.4.5 July 1, 1972. (Exhibit 2.9, File No. 2-68808)
4.4.6 May 1, 1986. (Exhibit 4.3.18, 1986 NU Form 10-K, File No. 1-5324)
4.4.7 December 1, 1988. (Exhibit 4.3.20, 1988 NU Form 10-K, File No. 1-5324.)
4.4.8 September 1, 1990. (Exhibit 4.3.15, 1990 NU Form 10-K, File No. 1-5324.)
4.4.9 December 1, 1992. (Exhibit 4.15, File No. 33-55772)
4.4.10 January 1, 1993. (Exhibit 4.5.13, 1992 NU Form 10-K, File No. 1-5324)
** 4.4.11 March 1, 1994.
** 4.4.12 March 1, 1994.
** 4.4.13 Series A (Tax Exempt Refunding) PCRB Loan Agreement between Connecticut Development Authority and WMECO (Pollution Control Bonds) dated as of September 1, 1993.
** 4.4.14 Series A (Tax Exempt Refunding) PCRB Letter of Credit and Reimbursement Agreement (Pollution Control Bonds) dated as of September 1, 1993.
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)
E-6 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). (Exhibit 13.1, File No. 2-22958)
10.2 Form of Power Contract dated as of July 1, 1964 between CYAPC and each of CL&P, HELCO, PSNH and WMECO. (Exhibit 13.2, File No. 2-22958)
10.2.1 Form of Additional Power Contract dated as of April 30, 1984, between CYAPC and each of CL&P, PSNH and WMECO. (Exhibit 10.2.4, 1984 NU Form 10-K, File No. 1-5324)
10.2.2 Form of 1987 Supplementary Power Contract dated as of April 1, 1987, between CYAPC and each of CL&P, PSNH and WMECO. (Exhibit 10.2.6, 1987 NU Form 10-K, File No. 1-5324)
10.3 Capital Funds Agreement dated as of September 1, 1964 between CYAPC and CL&P, HELCO, PSNH and WMECO. (Exhibit 13.3, File No. 2-22958)
#@** 10.4 Stockholder Agreement dated December 10, 1958 between Yankee Atomic Electric Company (YAEC) and CL&P, HELCO, PSNH and WMECO.
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.
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)
E-7 #@** 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.
#@** 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.
10.7.3 Form of Amendment No. 3 to Power Contract dated as of October 1, 1984 between MYAPC and each of CL&P, PSNH and WMECO. (Exhibit 10.7.3, 1985 NU Form 10-K, File No. 1-5324)
#@** 10.7.4 Form of Additional Power Contract dated as of February 1, 1984 between MYAPC and each of CL&P, PSNH and WMECO.
10.8 Capital Funds Agreement dated as of May 20, 1968 between Maine Yankee Atomic Power Company (MYAPC) and CL&P, PSNH, HELCO and WMECO. (Exhibit 4.13, File No. 2-30018)
10.8.1 Amendment No. 1 to Capital Funds Agreement, dated as of August 1, 1985, between MYAPC, CL&P, PSNH and WMECO. (Exhibit 10.6.1, 1985 NU Form 10-K, File No. 1-5324)
10.9 Sponsor Agreement dated as of August 1, 1968 among the sponsors of VYNPC. (Exhibit 4.16, File No. 2-30285)
10.10 Form of Power Contract dated as of February 1, 1968 between VYNPC and each of CL&P, HELCO, PSNH and WMECO. (Exhibit 4.18, File No. 2-30018)
10.10.1 Form of Amendment to Power Contract dated as of June 1, 1972 between VYNPC and each of CL&P, HELCO, PSNH and WMECO. (Exhibit 5.22, File No. 2-47038)
#@** 10.10.2 Form of Second Amendment to Power Contract dated as of April 15, 1983 between VYNPC and each of CL&P, PSNH and WMECO.
10.10.3 Form of Third Amendment to Power Contract dated as of April 24, 1985 between VYNPC and each of CL&P, PSNH and WMECO. (Exhibit 10.10.3, 1986 NU Form 10-K, File No. 1-5324)
10.10.4 Form of Fourth Amendment to Power Contract dated as of June 1, 1985 between VYNPC and each of CL&P, PSNH and WMECO. (Exhibit 10.10.4, 1986 NU Form 10-K, File No. 1-5324)
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)
E-8 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.
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.
10.12 Amended and Restated Millstone Plant Agreement dated as of December 1, 1984 by and among CL&P, WMECO and Northeast Nuclear Energy Company (NNECO). (Exhibit 10.17, 1985 NU Form 10-K, File No. 1-5324)
10.13 Sharing Agreement dated as of September 1, 1973 with respect to 1979 Connecticut nuclear generating unit (Millstone 3). (Exhibit 6.43, File No. 2-50142)
10.13.1 Amendment dated August 1, 1974 to Sharing Agreement - 1979 Connecticut Nuclear Unit. (Exhibit 5.45, File No. 2-52392)
10.13.2 Amendment dated December 15, 1975 to Sharing Agreement - 1979 Connecticut Nuclear Unit. (Exhibit 7.47, File No. 2-60806)
10.13.3 Amendment dated April 1, 1986 to Sharing Agreement - 1979 Connecticut Nuclear Unit. (Exhibit 10.17.3, 1990 NU Form 10-K, File No. 1-5324)
10.14 Agreement dated July 19, 1990, among NAESCO and Seabrook Joint owners with respect to operation of Seabrook. (Exhibit 10.53, 1990 NU Form 10-K, File No. 1-5324)
10.15 Sharing Agreement between CL&P, WMECO, HP&E, HWP and PSNH dated as of June 1, 1992. (Exhibit 10.17, 1992 NU Form 10- K, File No. 1-5324)
10.16 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)
E-9 10.17 Agreement for joint ownership, construction and operation of New Hampshire nuclear generating units dated as of May 1, 1973. (Exhibit 13-57, File No. 2-48966)
10.17.1 Amendments to Exhibit 10.17 dated May 24, 1974, June 21, 1974 and September 25, 1974. (Exhibit 5.15, File No. 2-51999)
10.17.2 Amendments to Exhibit 10.17 dated October 25, 1974 and January 31, 1975. (Exhibit 5.23, File No. 2-54646)
10.17.3 Sixth Amendment to Exhibit 10.17 dated as of April 18, 1979. (Exhibit 5.4.3, File No. 2-64294)
10.17.4 Seventh Amendment to Exhibit 10.17 dated as of April 18, 1979. (Exhibit 5.4.4, File No. 2-64294)
10.17.5 Eighth Amendment to Exhibit 10.17 dated as of April 25, 1979. (Exhibit 5.4.5, File No. 2-64815)
10.17.6 Ninth Amendment to Exhibit 10.17 dated as of June 8, 1979. (Exhibit 5.4.6, File No. 2-64815)
10.17.7 Tenth Amendment to Exhibit 10.17 dated as of October 10, 1979. (Exhibit 5.4.2, File No. 2-66334)
10.17.8 Eleventh Amendment to Exhibit 10.17 dated as of December 15, 1979. (Exhibit 5.4.8, File No. 2-66492)
10.17.9 Twelfth Amendment to Exhibit 10.17 dated as of June 16, 1980. (Exhibit 5.4.9, File No. 2-68168)
10.17.10 Thirteenth Amendment to Exhibit 10.17 dated as of December 31, 1980. (Exhibit 10.6, File No. 2-70579)
* 10.17.11 Fourteenth Amendment to Exhibit 10.17 dated as of June 1, 1982.
10.17.12 Fifteenth Amendment to Exhibit 10.17 dated as of April 27, 1984. (Exhibit 10.14.12, 1984 NU Form 10-K, File No. 1-5324)
10.17.13 Sixteenth Amendment to Exhibit 10.17 dated as of June 15, 1984. (Exhibit 10.14.13, 1984 NU Form 10-K, File No. 1-5324)
10.17.14 Seventeenth Amendment to Exhibit 10.17 dated as of March 8, 1985. (Exhibit 10.13.14, 1985 NU Form 10-K, File No. 1-5324)
10.17.15 Eighteenth Amendment to Exhibit 10.17 dated as of March 14, 1986. (Exhibit 10.13.15, 1986 NU Form 10-K, File No. 1-5324)
10.17.16 Nineteenth Amendment to Exhibit 10.17 dated as of May 1, 1986. (Exhibit 10.13.16, 1986 NU Form 10-K, File No. 1-5324)
E-10 10.17.17 Twentieth Amendment to Exhibit 10.17 dated as of July 15, 1986. (Exhibit 10.13.17, 1986 NU Form 10-K, File No. 1-5324)
10.17.18 Twenty-first Amendment to Exhibit 10.17 dated as of November 12, 1987. (Exhibit 10.13.18, 1987 NU Form 10-K, File No. 1-5324)
10.17.19 Twenty-second Amendment to Exhibit 10.17 dated as of January 13, 1989. (Exhibit 10.13.19, 1989 NU Form 10-K, File No. 1-5324)
10.17.20 Twenty-third Amendment to Exhibit 10.17 dated as of November 1, 1990. (Exhibit 10.13.20, 1990 NU Form 10- K, File No. 1-5324)
10.17.21 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)
10.17.22 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)
10.17.22.1 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.
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.
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)
E-11 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.
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.
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.
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. (Exhibit 10.52, 1985 NU Form 10-K, File No. 1-5324)
E-12 10.26 Simulator Financing Lease Agreement, dated as of May 2, 1985, by and between The Prudential Insurance Company of America and NNECO. (Exhibit 10.53, 1985 NU Form 10-K, File No. 1-5324)
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 date 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.
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)
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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.
* 10.35.2 Amendment 2 to Exhibit 10.35, effective as of January 1, 1994.
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.
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.
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.)
E-14 * 13.1 Portions of the Annual Report to Security Holders of NU (pages 17 - 54) 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)
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