ITEM 1. BUSINESS THE NORTHEAST UTILITIES SYSTEM
Northeast Utilities (NU) is the parent company of the Northeast Utilities system (the NU system). The NU system furnishes franchised retail electric service to over 1.8 million customers in 409 cities and towns in Connecticut, New Hampshire and western Massachusetts through three of NU's wholly-owned subsidiaries (The Connecticut Light and Power Company [CL&P], Public Service Company of New Hampshire [PSNH] and Western Massachusetts Electric Company [WMECO]).
The NU system also furnishes franchised retail natural gas service in a large part of Connecticut through Yankee Gas Services Company (Yankee Gas), a subsidiary of Yankee Energy System, Inc. (Yankee), the largest natural gas distribution company in Connecticut. Yankee Gas serves approximately 191,000 residential, commercial and industrial customers in 70 cities and towns in Connecticut, including large portions of the central and southwest sections of the state.
NU, through its wholly owned subsidiary, NU Enterprises, Inc. (NUEI), owns a number of competitive energy and related businesses, including Northeast Generation Company (NGC), Northeast Generation Services Company (NGS), Select Energy, Inc. (Select Energy), Select Energy Services, Inc. (SESI; formerly HEC Inc.) and Mode 1 Communications, Inc. (Mode 1). Holyoke Water Power Company (HWP), a subsidiary of NU, is a resource of NUEI through an output contract. For information regarding the activities of these subsidiaries, see "Competitive System Businesses."
North Atlantic Energy Corporation (NAEC) is a wholly owned special-purpose operating subsidiary of NU that owned a 35.98 percent interest in the Seabrook station nuclear unit (Seabrook) in Seabrook, New Hampshire prior to its sale to the FPL Group, Inc. (FPL) in November 2002. North Atlantic Energy Service Corporation (NAESCO) had operational responsibility for Seabrook prior to its sale. Several other wholly owned subsidiaries of NU provide support services for the NU system companies and, in some cases, for other New England utilities. Northeast Utilities Service Company (NUSCO) provides centralized accounting, administrative, information technology, engineering, financial, legal, operational, planning, purchasing and other services to the NU system companies. Three other subsidiaries construct, acquire or lease some of the property and facilities used by the NU system companies.
The NU system is regulated in virtually all aspects of its business by various federal and state agencies, including the Securities and Exchange Commission (SEC), the Federal Energy Regulatory Commission (FERC), the Nuclear Regulatory Commission (NRC) and various state and/or local regulatory authorities with jurisdiction over the industry and the service areas in which each company operates, including the Connecticut Department of Public Utility Control (DPUC), the New Hampshire Public Utilities Commission (NHPUC) and the Massachusetts Department of Telecommunications and Energy (DTE). In recent years, there has been significant legislative and regulatory activity changing the nature of regulation of the industry. For more information regarding these restructuring initiatives, see "Rates and Electric Industry Restructuring" and "Regulated Electric Operations."
SAFE HARBOR STATEMENT UNDER THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
In connection with the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 (Reform Act), NU and its reporting subsidiaries are hereby filing cautionary statements identifying important factors that could cause NU or its subsidiaries' actual results to differ materially from those projected in forward looking statements (as such term is defined in the Reform Act) made by or on behalf of NU or its subsidiaries in this combined Form 10-K, in any subsequent filings with the SEC, in presentations, in response to questions, or otherwise. Any statements that express or involve discussions as to expectations, beliefs, plans, objectives, assumptions or future events, or performance (often, but not always, through the use of words or phrases such as will likely result, are expected to, will continue, is anticipated, estimated, projection, outlook) are not statements of historical facts and may be forward looking. Forward looking statements involve estimates, assumptions and uncertainties that could cause actual results to differ materially from those expressed in the forward looking statements. Accordingly, any such statements are qualified in their entirety by reference to, and are accompanied by, the following important factors that could cause NU or its subsidiaries' actual results to differ materially from those contained in forward looking statements of NU or its subsidiaries made by or on behalf of NU or its subsidiaries.
Any forward looking statement speaks only as of the date on which such statement is made, and NU and its subsidiaries undertake no obligation to update any forward looking statement or statements to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time and it is not possible for management to predict all of such factors, nor can it assess the impact of each such factor on the business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward looking statements.
Some important factors that could cause actual results or outcomes to differ materially from those discussed in the forward looking statements include prevailing governmental policies and regulatory actions, including those of the SEC, the NRC, the FERC, and state regulatory agencies, with respect to allowed rates of return, industry and rate structure, operation of nuclear power facilities, acquisition and disposal of assets and facilities, operation and construction of plant facilities, recovery of purchased-power costs, stranded costs, decommissioning costs, and present or prospective wholesale and retail competition (including but not limited to retail wheeling and transmission costs).
The business and profitability of NU and its subsidiaries are also influenced by economic and geographic factors including political and economic risks, changes in environmental and safety laws and policies, weather conditions (including natural disasters), population growth rates and demographic patterns, competition for retail and wholesale customers, pricing and transportation of commodities, market demand for energy from plants or facilities, changes in tax rates or policies or in rates of inflation, changes in project costs, unanticipated changes in certain expenses and capital expenditures, capital market conditions, competition for new energy development opportunities, and legal and administrative proceedings (whether civil or criminal) and settlements.
All such factors are difficult to predict, contain uncertainties which may materially affect actual results and are beyond the control of NU or its subsidiaries.
RATES AND ELECTRIC INDUSTRY RESTRUCTURING
GENERAL
NU's electric utility subsidiaries, CL&P, WMECO and PSNH, have undergone fundamental changes in their business operations as a result of the restructuring of the electric industry in their respective jurisdictions. The year 2002 represented the final year of a four-year process of selling most of the regulated generating assets of the NU system. Most notably, CL&P and WMECO have divested all of their generation assets and are acting solely as transmission and distribution companies, while divestiture of PSNH's fossil and hydro generation has been postponed by state statute until at least 2004. All operating company customers are now able to choose their energy suppliers, with the electric utility companies furnishing "standard offer," "default" or "transition" service to those customers who do not choose a competitive supplier. Critical to this restructuring is the companies' ability to recover their stranded costs. Stranded costs are expenditures incurred, or commitments for future expenditures made, on behalf of customers with the expectation such expenditures would continue to be recoverable in the future through rates.
As discussed more fully below, CL&P and WMECO have received regulatory orders allowing each to recover all or substantially all of their prudently incurred stranded costs. Under an April 2000 settlement agreement among NU, PSNH and the State of New Hampshire (Restructuring Settlement), which has been approved by the NHPUC, PSNH is entitled to recover all of its remaining prudently incurred stranded costs. All three companies have recovered significant portions of their stranded costs through the issuance of rate reduction bonds (RRBs) and rate reduction certificates (RRCs) (securitization) and are recovering these costs through rates.
Electric utility restructuring in Connecticut, New Hampshire and Massachusetts provides for a transition period of several years following the opening of each state's electric market to customer choice. During that interim period, the energy delivery companies, including CL&P, WMECO and PSNH, are responsible for arranging for the supply of power to customers who do not select alternative energy suppliers. Management recognizes that in other states electric companies have been negatively affected by the inability to recover supply costs on a timely basis. However, the Company believes that current statutes and regulatory policy in the three states in which NU subsidiaries operate electric delivery businesses will permit timely recovery.
CL&P has signed fixed-price contracts with three suppliers who together will serve all of CL&P's standard offer requirements through 2003. One of these suppliers is the company's competitive marketing affiliate, Select Energy, and the other two suppliers, NRG Power Marketing, Inc. (NRG-PM) and Duke Energy Trading and Marketing Northeast, LLC (Duke Energy), are unaffiliated with CL&P. CL&P is fully recovering all of the payments it is making to those suppliers and has limited financial guarantees from each unaffiliated supplier to shield CL&P from risk in the event any of the suppliers encounters financial difficulties. See "Connecticut Rates and Restructuring."
After a competitive solicitation, WMECO signed supply agreements for standard offer service in November 2002 for the 2003 calendar year. Select Energy was the winning bidder. The DTE approved the standard offer contract and approved rates, which will allow WMECO to recover fully its standard offer service supply costs. In addition, in Massachusetts there is a second type of service supplied by electric distribution companies called default service. Default service is provided to those customers not on competitive supply that are not eligible for standard offer service. A single unaffiliated supplier won the competitive solicitation to provide default service to WMECO for the period January 1, 2003, through June 30, 2003. Default service supply for the second half of the year will be solicited in the spring of 2003.
Retail competition for all PSNH customers began on May 1, 2001. PSNH provides transition service energy to its retail customers from its owned generating plants, from purchase power obligations and from market purchases. See "New Hampshire Rates and Restructuring."
CONNECTICUT RATES AND RESTRUCTURING
Since retail competition began in Connecticut in 2000, an extremely small number of CL&P customers (about 20,000 out of 1.2 million CL&P customers) have opted to choose their retail supplier. Through December 2003, 50 percent of CL&P's standard offer supply requirements will be purchased from Select Energy, 45 percent from NRG-PM, and 5 percent from Duke Energy.
In November 2001, at the request of NRG-PM, CL&P filed a request with the DPUC to raise the standard offer rate from an average of $0.0495 per kilowatt- hour (kWh) to $0.0595 per kWh, which would help promote competition in advance of the January 1, 2004 termination of the standard offer period and provide financial relief to standard offer suppliers. In December 2001, the DPUC rejected CL&P's request, but opened two new dockets to examine the absence of effective retail competition in Connecticut and the financial condition of the suppliers. The first docket culminated in a joint study report issued in a DPUC decision on February 15, 2002, which provided the DPUC's and the Connecticut Office of Consumer Counsel's (OCC) findings on how to best structure default service and other issues related to electric industry restructuring. In the second docket, the DPUC concluded on June 17, 2002, "that there does not exist either a legal or factual basis upon which to find probable cause to commence further proceedings regarding the standard offer generation service charge."
On July 18, 2002, CL&P, concerned with NRG-PM's financial viability, filed a new proposal with the DPUC to maintain current total rates, but to shift $0.007 per kWh from being used to accelerate the amortization of stranded costs to instead provide additional payments to NRG-PM and Select Energy. The payments to NRG-PM would help ensure that there are adequate available generating units to maintain electric reliability in the near term in southwest Connecticut. On July 26, 2002, the DPUC denied the request, indicating that it expects CL&P to enforce the current standard offer contracts. Subsequent to July 26, NRG-PM announced that it entered an agreement with ISO-New England to keep three units at its Devon, Connecticut station in service. Under the terms of the agreement, NRG-PM will be provided compensation to continue operating the units until the end of the agreement on September 30, 2003. These units will accordingly remain available until ISO-New England determines that they are no longer needed for reliability. Based on this information and the fact that there were no further issues brought to the DPUC's attention, the docket was closed on August 29, 2002.
In light of recent downgrades of NRG Energy, Inc., NRG-PM's parent company (NRG), by all three major rating companies to below minimum investment grade levels, NU continues to evaluate NRG-PM's financial health. If CL&P is required to seek an alternate source of supply, CL&P would pursue recovery of any additional costs from NRG-PM pursuant to the contract. In the event NRG-PM did not pay such costs, CL&P may be required to seek DPUC approval to flow through any such costs, including any increased payments to its other standard offer service suppliers, to its customers. On February 21, 2003, Fitch Ratings lowered its ratings outlook on CL&P to negative as a result of its concern over timely recovery of higher purchased-power costs if NRG-PM were to default on its CL&P standard offer obligations. Management believes that recovery of these costs would be consistent with the provisions of Connecticut's electric utility restructuring legislation and all other ratings outlooks on CL&P remain stable. In view of the deterioration of NRG's financial condition, CL&P exercised its contractual right to withhold past due congestion costs from the July 2002 standard offer payment to NRG-PM pending the outcome of litigation between the parties concerning contractual liability for congestion costs ongoing in the United States District Court for the District of Connecticut. All subsequent standard offer payments to NRG-PM have similarly been reduced to reflect continued withholding of congestion costs.
On December 20, 2002, FERC issued an order in connection with a dispute between CL&P and NRG concerning the provision of station service to Connecticut generating plants purchased from CL&P by NRG affiliates in December 1999. CL&P filed a complaint at FERC seeking interpretation of a FERC-filed interconnection agreement in which NRG agreed to pay CL&P's applicable retail rates for station service power (if procured from CL&P) and delivery of such power (whether procured from CL&P or a third party supplier). FERC further affirmed the language in its Order 888 concerning state jurisdiction over the delivery of power to end users, even in the absence of distribution facilities, and the state's authority to impose certain charges on end users, such as those associated with stranded cost recovery. CL&P has made a demand upon NRG for payment of $13.3 million in station service charges through January 2003 and is preparing to take any steps necessary to collect the unpaid balance. For further information relating to NRG-related litigation, see Item 3, "Legal Proceedings."
On September 27, 2001, CL&P filed its application with the DPUC for approval of the disposition of the proceeds from the sale of the Millstone nuclear units (Millstone) to Dominion Nuclear Connecticut, Inc. (DNCI). This application described and requested DPUC approval for CL&P's treatment of its share of the proceeds from the sale, including CL&P's recovery of approximately $75 million of capital additions at Millstone during the approximately four years prior to sale. On February 27, 2003, the DPUC issued a final decision in this docket requiring a $26.9 million increase in the amount of proceeds CL&P had proposed to be applied to stranded costs.
On May 17, 2002, CL&P filed an application with the DPUC for approval of the auction results in the sale of Seabrook to a subsidiary of FPL. A final decision approving the sale was issued in September 2002 and the sale closed on November 1, 2002.
On November 23, 2001, CL&P petitioned the DPUC to adjust its stranded costs to account for the announced sale of the Vermont Yankee nuclear unit (VY) to an unaffiliated company. On June 12, 2002, the DPUC issued a final decision that found CL&P's request was beneficial to ratepayers and allowed for stranded cost recovery through the Competitive Transition Assessment.
CL&P was unable to negotiate buy down or buy out arrangements with 15 independent power producers (IPPs) that produce approximately 345 megawatts (MW). CL&P is selling the output from these projects into the market and will, pursuant to DPUC authority, continue to collect the difference between the contract prices and the market revenues as stranded costs. These stranded costs cannot be securitized.
As of December 31, 2002, CL&P had fully recovered all stranded costs except those to be recovered through RRBs, ongoing IPP costs, costs associated with the ongoing decommissioning of the Maine Yankee, Connecticut Yankee and Yankee Rowe nuclear units and annual decontamination and decommissioning costs payable under federal law.
In December 2000, the Attorney General of the State of Connecticut (AG) and the OCC each filed a petition requesting that the DPUC initiate a proceeding to consider whether an interim decrease in the rates charged by CL&P is required. The applicable statute requires the DPUC to commence a special public hearing on the need for an interim rate decrease when, among other reasons, a public service company has for six consecutive months earned a return on equity (ROE) that exceeds the return authorized by the DPUC by at least one percentage point. In June 2001, the DPUC concluded its investigation on potential overearnings by CL&P and ordered a $21.1 million reduction in CL&P's electric transmission and distribution rates and an equal increase in CL&P's generation services charge. The DPUC also implemented an earnings sharing mechanism under which earnings in excess of a 10.3 percent authorized ROE are shared equally by shareholders and ratepayers. In September 2001, the DPUC ordered a $21.3 million annual reduction in CL&P's System Benefits Charge as a result of a sharp reduction in decommissioning collections and an equal increase in the competitive transition assessment, effective March 1, 2002. The net result of the decisions noted above was to reduce CL&P's pretax earnings by $21.1 million beginning June 20, 2001, and accelerate CL&P's recovery of stranded costs in 2002 and 2003. For the twelve-month period ended June 30, 2002, CL&P overearned its allowed 10.3 percent ROE by .23 percent, resulting in an approximate $1 million reduction in stranded costs.
In July 2001, the DPUC authorized CL&P to assess a charge of approximately $0.002 per kWh through December 2003 to collect approximately $98.5 million of deferred fuel costs, including carrying costs, primarily incurred prior to January 1, 2000.
In December 2001, the AG filed a petition seeking an investigation into CL&P's potential overearnings. On February 6, 2002, the DPUC rejected the petition.
In mid-2003, CL&P expects to file a distribution rate case with the DPUC for rates that would be effective January 2004. Also, in the second half of 2003, CL&P will need to secure bids for power supply contracts to meet the needs of its customers for 2004. Management has not yet identified what level of rates it will request in 2004.
On December 2, 2002, the Connecticut Siting Council (CSC) resumed hearings on CL&P's proposed $135 million project to build a new 345,000-volt transmission line between Bethel and Norwalk, Connecticut. A final decision on the project is expected by mid-April 2003. CL&P expects to file with the CSC later in 2003 to build a 65-mile 345,000-volt line between Norwalk and Middletown, Connecticut. The two projects are needed to resolve a host of growth-related problems in the import-dependent Norwalk-Stamford and southwest Connecticut load pockets. For additional information on CL&P's proposed expansion of its transmission system, see "Construction and Capital Improvement Plan."
On March 1, 2003, ISO-New England implemented a new Standard Market Design (SMD). As part of this effort, locational marginal pricing (LMP) will be utilized to assign value and causation to transmission congestion. Transmission congestion costs will be assigned to the load zone in which the congestion occurs. Those costs are now spread across virtually all New England electric customers. In addition, the implementation of SMD will impact wholesale energy contracts with respect to the energy delivery points contained in these contracts. See "Competitive System Businesses-Wholesale and Retail Marketing."
Connecticut has been designated a single load zone. Due to transmission constraints and inadequate generation Connecticut could experience significant additional congestion costs under SMD. The New England ISO has estimated that the costs of transmission congestion for 2003 in New England under SMD will range between $50 million and $300 million. ISO-New England estimates that the majority of this congestion and its costs will be in Connecticut, where approximately 80 percent of those costs are expected to be paid by CL&P beginning on March 1, 2003. CL&P believes that under the terms of its standard offer service contracts with its standard offer suppliers, these costs are its responsibility. The contracts with the standard offer suppliers expire on December 31, 2003. In addition, the determination of the energy delivery points associated with the standard offer service contracts under SMD could also produce significant costs for CL&P that management cannot determine at this time.
Another factor affecting the level of congestion costs is the designation of certain generating units by ISO-New England as units needed for system reliability. Some of the companies owning these units have applied to the FERC for "reliability must run" (RMR) treatment. RMR treatment allows these units to receive cost of service based payments that recognize their reliability value. Prior to March 1, 2003, all RMR costs were spread across New England with all utilities being billed by ISO-New England based upon their share of New England's load. NU's regulated electric utilities were responsible for approximately 25 percent of these costs. Effective with the March 1, 2003 implementation of SMD by ISO-New England, RMR costs will be allocated to the load zone in which the RMR unit is located. At present, the only load zone that will experience a cost increase in which a NU regulated electric company operates is Connecticut. With respect to the Connecticut load zone, there are two generating units operating under a RMR contract with an additional contract pending before FERC. These contracts are for one year terms, and one contract contains an extension option. On a combined basis, these two RMR contracts will result in an annual cost of approximately $45 million to the Connecticut load zone. CL&P accounts for approximately 80 percent of the Connecticut load zone, and would be responsible for approximately $36 million of this cost. In the near future, it is probable that there will be significant new requests for RMR treatment in Connecticut which, if approved by FERC, would add significant additional costs to the total cost of energy in Connecticut. However, generating units operating under RMR contracts could potentially mitigate the overall level of congestion costs.
These unavoidable congestion and RMR costs are part of the prudent cost of providing regulated electric service in Connecticut. A DPUC regulatory proceeding is expected to be initiated soon to determine the appropriate recovery mechanism for these costs. If these costs are incurred before the final recovery mechanism is established by the DPUC, CL&P expects to record a regulatory asset for those costs incurred.
In response to the regional transmission expansion plan prepared by ISO- New England, CL&P has advised ISO-New England that it will seek to obtain approximately 60 to 80 MW of peaking capacity to be located in southwest Connecticut for the summer of 2003. CL&P is also seeking a longer-term solution to the peaking capacity needs of southwest Connecticut.
For further information on SMD and transmission-related issues, see "Regulated Electric Operations - Transmission Access and FERC Regulatory Changes."
In July 2001, Yankee Gas filed an application to increase customers' rates by approximately $29.2 million, or an average of 7.64 percent. Yankee Gas requested the increase to fund system reliability projects and a proposed expansion of its distribution system. On January 30, 2002, the DPUC issued a final decision in the case, ordering a $4.0 million reduction in Yankee Gas rates, which became effective April 1, 2002. The DPUC authorized Yankee Gas' distribution expansion plan, subject to annual reviews, and approved, with some conditions, its capital investment ratemaking recovery mechanism (Infrastructure Expansion Rate Mechanism or IERM). The final decision also authorized an 11 percent ROE for Yankee Gas and a sharing formula for earnings above that level from 2002 through 2005. On August 1, 2002, Yankee Gas filed testimony and exhibits with the DPUC reflecting its proposal for IERM projects to be placed in-service during the period July 1, 2002 through December 31, 2003 and that meet certain financial criteria outlined by the DPUC. Yankee Gas is currently proposing no IERM charge for 2003 and that any over-collection for 2003 be carried forward to the 2004 IERM period. A decision in this docket is expected in the first quarter of 2003.
On December 4, 2002, the DPUC opened a docket to review Yankee Gas earnings in excess of its authorized ROE. Hearings are scheduled for March 2003 and a decision is expected in May 2003.
A schedule has been set in Yankee Gas' proceeding before the DPUC to obtain rate approval to build a two billion cubic foot liquefied natural gas production and storage facility in Waterbury, Connecticut. The rate schedule includes hearings in March 2003 with a final decision in the second quarter of 2003. If approved, construction of the facility, which could cost approximately $60 million, could begin in the fourth quarter of 2003.
MASSACHUSETTS RATES AND RESTRUCTURING
Massachusetts enacted comprehensive electric utility industry restructuring in November 1997. That legislation required each electric company to submit a restructuring plan and to reduce its rates by 15 percent adjusted for inflation by September 1999. The 15 percent rate reduction is a rate cap for standard offer service customers that extends until February 2005, the end of the restructuring transition period. The restructuring plan approved by the DTE in 1999 allows WMECO's customers to choose their energy suppliers and WMECO to recover stranded costs. Two parties have appealed the DTE's decision on WMECO's restructuring plan to the Massachusetts Supreme Judicial Court. One appeal has been dismissed without prejudice by the Supreme Judicial Court because the appellant has failed to prosecute the appeal. There has been no significant action in the other appeal since it was filed in December 1999.
In December 2002, the DTE approved a 1.8 percent increase in WMECO's overall bills, primarily reflecting slightly increased standard offer service and default service costs as well as other inflationary factors. See "Rates and Electric Industry Restructuring-General" information relating to WMECO's standard offer service and default service supply.
During the first quarter of 2000, WMECO filed its first annual stranded cost reconciliation filing covering the period March 1, 1998 through December 31, 1999. The DTE issued its decision on this filing on June 7, 2002. The decision included, among other things, a ruling that investment tax credits associated with generation assets that have been divested should not be used to reduce rates. As a result, WMECO recognized approximately $13 million in tax credits in the second quarter of 2002.
On March 30, 2001, WMECO filed its second annual stranded cost reconciliation with the DTE for calendar year 2000. On March 29, 2002, WMECO filed its 2001 annual transition cost reconciliation with the DTE for calendar year 2001. Included in that filing were the sales proceeds from WMECO's interest in Millstone, the impact of securitization and approximately a $13 million benefit to ratepayers from WMECO's performance-based ratemaking process. On July 8, 2002, WMECO submitted a compliance filing in accordance with the DTE's June 7, 2002 order in WMECO's 1998-1999 stranded cost reconciliation proceedings. This filing reflected changes to the 1998 through 1999 reconciliations as agreed to by WMECO and/or ordered by the DTE and also included a revised transition charge filing for 2000 and 2001 to reflect the June 7, 2002 order. Subsequent to the July 8, 2002 filing, WMECO and the office of the Massachusetts Attorney General reached a settlement covering all transition charge issues for the 1998 through 2001 reconciliations. This settlement was approved by the DTE on December 27, 2002. The after-tax impact of this settlement increased 2002 earnings by approximately $5.7 million.
NEW HAMPSHIRE RATES AND RESTRUCTURING
In July 2001, the NHPUC opened a docket to review the fuel and purchased- power adjustment clause (FPPAC) costs incurred by PSNH between August 2, 1999 and April 30, 2001, in order to determine the amount of deferred FPPAC costs PSNH should be entitled to recover through the stranded cost recovery charge. Hearings at the NHPUC concluded in June 2002, and PSNH filed its closing brief with the NHPUC in July 2002. Under the Restructuring Settlement, FPPAC deferrals are recovered as Part 3 stranded costs through the stranded cost recovery charge. On December 31, 2002, the NHPUC approved the recovery of all but $17,000 of PSNH's request to recover approximately $200 million.
On June 28, 2002, PSNH made its first stranded cost recovery charge reconciliation filing with the NHPUC for the period May 1, 2001 through December 31, 2001. This filing reconciles stranded cost revenues against actual stranded costs with any difference being refunded to customers or deferred for future recovery. Included in the stranded cost charges are the net generation revenues and generation cost charges for the filing period. Where generation revenues exceed costs, additional stranded costs were amortized; where generation costs exceed revenues, costs were deferred for future recovery. The generation costs included in this filing are subject to a prudence review by the NHPUC. PSNH entered into a settlement with the NHPUC staff and the Office of Consumer Advocate recommending that the NHPUC find that all of PSNH's generation costs were prudently incurred. The NHPUC held a hearing on January 8, 2003 and a decision was issued on February 14, 2003, effectively adopting the terms of the settlement.
On September 12, 2002, the NHPUC issued a final decision approving the auction results in the sale of Seabrook to FPL. Under the terms of the Settlement Agreement, PSNH non-securitized stranded costs will be reduced by the net proceeds from NAEC's ownership interest in Seabrook. To date, NAEC has credited PSNH with approximately $179 million through the contracts under which PSNH was obligated to purchase NAEC's ownership of the output and capacity of Seabrook (Seabrook Power Contracts). These credits are being used to offset Part 3 stranded costs, which are nonsecuritized regulatory assets which must be recovered by a recovery end date determined in accordance with the Restructuring Settlement or be written off.
In 2002, NAEC supplied PSNH with approximately 2.74 billion kWh. PSNH fossil and hydroelectric units generated 3.52 billion kWh and PSNH purchased another 4.67 billion kWh, some under long-term rate orders with small power producers based in New Hampshire. Of that total 10.93 billion kWh, 7.91 billion kWh were used to service PSNH's retail electric customers and the remaining 3.02 billion kWh were sold in the wholesale market. As a result of NAEC's sale of Seabrook, PSNH expects its wholesale electric sales to decline significantly in 2003. However, PSNH expects to generate most of the electricity it needs to serve transition service for its customers from its own generating plants or purchased-power obligations and to purchase the remainder in the wholesale market.
On December 5, 2002, PSNH announced an agreement to acquire the franchise and electric system of Connecticut Valley Electric Company, Inc. (CVEC), a subsidiary of Central Vermont Public Service Corporation (CVPS) that serves approximately 10,000 customers in western New Hampshire. Under the agreement, PSNH will pay CVPS approximately $9 million for its assets and an additional $21 million to terminate a wholesale power contract between CVPS and CVEC. Customers of CVEC will become customers of PSNH, whose residential rates are now approximately 20 percent lower than those of CVEC. PSNH will be allowed to recover the $21 million payment with a return consistent with Part 3 stranded cost treatment under the Restructuring Settlement. Part 3 stranded costs are nonsecuritized regulatory assets which must be recovered by a recovery end date determined in accordance with the Restructuring Settlement or be written off. The sale agreement is supported by the New Hampshire Governor's Office, NHPUC staff, the state Office of Consumer Advocate, the City of Claremont and New Hampshire Legal Assistance. The FERC and the NHPUC must approve the sale, which is expected to become effective on January 1, 2004.
On February 1, 2003, in accordance with New Hampshire law, PSNH raised the transition service rate for residential and small commercial customers to 4.60 cents per kWh from 4.40 cents per kWh. On the same date, pursuant to New Hampshire law and order of the NHPUC, PSNH also raised its transition supply rate for large commercial and industrial customers to 4.67 cents per kWh from 4.40 cents per kWh. PSNH expects those rates to be adequate to recover its generation and power purchased-power costs, including the recovery of carrying costs on PSNH's generation investment. If recoveries exceed PSNH's costs, those overrecoveries will be credited against PSNH's Part 3 stranded cost balance. If actual costs exceed those recoveries, PSNH will defer those costs for future recovery from customers through its Stranded Cost Recovery Charge.
PSNH's delivery rates are fixed until February 1, 2004. Under the Restructuring Settlement, PSNH must file a rate case by December 31, 2003 for the purpose of commencing a review of PSNH's delivery rates.
COMPETITIVE SYSTEM BUSINESSES
NU is engaged in a variety of competitive businesses which are primarily involved in the marketing of electricity and natural gas in the Northeast United States and the provision of energy related services to large government, industrial, commercial and institutional facilities. NU's competitive businesses operate four major business units: wholesale marketing, retail marketing, energy trading and energy products and services.
NUEI is the lead competitive energy business within NU. NUEI is a wholly owned subsidiary of NU and acts as the holding company for certain of NU's competitive energy subsidiaries. These subsidiaries include SESI, a provider of energy management, demand-side management and related consulting services for commercial, industrial and institutional customers and electric utility companies; NGC, a corporation that acquires and manages generation facilities; NGS, a corporation that maintains and services fossil and hydroelectric facilities, and Select Energy, a corporation engaged in the trading, marketing, transportation, storage and sale of energy commodities, at wholesale and retail, in designated geographical areas. NUEI and its integrated competitive energy business affiliates had aggregate revenues of approximately $1.7 billion in 2002 as compared to approximately $2.1 billion in 2001 and lost $54.1 million in 2002, as compared to earnings of approximately $5 million (before extraordinary items) in 2001.
NGC is the competitive generating subsidiary of NU and a major provider of pumped storage and conventional hydroelectric power in the northeastern United States. NGC owns and operates a portfolio of approximately 1,291 MW of generating assets in New England. The generation facilities owned by NGC were acquired at auction from CL&P and WMECO. NGC's portfolio consists of seven hydro facilities along the Housatonic River System (121 MW), the three facilities comprising the Eastern Connecticut System, including one gas turbine (28 MW), all located in Connecticut, and the Northfield Mountain pumped storage station (1,080 MW) and the Cabot and Turners Falls No. 1 hydroelectric stations (62 MW) located in Massachusetts. NGC sells all its generation output to Select Energy, which in turn markets it to customers. Select Energy's performance under its contract with NGC is guaranteed by NU through 2005.
Select Energy also buys and manages the entire generation output of HWP, which consists of approximately 147 MW generated at the Mt. Tom station in Holyoke, Massachusetts under a renewable contract.
NUEI's deregulated operations are a core business of NU. NGC's assets and Mt. Tom perform functions that are critical to NUEI's wholesale and retail businesses by providing Select Energy with access to electric generation within New England and thus reducing its exposure to energy price fluctuations.
WHOLESALE AND RETAIL MARKETING
NUEI, through Select Energy, sells multiple energy products including electricity and natural gas to wholesale and retail customers in the northeastern United States. Select Energy procures and delivers energy and capacity required to serve its electric and gas customers. Select Energy is one of the largest wholesale and retail electric energy marketers in New England as measured by megawatt load. In order to support and complement its growing wholesale and retail business, Select Energy contracted in December of 1999 with NGC to purchase and market all of NGC's 1,291 MW for a 6-year period. In addition, during 2002 Select Energy purchased approximately 147 MW of coal generating plant output from its affiliate, HWP, and more than 2,800 MW of electrical supply from various New England generating facilities on a long-term basis to meet its New England load obligations. Select Energy may also utilize generation failure insurance, options and energy futures to hedge its supply requirements. NUEI also offers energy management consulting and construction services through its affiliate, SESI, discussed more fully below.
In 2002, Select Energy reported revenues of $1.5 billion and had retail and wholesale marketing sales of approximately 26,000 gigawatt-hours (GWh) of electricity and 52 billion cubic feet (BcF) of natural gas to approximately 19,000 customers. During 2001, Select Energy reported revenues of $1.9 billion and had retail and wholesale marketing sales of approximately 25,000 GWh of electricity and 32 BcF of natural gas to approximately 18,000 customers. Twelve months of operations from Select Energy New York, Inc. are reflected in 2002 versus one month of operations in 2001.
There are a number of large energy companies bidding for business in the restructured Northeast market. During 2002, the breadth and depth of the market for energy trading and marketing products in Select Energy's market was adversely affected by the withdrawal or financial weakening of a number of companies who have historically done significant amounts of business with Select Energy. In general, the market for such products has become shorter term and less liquid in nature and participants are more often unable to meet Select Energy's credit standards without additional credit support. Select Energy's business has been adversely affected by these factors and they could continue to adversely affect Select Energy's results in 2003.
Changes are occurring in the administration of transmission systems in territories in which Select Energy does business. Regional transmission organizations (RTO) are being contemplated, and other changes in market design are occurring within transmission regions. For example, SMD was implemented in New England on March 1, 2003 and will create challenges and opportunities for Select Energy. The impact of SMD on the wholesale marketing business could be significant. The determination of the energy delivery points in many wholesale marketing contracts and the location of sources of supply could have a significant effect on Select Energy. As more information regarding the timing and impact of SMD becomes available, there could be additional adverse effects that management cannot determine at this time. For more information on the proposed changes, see "Regulated Electric Operations-Transmission Access and FERC Regulatory Charges" and "Rates and Electric Industry Restructuring- Connecticut Rates and Restructuring."
Wholesale Marketing. Select Energy's goal is to be the regional leader in providing electric service to the Northeastern competitive markets. In 2002, Select Energy supplied more than 5,600 MW of standard offer and default service load in the region, making it one of the largest providers of standard offer service in the Northeast. Revenues from these services comprised in the aggregate approximately 70 percent of Select Energy's 2002 revenues.
On January 1, 2000, Select Energy began serving one half of CL&P's standard offer load for a four-year period at fixed prices. This equates to approximately 2,000 MW annually for each of the four contract years. Approximately 38 percent of Select Energy's 2002 competitive energy revenues came from CL&P's supply contract. Although Select Energy lost an estimated $47 million on this arrangement last year, in 2003 Select Energy expects improved results due to more favorable purchase contracts. A return to normal river conditions at NGC's hydroelectric plants, in contrast to the near-drought conditions New England experienced during much of 2002, is also expected to improve results. In 2003, Select Energy will also focus on improved management of power supply associated with its full requirements contracts. To meet its profit target in 2003, Select Energy must also secure a significant amount of new business at acceptable margins. Management expects Select Energy's wholesale marketing business will be profitable in 2003.
In addition to its contract with CL&P, Select is serving 2,100 MW of New Jersey's basic generation supply (BGS) load through July 31, 2003, 1,200 MW of BGS load from August 1, 2003 through May 31, 2004, and 500 MW of BGS load from June 1, 2004 through May 31, 2006. In addition, on January 1, 2003, Select Energy began serving the 500 MW standard offer load of its affiliate, WMECO, for a 12 month period. There are also approximately 300 MW of fixed price market-based wholesale contracts throughout New England that were previously supplied by WMECO and CL&P that are now the responsibility of Select Energy.
Retail Marketing. Select Energy is licensed to provide retail electric supply in Connecticut, Delaware, Maryland, New Jersey, Maine, Pennsylvania, Virginia, New York, Massachusetts, Rhode Island and New Hampshire. Within these states, Select Energy is currently registered with approximately 36 electric distribution companies and 51 gas distribution companies to provide retail services.
As of December 31, 2002, Select Energy had contracts with retail electric customers in states throughout the Northeast with over 900 MW of peak load at 13,000 locations, including predominately commercial, industrial, institutional and governmental accounts. As over 600 MW of this load is in New England, Select Energy is among the largest competitive retail suppliers of electricity in New England as measured by megawatt load. No single retail electric customer accounts for more than ten percent of Select Energy's expected retail revenues.
Select Energy's retail marketing business had far weaker performance in 2002, when it lost approximately $28 million, than in 2001, when it lost approximately $8 million, prior to a $22.4 million accounting change. The weaker performance is attributed to unusually warm weather in the first quarter of 2002, which particularly affected retail gas sales, and to unfavorable retail supply contracts, many of which were terminated by the end of 2002. Select Energy expects its retail marketing business to break even in 2003. In order to achieve this goal, Select Energy plans to size the retail organization to better fit the expected level of business and to better manage volumetric risk, particularly in the winter heating months. This goal also assumes that Select Energy will be successful in securing and managing a significant amount of new business at acceptable margins.
During 2002, Select Energy's competitive natural gas business, primarily retail in nature, produced revenues of approximately $247 million, an increase from 2001 revenues of approximately $200 million. This increase was due to changes in gas prices and increased volume. As of December 31, 2002, Select Energy provided over 39 BcF of natural gas to approximately 6,000 retail gas customers, primarily located in Connecticut, Massachusetts and Pennsylvania. These contracts generally have one-year terms and include primarily commercial, institutional, industrial and governmental accounts. No single retail gas customer accounts for more than ten percent of Select Energy's expected retail gas revenues. In 2002, Select Energy's retail gas revenues were approximately $180 million representing approximately a 13 percent increase compared to 2001.
ENERGY TRADING
Select Energy trades a number of energy-related products in the Eastern United States, primarily for price discovery and risk management purposes. The trading segment of the business can buy, sell, hold or trade any energy futures, options, third party or counter-party positions for energy commodities. The energy trading business also includes entering into associated risk management products, including derivatives, as part of managing the exposure and risk of energy commodity trading.
In early 2002, after concluding that a mild winter and high natural gas inventories would result in falling prices, Select Energy established a significant "short" position in natural gas. Despite contrary fundamentals, natural gas prices rose significantly in March and April 2002, resulting, after break-even performance for the balance of 2002, in an after-tax loss of approximately $24 million for the year compared with earnings of $19 million in 2001. After April 2002, senior NU management decided to reduce significantly its speculative trading activities and the capital at risk in the trading area to a daily average of approximately $0.4 million from up to $6 million in early 2002 and is continuing to evaluate the scope and size of Select Energy's trading function. Management projects that its trading business will be modestly profitable in 2003.
NU provides credit assurance as the credit support provider in Select Energy's contracts, in the form of guarantees and letters of credit for the financial performance obligations of certain of its competitive energy subsidiaries. NU currently has authorization from the SEC to provide up to $500 million of guarantees through September 30, 2003, and has applied for authority to increase this amount to $750 million and extend the authorization period through September 30, 2005. As of December 31, 2002, NU had provided approximately $183 million of such guarantees and $7 million of letters of credit. In addition, NU's "aggregate investment" in Select Energy and its other energy service companies (but not including NGC, HWP or SESI) (which is inclusive of most such credit assurances) is limited by SEC rule to 15 percent of NU's most recent quarterly consolidated capitalization. NU has applied for authority to exempt its investments in such energy services companies from this limitation.
ELECTRIC GENERATION
NGC, NU's competitive electric generating affiliate, owns approximately 1,291 MW of hydroelectric and pumped storage generating assets in Connecticut and Massachusetts. NGC sells all of its energy and capacity to its affiliate, Select Energy. Select Energy's performance under its contract with NGC is guaranteed by NU. Select also buys and manages the entire generation output of approximately 147 MW from HWP's Mt. Tom generating plant under a renewable contract. Select Energy uses the NGC and Mt. Tom generation to furnish a portion of the resources it uses to meet supply commitments to its marketing customers.
NGC's contract with Select Energy extends through December 2005. About 85 percent of NGC's revenues from this contract (including all of the revenues from Northfield Mountain) are in the form of predetermined, fixed monthly payments based on the capacity of specified facilities. The remaining 15 percent of the revenues are in the form of monthly payments at predetermined rates per unit of actual energy output. NGC currently derives approximately 80 percent of its revenues from Northfield Mountain.
This contract provides NGC with a stable stream of revenues at prices that are currently higher than average wholesale electricity prices in the markets served by NGC's facilities. If NGC's agreement with Select Energy were to terminate at the end of its term in 2005, NGC may, depending upon market conditions, pursue similar contracts or choose to optimize the value of its assets in another manner. NGC plans to continue to evaluate growth opportunities in the northeastern United States; however, its ability to pursue such opportunities is limited by capital and regulatory constraints.
COMPETITIVE ENERGY SUBSIDIARIES' MARKET AND OTHER RISKS
NU's competitive energy subsidiaries, primarily Select Energy, are exposed to certain market and other risks inherent in their business activities.
A significant portion of their retail and wholesale marketing business is providing full requirements service to customers, primarily regulated distribution companies. The "full requirements" obligation commits these companies to supply the total energy requirement for the customers' load at all times. An important component of their risk management strategy is to manage the volume and price risks of their full requirements contracts. These risks include unexpected fluctuations in both supply and demand due to numerous factors which are not within their control, such as weather, plant availability, exposure to transmission congestion costs and price volatility. Select Energy's 2002 results were negatively impacted when contracted supply exceeded demand in the warmer than expected winter months and additional supply had to be acquired during summer months at higher than expected prices.
In serving its marketing customers, Select Energy utilizes derivative financial and commodity instruments, including futures and forward contracts, to manage the risk of fluctuating market prices. At December 31, 2002, Select Energy had net hedging derivative assets of $20.8 million, as compared to net derivative liabilities of $55.5 million at December 31, 2001. Generally, such derivatives impact earnings over the life of the contracts which they hedge, but in certain cases the impact is accelerated and affects earnings immediately.
In addition, Select Energy's trading business is exposed to certain risks. Select Energy trades in both financial derivative (non-physical delivery) and physical delivery transactions for electricity, natural gas and oil in which it attempts to profit from short-term changes in market prices. Energy trading contracts of both types are recorded at fair value, changes in which impact Select Energy's earnings in the period of change. Such fair values are derived from a number of sources, including market quotes of exchange-traded commodities, prices provided by external sources in over-the-counter transactions and, in rare cases, values derived from pricing models.
Select Energy's trading portfolio had a net positive $41 million fair value at December 31, 2002, as compared to a net positive $56.4 million fair value at December 31, 2001. Approximately 90 percent of the $41 million was priced from external sources, while the balance of approximately $4.5 million was from pricing models, and only a nominal amount was based on exchange quotes. Of the $41 million of net fair value in the trading portfolio at December 31, 2002, $1.6 million will mature in 2003, $24.8 million in 2004-2007 and $14.6 million after 2007. Generally, valuations of short-term contracts derived from quotes or other external sources are more reliable while valuations based on trading models are less certain.
Accordingly, there is a risk that the trading portfolio will not be realized in the amount recorded. Realization of cash will depend upon a number of factors over which Select Energy has limited or no control, including the accuracy of its valuation methodologies, the volatility of commodity prices, changes in market design and settlement mechanisms, the outcome of future transactions, the performance of counterparties, the breadth and depth of the trading market and other factors.
In addition, the application of derivative accounting principles is complex and requires management judgment in identification of derivatives and embedded derivatives, election and designation of the "normal purchases and sales" exceptions, identifying hedge relationships and assessing hedge effectiveness, determining the fair value of derivatives and measuring hedge ineffectiveness. All of these judgments, depending upon their timing and effect, can have a significant impact on the competitive subsidiaries' performance and, ultimately, NU's consolidated net income.
Risk management within the competitive energy subsidiaries, including Select Energy, is organized by management to address the market, credit and operational exposures arising from the company's primary business segments, including wholesale marketing, retail marketing and trading. The framework and degree to which these risks are managed and controlled is consistent with the limitations imposed by NU's Board of Trustees as established and communicated in NU's overall risk management policies and procedures. As a means to monitor and control compliance with these policies and procedures, NU has formed a Risk Oversight Council (ROC) to monitor competitive energy risk management processes independently from the businesses that create or manage these risks. The ROC ensures that the policies pertaining to these risks are followed and makes recommendations to the Board of Trustees regarding periodic adjustment to the metrics used in measuring and controlling portfolio risk while also confirming the methodologies employed by management to discern portfolio values.
ENERGY MANAGEMENT SERVICES
NUEI has two affiliated companies in the energy management business: NGS and SESI.
NGS was formed in 1999 to provide a full range of integrated energy- related services to owners of generation facilities and the industrial market in the Northeast. NGS designs, builds, manages, operates, maintains and supports electric power generating equipment, facilities and associated transmission and distribution equipment and provides turnkey management and operation services to owners of electric generation facilities. NGC and HWP have contracted with NGS to operate and maintain all of their generating plants.
Through its wholly-owned subsidiaries, E.S. Boulos Company and Woods Electrical Co., Inc. (Woods Electrical), NGS provides electrical construction and contracting services. These services focus on high and medium voltage installations and upgrades and substation and switchyard construction. Woods Network Services, Inc. (Woods Network), a subsidiary of NUEI, is a network products and services company. Woods Electrical and Woods Network were acquired in July 2002 for an aggregate adjusted purchase price of $16.3 million.
NGS's construction and maintenance services include construction management and mechanical construction and maintenance services for industrial and power generation customers. NGS also provides consulting services to its customers, including engineering and design, asset development, due diligence reviews and environmental regulatory compliance and permitting services. In addition, NGS provides laboratory analyses and specialized electrical testing services.
During 2002, NGS's revenues were approximately $76 million, excluding intercompany transactions, and are forecasted to grow by approximately 30 percent in 2003. This anticipated growth is expected to be driven by NGS's increased geographical scope, additional contracts with both new and repeat customers and the effect of recent acquisitions. Thirty-six percent of NGS's revenues in 2002 were derived from contracts with its affiliates NGC, PSNH, SESI and HWP.
SESI was acquired in 1990 and provides energy efficiency, design and construction solutions to government, institutional and commercial facilities. In delivering its services, SESI focuses on reducing its customers' energy costs, improving the efficiency and reliability of their energy-consuming equipment and conserving energy and other resources. SESI also designs, builds and maintains central energy plants producing power, heating and cooling for their hosts. SESI's engineering and construction management services have been directed primarily to markets in the eastern United States. SESI's subsidiary, Select Energy Contracting, Inc. (SECI), provides service contracts and mechanical and electrical contracting, primarily directed to energy systems in commercial markets.
In competitive procurements by the United States Departments of Defense and Energy and the General Services Administration, SESI has been selected as an "Energy Saving Performance Contractor" (ESPC) for all fifty states and overseas facilities. Over the last several years, SESI became one of the major providers of design, construction, financing and long-term operation and maintenance of energy-efficient and environmentally clean systems to replace older infrastructure. SESI has recently installed the largest fuel cell-based energy plant in the United States (at a state school in Connecticut) and the new stand-alone energy plant at Bradley International Airport in Connecticut. SESI is under contract to operate and maintain the plants for at least 20 years. In 2002, federal ESPC work constituted 20 percent of SESI's revenues, which were approximately $99 million. In 2003, SESI's revenues are anticipated to grow by approximately 30 percent based on existing backlog and continuing success in its existing business lines.
TELECOMMUNICATIONS
Mode 1 was established in 1996 to participate in a wide range of telecommunications activities both within and outside New England and is currently owned by NUEI. Mode 1 is a licensed competitive local exchange carrier authorized to provide local phone service within the state of Connecticut. Mode 1 provides telecommunication network services at the retail and wholesale levels, primarily dark fiber. It has built high speed fiberoptic connectivity to secondary and tertiary markets within cities such as Hartford, Connecticut and serves the City of Hartford's schools and libraries with an optical network.
NU has invested approximately $22 million in Mode 1 since it was established, which investment was principally used to fund Mode 1's investment in NEON Communications, Inc., a wholesale telecommunication infrastructure provider of dark and light fiber-optic services (NEON). As of January 1, 2002, Mode 1 was the largest equity investor in NEON, owning approximately 19.3 percent of the common shares of NEON. NEON is a wholesale provider of high bandwidth, advanced optical networking solutions and services on intercity, regional and metro networks in the twelve-state Northeast and mid-Atlantic markets, utilizing a portion of the NU system companies' transmission and distribution facilities. An officer and trustee of NU is a member of the Board of Directors of NEON.
In June 2001, NEON and Mode 1 entered into a purchase agreement pursuant to which Mode 1 purchased from NEON an 18 percent subordinated convertible note due 2008 in the principal amount of $15 million (Note). On June 25, 2002 NEON filed for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code. Following negotiations with its senior debtholders and Mode 1, NEON filed a plan of reorganization and emerged from bankruptcy on December 22, 2002. Under NEON's plan of reorganization, all existing shares of NEON's common stock, including those held by Mode 1, were cancelled along with the Note held by Mode 1. As part of the reorganization, Mode 1 agreed to purchase seven percent of the outstanding securities of the reorganized NEON for approximately $3.2 million. This phase of NEON's reorganization closed in December 2002.
FINANCING PROGRAM
2002 FINANCINGS
On January 30, 2002, PSNH Funding LLC 2, a subsidiary of PSNH, sold $50 million of additional RRBs at an interest rate of 4.58 percent. The bonds, which were rated AAA by three credit rating agencies, will amortize over the next six years with an average maturity of 3.5 years and have a scheduled maturity date of February 1, 2008. PSNH used the proceeds to repay short-term debt that was incurred to buy out a high-cost purchase power obligation in December 2001. In 2001, funding affiliates of PSNH, CL&P and WMECO sold an aggregate of approximately $2.1 billion of RRBs and RRCs in similar transactions. All RRBs and RRCs are payable solely from collections from customers of PSNH, CL&P and WMECO, respectively, and are non-recourse to the companies.
On April 4, 2002, NU issued $263 million of 10-year senior unsecured notes. The notes carry a coupon of 7.25 percent and mature on April 1, 2012. Proceeds from the issuance were used to redeem a similar amount of variable rate notes that were issued on February 28, 2001 to finance NU's merger with Yankee.
On July 10, 2002, CL&P renewed its accounts receivable securitization bank credit line and extended its termination date to July 9, 2003. The credit line capacity remained the same at $100 million.
On August 29, 2002, SESI entered into an assignment of delivery orders payments (Assignment) with a financing entity, BFL Funding IV LLC (BFL), to finance the construction and installation of certain energy conservation measures at several federal government installations which SESI had agreed to install pursuant to delivery orders issued by the federal government. Pursuant to the Assignment, SESI assigned the payments due under the delivery orders by the federal government to BFL in exchange for $12.5 million. BFL issued $12.6 million of trust certificates at an interest rate of 6.25 percent that mature in October 2021 to fund this payment. Certain obligations of SESI under the transaction documents and the delivery order payments due from the government are backed by an NU parent guaranty.
On September 9, 2002, CL&P entered into a replacement standby bond purchase agreement supporting the 1996A series pollution control revenue bonds (PCRBs). The $62.9 million, 364-day agreement replaced a similar agreement and expires on October 21, 2003. The original transaction was approved by the DPUC in 1997.
On October 24, 2002, Hannie Mae LLC purchased from SESI monies due or to become due under certain task order contracts for $30 million. The proceeds will be used to fund the construction of energy conservation projects at several governmental facilities and will be recorded as debt as construction draws occur through April 2004. The interest rate is approximately 7.65 percent and the amortizing debt will mature on December 1, 2026. The debt, payable from the resulting energy savings, is backed by an NU parent guaranty.
On November 1, 2002, NAEC used its share of proceeds from the sale of the Seabrook nuclear generating station to pay off its $90 million term credit agreement that expired on November 9, 2001.
On November 12, 2002, CL&P, WMECO, PSNH and Yankee Gas entered into a new unsecured 364-day revolving credit facility for $300 million, replacing a similar $350 million facility that was due to expire on November 15, 2002. CL&P may draw up to $150 million, and WMECO, PSNH and Yankee Gas may draw up to $100 million each, subject to the $300 million maximum for the entire facility. Unless extended, the credit facility will expire on November 11, 2003.
On November 12, 2002, NU entered into a new unsecured 364-day revolving credit facility for $350 million, replacing a similar $300 million facility that was due to expire on November 15, 2002. The facility supports the working capital needs of NU and its competitive subsidiaries. The new facility provides a total commitment of $350 million which is available subject to two overlapping sub-limits. First, subject to the notional amount of any letters of credit outstanding, amounts up to $350 million are available for advances. Second, subject to the advances outstanding, letters of credit may be issued in an aggregate amount of up to $250 million, an increase of $50 million over the prior facility. The agreement provides for letters of credit to be issued in the name of NU or any of its subsidiaries. Unless extended, the credit facility will expire on November 11, 2003.
NU paid common dividends totaling $67.8 million in 2002, compared to $60.9 million paid in 2001, reflecting increases in the quarterly dividend rate that were effective September 30, 2001 and September 30, 2002. The higher levels of dividends were easily accommodated by rising general liquidity at the NU parent level, due in part to the continued return of equity capital from the regulated subsidiaries, as well as their payment of common dividends to the parent. Liquidity at the parent company is also reinforced by the absence of debt maturities and minimal sinking fund payments in the near term ($23 million in 2003 and $24 million in 2004).
Total NU system debt, including short-term and capitalized lease obligations but not including RRCs and RRBs, was $2.4 billion as of December 31, 2002, compared with $2.7 billion as of December 31, 2001. The decrease was primarily due to a reduction in short-term bank borrowings.
For more information regarding NU system financing, see "Notes to Consolidated Statements of Capitalization" in NU's financial statements, other footnotes related to long-term debt, short-term debt and the sale of accounts receivables, as applicable, in the notes to NU's, CL&P's, PSNH's, and WMECO's financial statements and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."
2003 FINANCING REQUIREMENTS
The NU system's aggregate capital requirements for 2003 are approximately as follows:
Yankee NU CL&P PSNH WMECO Gas Other System (Millions) Construction $327 $116 $ 28 $ 73 $ 96 $640
Maturities 0 0 0 0 0 0 Cash Sinking Funds * 0 0 0 2 55 57 ---- ---- ---- ---- ---- ---- Total $327 $116 $ 28 $ 75 $151 $697 ==== ==== ==== ==== ==== ====
* CL&P, WMECO and PSNH have sinking funds associated with RRCs and RRBs that are not included in the capital requirements subtotal. All interest and principal payments for these bonds are collected through a non-bypassable charge assessed to customers and do not represent additional capital requirements.
For further information on the NU system's 2003 financing requirements, see "Notes to Consolidated Statements of Capitalization" in NU's financial statements, "Long-Term Debt" in the notes to CL&P's, PSNH's and WMECO's financial statements and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."
2003 FINANCING PLANS
NU projects a moderate level of system financings in 2003.
CL&P is contemplating the issuance of up to $220 million of debt to refinance its pre-1983 spent nuclear fuel obligations and has applied to the DPUC for authority to issue this debt. CL&P has also announced plans for the construction of various transmission facilities. The projects require numerous federal and state regulatory approvals. If approved, construction of these facilities would require external financing. See "Financing Program - Construction and Capital Improvement Program."
WMECO has applied to the DTE to issue approximately $105 million of debt to refinance its existing short-term debt and pre-1983 spent nuclear fuel obligations.
Yankee Gas may seek to issue up to $75 million of long-term debt in 2003 to finance its capital requirements and may also require additional debt issuances in later years, depending on the extent of its capital program. Yankee Gas is currently implementing a number of capital projects and is planning the construction of a liquefied natural gas storage and production facility in Waterbury, Connecticut that could cost approximately $60 million. See "Financing Program - Construction and Capital Improvement Program."
FINANCING LIMITATIONS
Many of the NU system companies' charters and borrowing facilities contain financial limitations that must be satisfied before borrowings can be made and for outstanding borrowings to remain outstanding. In addition, the NU system companies are subject to certain federal and state orders and policies which limit their financial activities.
Under their current revolving credit facility agreement, CL&P, WMECO, PSNH and Yankee Gas are allowed to maintain a ratio of debt to total capitalization (leverage ratio) of no more than 65 percent. At December 31, 2002, CL&P's, WMECO's, PSNH's, and Yankee Gas's leverage ratios were 44 percent, 48 percent, 56 percent and 30 percent, respectively. This agreement also requires the companies to maintain 12-month earnings before interest and taxes to interest expense ratio (interest coverage ratio) of at least 2.25 to 1.0. At December 31, 2002, CL&P's, WMECO's, PSNH's and Yankee Gas' interest coverage ratios were 4.37 to 1, 10.78 to 1, 6.54 to 1 and 2.76 to 1, respectively. These ratios do not include RRBs and RRCs.
NU is allowed, under its current revolving short-term credit agreement facility, to maintain a debt to total capitalization (leverage ratio) of no more than 66 percent. At December 31, 2002, NU's leverage ratio was 50 percent. In addition, NU is required to maintain a 12-month consolidated interest coverage ratio of at least 2.0 to 1.0. This covenant was reduced from 2.25 to 1.0 in the prior year's facility to provide additional flexibility to NU. At December 31, 2002, NU's consolidated interest coverage ratio was 2.57 to 1.0. These ratios do not include RRBs and RRCs.
The amount of short-term debt that may be incurred by NU, CL&P, PSNH, WMECO, NAEC, Northeast Nuclear Energy Company (NNECO), Yankee, Yankee Gas and HWP is also subject to periodic approval by the SEC under the Public Utility Holding Company Act of 1935 (1935 Act). Current short-term debt authorizations expire on June 30, 2003 and NU plans to file in early 2003 with the SEC to extend the short-term debt authority for these companies and to add certain additional subsidiaries to the Northeast Utilities System Money Pool (Pool). PSNH's and NAEC's short-term debt in excess of 10 percent of net fixed plant is also regulated by the NHPUC. The following table shows the amount of short- term borrowings authorized by the SEC or the NHPUC for each company, as the case may be, as of December 31, 2002, and the amounts of outstanding short-term debt of those companies at the end of 2002 and as of March 3, 2003:
Maximum Authorized Outstanding Short-Term Debt Short-Term Debt (1) December 31, 2002 March 3, 2003 (Millions)
NU $400 $ 0.0 $ 0.0 CL&P 375 38.1 14.0 PSNH (2) 225 0.0 0.0 WMECO 250 92.9 86.8 NAEC(3) 260 0.0 0.0 NNECO 75 0.0 0.0 Yankee 50 0.0 0.0 Yankee Gas 100 66.0 58.6 HWP 5 0.0 0.0 Select Energy N/A 217.2 161.7 NGS(4) N/A 18.5 17.9 SESI(4) N/A 6.5 0.0 RRR(4) N/A 32.7 33.0 Other 7.5 9.3 ------ ------ Total $479.4 $381.3 ====== ======
(1) These columns include borrowings of various NU system companies from NU and other NU system companies. Total NU system short-term indebtedness to unaffiliated lenders was $56 million at December 31, 2002 and $20 million at March 3, 2003.
(2) Under applicable NHPUC provisions, PSNH can incur short-term debt up to $100 million.
(3) Under applicable NHPUC regulations, NAEC can incur short term debt up to 10 percent of net fixed plant or such other amount as approved by the NHPUC. Prior to the sale of Seabrook, NAEC had authorization from the NHPUC to issue up to $260 million of short-term debt. NAEC has no plans to incur any future short-term borrowings.
(4) The SEC limits, as indicated, the following companies' borrowings from the Pool (but not borrowings from either parent companies or non-affiliates): NUEI ($100 million); Select Energy ($200 million); NGS ($20 million); SESI ($20 million) and The Rocky River Realty Company (RRR) ($30 million). NU, NGC and Mode 1 may lend to but are not authorized to borrow from the Pool.
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 NU system companies' stock, limitations of liens on NU assets and restrictions on distributions on and acquisitions of NU stock. Under these provisions, NU, CL&P, PSNH and WMECO may not dispose of voting stock of CL&P, PSNH or WMECO other than to NU or another NU 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. Many of the NU system companies' credit agreements have similar restrictions. As of December 31, 2002, no NU debt was secured by liens on NU assets. Furthermore, NU may not declare or make distributions on its capital stock, acquire its capital stock (or rights thereto), or permit an NU system company to do the same, at times when there is an event of default existing under the supplemental indentures under which the amortizing notes were issued.
The indenture under which NU issued $263 million in principal amount of 7.25 percent notes in April 2002 contains a limitation of liens on NU assets and a limitation of sale and leaseback transactions on those assets.
CL&P's charter contains preferred stock provisions restricting the amount of additional unsecured debt it may incur. As of December 31, 2002, the amount of additional unsecured debt it could incur was $480 million.
The indentures securing the outstanding first mortgage bonds of CL&P provide that additional bonds may not be issued, except for certain refunding purposes, unless earnings are at least twice the pro forma annual interest charges on outstanding bonds, and certain prior lien obligations and bonds to be issued.
The preferred stock provisions of CL&P's charter 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. At December 31, 2002, CL&P's income before interest charges was approximately 2.95 times the pro forma annual interest and dividend requirements. CL&P has no current plans to issue any preferred stock.
Certain consolidated subsidiaries have dividend restrictions imposed by their long-term debt agreements. These restrictions also limit the amount of retained earnings available for NU common dividends. At December 31, 2002, retained earnings available for the payment of dividends totaled $765.6 million.
The Federal Power Act limits the payment of dividends by PSNH, NAEC, CL&P, and WMECO to retained earnings. At December 31, 2002, retained earnings for these companies were $195 million, $20.3 million, $308.6 million and $77.5 million, respectively.
New Hampshire statutes also limit the payment of dividends by PSNH and NAEC to the amount of retained earnings.
CL&P's first mortgage bond indenture limits dividend payments and share repurchases to an amount equal to (i) retained earnings accumulated after December 31, 1966; plus (ii) retained earnings accumulated prior to January 1, 1967, not exceeding $13.5 million; plus (iii) any additional amounts authorized by the SEC. In 2000 and 2002, the SEC approved CL&P's proposal to pay dividends and repurchase shares from capital or unearned surplus of up to $410 million in aggregate from proceeds derived from industry restructuring transactions.
Applicable merger accounting rules required that upon acquisition by NU, Yankee's and its subsidiaries' retained earnings were reclassified as capital surplus. Also, the merger premium NU paid to acquire Yankee was allocated among Yankee and its subsidiaries and "pushed down" to their balance sheets. Under accounting conventions in existence at the time of the merger, the majority of the merger premium would be amortized over 40 years. In June 2001, the Financial Accounting Standards Board issued a statement that, effective January 1, 2002, no longer requires companies to amortize goodwill as an expense to the income statement. Instead goodwill is required to be evaluated for impairment and any impairments to goodwill would be charged to expense. The effect of the new accounting standard was a $0.4 million annual reduction in goodwill amortization expense.
Under the 1935 Act, subsidiaries of registered holding companies are only allowed to pay dividends out of retained earnings unless the SEC allows otherwise. The effect of this rule would be to prevent Yankee from paying dividends to NU from any source other than post-merger earnings, as reduced by the merger premium amortization. NU had received permission from the SEC, through June 2002, for Yankee and Yankee Gas to pay dividends (i) out of additional paid-in capital up to the amount of their respective retained earnings just prior to the merger with NU and (ii) out of earnings before the amortization of the merger goodwill (gross earnings) in the case of Yankee Gas and out of distributed earnings in the case of Yankee. To assure that Yankee Gas has sufficient cash to fund operations, Yankee Gas will not pay dividends in excess of 80 percent of gross earnings on a rolling five-year average basis. In no case would dividends be paid by Yankee or Yankee Gas if their common equity to total capitalization ratios were below 35 percent. NU also received permission from the SEC, through June 2002, for Yankee and Yankee Gas to repurchase their common stock such that their common equity to total capitalization ratios do not fall below 35 percent. To date, Yankee Gas has paid no dividends to NU since the merger.
NGC bond covenants prevent NGC from making dividend payments unless (i) no default or event of default will occur from doing so, (ii) the debt service reserve account has been sufficiently funded with six months of principal and interest on the outstanding bonds, and (iii) the debt service coverage ratio for the previous four fiscal quarters (or, if shorter, since the bond issuance closing date) and projected debt service coverage ratio for the next eight fiscal quarters is (a) greater than or equal to 1.35 if contracted generating capacity is greater than 75 percent or (b) greater than or equal to 1.70 if contracted generating capacity is less than 75 percent. At December 31, 2002, NGC's contracted generating capacity was greater than 75 percent. NGC expects to meet its debt service coverage ratio requirements under this covenant and to pay dividends in 2003.
NU is required under the 1935 Act to maintain its consolidated common equity at a level equal to at least 30 percent of its consolidated capitalization. In planning for the issuance of RRBs and RRCs by its subsidiaries in 2001, NU anticipated being unable to meet this standard because such bonds and certificates, although nonrecourse to the NU system company issuers, are considered to be indebtedness of the companies under generally accepted accounting principles. In 2000, the SEC authorized the consolidated common equity ratio of NU to fall below 30 percent through December 31, 2002 on account of such sales and certain related restructuring transactions. NU's consolidated common equity ratio was greater than 30 percent as of December 31, 2002 and is expected to remain above this level in the future. The 30 percent test also applies to NU's electric operating subsidiaries. The SEC has consented to the common equity ratios of CL&P, WMECO and PSNH falling below 30 percent through December 31, 2004. As of December 31, 2002, NU's, CL&P's, WMECO's and PSNH's ratios were 33.6 percent, 24.1 percent, 31.9 percent and 26 percent, respectively. These ratios include RRBs and RRCs as debt.
NU provides credit assurance in the form of guarantees and letters of credit for the financial performance obligations of certain of its unregulated subsidiaries. NU currently has authorization from the SEC to provide up to $500 million of such guarantees through September 30, 2003 and has applied for authority to increase this amount to $750 million and extend the authorization period through September 30, 2005. As of December 31, 2002, NU had provided approximately $183 million and $7 million, respectively, of such guarantees and letters of credit. As of January 31, 2003, NU had provided approximately $234 million and $22 million, respectively, of such guarantees and letters of credit.
Certain NU system credit financing agreements have trigger events tied to the credit ratings of certain NU system companies, as discussed below.
RRR is a real estate subsidiary that owns NU's Connecticut headquarters site. It has approximately $6.5 million of debt outstanding that could be affected by a ratings change. If NU, CL&P, PSNH or WMECO ratings fall below a B1 Moody's rating or a B+ Standard & Poor's rating, bondholders would have the right to demand mandatory prepayments.
NGC has a debt reserve account related to the $440 million bond issue that can be funded with cash, an NU guarantee or a letter of credit from an acceptable counterparty. The account is currently funded with cash and may be funded with a guarantee from NU only if NU has an investment grade rating by Standard & Poor's and Moody's.
NU and its subsidiaries have $650 million of revolving credit agreements with a number of banks. There are no ratings triggers that would result in a default, but lower ratings would increase interest on future borrowings from the credit lines.
A number of Select Energy's contracts require the posting of additional collateral in the form of cash or letters of credit in the event NU's ratings were to decline and in increasing amounts dependent upon the severity of the decline. At NU's present investment grade ratings, Select Energy has not had to post any collateral based on credit downgrades. Were NU's unsecured ratings to decline two to three levels to sub-investment grade, Select Energy would, under its present contracts, be asked to provide approximately $140 million of collateral or letters of credit to various unaffiliated counterparties and approximately $80 million to several independent system operators (ISO) and unaffiliated local distribution companies, which NU, under present circumstances, would be able to provide from available sources. NU's ratings are currently stable, and management does not believe that at this time there is a significant risk of a ratings downgrade to sub-investment grade levels.
CONSTRUCTION AND CAPITAL IMPROVEMENT PROGRAM
The NU system's construction program expenditures, including allowance for funds used during construction, is estimated to total $640 million in 2003. Of such total amount, approximately $327 million is expected to be expended by CL&P, $116 million by PSNH, $73 million by Yankee Gas, $28 million by WMECO and up to $96 million by other system entities. This construction program data includes all anticipated costs necessary for committed projects and for those reasonably expected to become committed projects in 2003, regardless of whether the need for the project arises from environmental compliance, reliability requirements or other causes. The construction program's main focus is maintaining, upgrading and expanding the existing transmission and distribution system and natural gas distribution system. The system expects to evaluate its needs beyond 2003 in light of future developments, such as restructuring, industry consolidation, performance and other events.
The $96 million in construction expenditures planned for other system entities in 2003 includes $23 million for NUEI (including NGS).
CL&P has announced plans to invest approximately $535 million by the end of 2008 to construct two new 345,000 volt transmission lines from inland Connecticut to Norwalk, Connecticut and another $40 million to replace an existing 138,000 volt transmission line beneath Long Island Sound. The investment in transmission lines and continued upgrading of the electric distribution system are expected to increase CL&P's net investment in electric plant by between $240 million and $360 million for the years 2003 to 2005. All of these projects are in the developmental or governmental approval stage and management cannot yet determine whether the projects will be built as proposed. If current plans are implemented on schedule, the NU system would likely require additional external financing to construct these projects. If all of the transmission projects are built as proposed, the NU system's net investment in electric transmission would increase to nearly $1.1 billion by the end of 2008.
Yankee Gas will continue to emphasize system expansion of its natural gas distribution system in Connecticut and plans to move forward with its three year plan to install a liquid natural gas facility in Waterbury, Connecticut. See "Connecticut Rates and Restructuring" for information on Yankee Gas' DPUC filing and the related decision.
REGULATED ELECTRIC OPERATIONS
DISTRIBUTION AND SALES
CL&P, PSNH and WMECO furnish retail franchise electric service in 149, 201 and 59 cities and towns in Connecticut, New Hampshire and Massachusetts, respectively. In December 2002, CL&P provided retail franchise service to approximately 1.2 million customers in Connecticut, PSNH provided retail service to approximately 449,000 customers in New Hampshire and WMECO served approximately 204,000 retail customers in Massachusetts.
The following table shows the sources of 2002 electric franchise retail revenues based on categories of customers (exclusive of HWP):
Total NU CL&P PSNH WMECO System ---- ---- ----- --------
Residential 46% 42% 45% 45% Commercial 40% 38% 36% 39% Industrial 12% 19% 18% 15% Other 2% 1% 1% 1% ---- ---- ---- ---- Total 100% 100% 100% 100% ==== ==== ==== ====
The actual changes in retail kWh sales for the last two years and the forecasted retail sales growth estimates for the ten-year period 2003 through 2012 for CL&P, PSNH and WMECO are set forth below:
Forecast 2003-2012 2002 over 2001 over Compound Rate 2001 2000 Of Growth NU System 1.3% 2.3% 1.0% CL&P 1.8% 2.4% 1.0% PSNH -0.1% 3.9% 1.5% WMECO 1.9% -0.9% 0.7%
Consolidated NU retail sales rose by 1.3 percent in 2002, compared with 2001, primarily due to higher cooling requirements. Residential electric sales were up 4.5 percent. Commercial sales were up by 2.6 percent for the year and industrial sales decreased by 7.7 percent. Retail sales for CL&P, WMECO and PSNH were up 1.8 percent, up 1.9 percent and down 0.1 percent, respectively.
REGIONAL AND SYSTEM COORDINATION
The NU system companies and most other New England utilities are parties to an agreement (NEPOOL Agreement), which provides for coordinated planning and operation of the region's generation and transmission facilities. The NEPOOL Agreement was restated and revised as of March 1997 to provide for (i) a pool- wide open access transmission tariff; (ii) the creation of an ISO; and (iii) a broader governance structure for New England Power Pool (NEPOOL) and a more open, competitive market structure. Under these new arrangements the ISO, a nonprofit corporation whose board of directors and staff are not controlled by or affiliated with market participants, ensures the reliability of the NEPOOL transmission system, administers the NEPOOL tariff and oversees the efficient and competitive functioning of the regional power market.
The NEPOOL tariff provides for nondiscriminatory open access to the regional transmission network at a single rate regardless of transmitting distance for all transactions. The rate is a formula rate, structured to ensure that each transmission provider under the NEPOOL tariff recovers its revenue requirements.
In 1999, the NEPOOL Executive Committee filed a comprehensive settlement of all issues set for hearing concerning the NEPOOL transmission tariff. The settlement resolves disputes concerning the calculation of revenue requirements for transmission over NEPOOL facilities and resolves disputes over alleged "double charges" under grandfathered transmission contracts retained by individual transmission providers, including the NU system. The settlement also includes a return on earnings (ROES) component which sets the ROES for each individual transmission provider owning NEPOOL transmission facilities with respect to those facilities from March 1, 1997 through at least June 1, 2000, provided no changes to individual network transmission tariff rates are made after December 31, 1999. NU's ROES has been set at 11.75 percent. NU has made no changes to its transmission tariff rates since the settlement was reached; accordingly, its ROES has remained unchanged.
As part of the settlement, ISO is required to independently audit the charges in effect for the period June 1997 through May 2000 or direct that such an audit be conducted under its supervision. In June 2000, ISO engaged an independent auditing firm to conduct such an audit. The audit was conducted over a two-year period and the resulting audit report was filed at FERC on April 24, 2002. The audit report identified several areas of disagreement between the auditors and the audited transmission owners. The issues are currently being addressed through an alternative dispute resolution process with the FERC.
In December 2000, NU was notified by FERC that it, along with several other companies, would be the subject of a separate FERC industry-wide audit of the accounting related to formula rate transmission tariffs. FERC commenced its audit of NU in February 2001 and an exit conference was held on February 12, 2002.
Under an agreement (NUG&T) among CL&P, WMECO and HWP, these companies pool their electric production costs and the costs of their principal transmission facilities. The NUG&T was revised in 1999 to eliminate the generation aspects of the agreement. Final agreement from FERC on this revision was granted in October 2000.
Transmission revenues are allocated between the NUG&T signatories (CL&P, HWP, WMECO) and PSNH based upon the respective companies' cost of service.
TRANSMISSION ACCESS AND FERC REGULATORY CHANGES
Pursuant to FERC Order 888 (issued in April 1996), NU system companies operate their transmission system under an open access, nondiscriminatory transmission tariff.
In December 1999, the FERC issued an order calling on all transmission owners to voluntarily join RTOs in order to boost competition in electric markets (Order 2000). In general, each such organization would be an independent operator over all transmission facilities, and would perform, among other functions, tariff administration, construction planning and reliability management for the particular regional transmission system.
In January 2002, ISO-New England and New York ISO proposed to FERC that the two pools combine to form a single RTO. On November 22, 2002 the ISOs withdrew their application. On January 16, 2003, ISO-New England announced its intent to file a joint application with the New England transmission organizations to create a New England RTO.
On July 15, 2002, the NEPOOL Participants Committee and ISO-New England management filed a new NEPOOL market rule in a joint filing to implement SMD in New England. SMD would adopt LMP as a congestion tool as well as other market features similar to market rules in New York and the Pennsylvania-New Jersey- Maryland (PJM) Interconnection. The proposed New England SMD also includes market mitigation rules that would allow ISO-New England to set congestion proxy prices within certain Designated Congestion Areas (DCA) and would allow ISO-New England to utilize RMR contracts to ensure the availability of certain generating plants to run when it would otherwise be uneconomic for such plants to do so in order to maintain system reliability. NU intervened in the SMD docket at FERC largely supporting the new market rules, with the exception of the DCA proposal which, if implemented without restrictions on the ISO, NU believes could artificially inflate prices in DCAs. The New England SMD proposal was approved by FERC on December 20, 2002 and was implemented on March 1, 2003.
In response to concerns raised by the DPUC and the Connecticut Attorney General concerning the impact of LMP on transmission constrained areas such as southwest Connecticut, FERC held that the costs of transmission expansion projects already identified in ISO-New England's 2002 regional transmission expansion plan (i.e., NU's Phase I and Phase II southwest Connecticut projects) built within five years from the date of the order should be spread across the New England region. The December 20, 2002 Order also approved the DCA mitigation proposal, however, in apparent recognition of the inherent flaws of the DCA methodology, required ISO-New England to comment within 90 days on an alternative methodology. NU is seeking rehearing of the order with respect to the DCA approval. For further information regarding the effect of SMD in the NU system companies service territory, see "Rates and Electric Industry Restructuring-Connecticut Rates and Restructuring."
On July 31, 2002, FERC issued a notice of proposed rulemaking (NOPR) on SMD. The SMD NOPR would require markets to adopt rules similar to those proposed in the New England SMD, but would also require transmission owners to either transfer ownership or operational control over their transmission facilities to an independent transmission provider (ITP) or to become an ITP. An ITP is similar to the RTO required by Order 2000 except that it need not cover as large a geographic area as RTOs. The SMD NOPR also proposes to change the nature of transmission service by eliminating the notion of non-firm service and establishing priority of service based on the customer's holding of financial transmission rights. Comments were filed on November 15, 2002 and a second round of comments on more controversial issues such as transmission planning and pricing, financial transmission rights and resource adequacy requirements were filed on January 10, 2003. A final rule is expected to be issued some time in 2003.
REGULATED GAS OPERATIONS
In March 2000, NU acquired Yankee and Yankee became a wholly owned subsidiary of NU. Yankee is the parent of Yankee Gas, the largest natural gas distribution company in Connecticut. Yankee continues to act as the holding company of Yankee Gas and its two active nonutility subsidiaries, NorConn Properties, Inc. (NorConn), which holds the property and facilities of Yankee and its subsidiaries, and Yankee Energy Financial Services Company, which provides customers with financing for energy equipment installations.
Yankee Gas operates the largest natural gas distribution system in Connecticut as measured by number of customers and size of service territory. Total throughput (sales and transportation) for 2002 was 49.9 billion cubic feet. In 2002, total gas operating revenues of $293 million were comprised of the following: 48 percent residential; 28.1 percent commercial; 19.4 percent industrial; and the remaining 4.1 percent other. Yankee Gas provides firm gas sales service to customers who require a continuous gas supply throughout the year, such as residential customers who rely on gas for their heating, hot water and cooking needs. Yankee Gas also provides interruptible gas sales service to certain commercial and industrial customers that have the capability to switch from natural gas to an alternative fuel on short notice. Yankee Gas can interrupt service to these customers during peak demand periods. Yankee Gas offers firm and interruptible transportation services to customers who purchase gas from sources other than Yankee Gas. In addition, Yankee Gas performs gas sales, gas exchanges and capacity releases to marketers to reduce its overall gas expense.
Although Yankee Gas is not subject to FERC jurisdiction, the FERC does regulate the interstate pipelines serving Yankee Gas' service territory. Yankee Gas, therefore, is directly and substantially affected by the FERC's policies and actions. Accordingly, Yankee Gas closely follows and, when appropriate, participates in proceedings before the FERC.
Yankee Gas is subject to regulation by the DPUC, which, among other things, has jurisdiction over rates, accounting procedures, certain dispositions of property and plant, mergers and consolidations, issuances of securities, standards of service, management efficiency and construction and operation of distribution, production and storage facilities. For information relating to Yankee Gas DPUC proceedings, see "Rates and Electric Industry Restructuring - Connecticut Rates and Restructuring."
For information on the proposed expansion of Yankee Gas' natural gas delivery system in Connecticut, see "Construction and Capital Improvement Program."
NUCLEAR GENERATION GENERAL
During 2002, certain NU system companies had ownership interests in one nuclear unit, Seabrook, and equity interests in four regional nuclear companies (the Yankee Companies) that separately own the Connecticut Yankee nuclear unit (CY), the Maine Yankee nuclear unit (MY), VY (prior to its sale) and the Yankee Rowe nuclear unit (Yankee Rowe). One NU system company operated Seabrook prior to its sale in November 2002. Yankee Rowe, CY and MY have been permanently removed from service and are being decontaminated and decommissioned.
On November 1, 2002, CL&P and NAEC and certain nonaffiliated joint owners consummated the sale of their collective 88.2 percent interests in Seabrook to FPL. The remaining interests held by certain other nonaffiliated joint owners were retained by those entities. The NU system received approximately $384 million of cash proceeds from the sale and used those proceeds primarily to pay down debt maturing in less than one year. As part of the sale, FPL assumed responsibility for decommissioning Seabrook.
Before Seabrook was sold to FPL, CL&P and NAEC together owned 40.04 percent of Seabrook as tenants in common. Their respective ownership interests in each unit were 4.06 percent and 35.98 percent. The unit was shut down for a scheduled 28 day refueling outage beginning on May 4, 2002. The unit returned to service on June 1, 2002, completing the shortest outage in Seabrook's history. During 2002, Seabrook operated at a capacity factor of 90.2 percent through November 1, 2002, the date of closing on the sale of the unit.
CL&P, PSNH, WMECO and other New England electric utilities are the stockholders of the Yankee Companies. Each Yankee Company, other than VYNPC, owns a single nuclear generating unit. The stockholder-sponsors of each Yankee Company are responsible for proportional shares of the operating and decommissioning costs of the respective Yankee Company. The relative rights and obligations with respect to the Yankee Companies are approximately proportional to the stockholders' percentage stock holdings, but vary slightly to reflect arrangements under which nonstockholder electric utilities have contractual rights to some of the output of particular units. CL&P's, PSNH's and WMECO's stock ownership percentages in the Yankee Companies are set forth below: NU CL&P PSNH WMECO System Connecticut Yankee Atomic Power Company (CYAPC) 34.5% 5.0% 9.5% 49.0% Maine Yankee Atomic Power Company (MYAPC) 12.0% 5.0% 3.0% 20.0% Vermont Yankee Nuclear Power Corporation (VYNPC) 10.1% 4.3% 2.6% 17.0% Yankee Atomic Electric Company (YAEC) 24.5% 7.0% 7.0% 38.5%
The ownership interests of CL&P, PSNH and WMECO in VYNPC increased slightly in early 2002 when VYNPC redeemed the stock owned by certain Vermont municipal electric systems which had previously owned about five percent of VYNPC's stock.
In March 2001, the board of VYNPC voted to proceed to auction the plant. J.P. Morgan was selected to conduct the auction. In August 2001, the owners of VYNPC announced they would sell the VY unit to a subsidiary of Entergy Corporation for approximately $180 million (approximately $145 million for the plant, materials and supplies and $35 million for the nuclear fuel). NU subsidiaries owned 17 percent of the VY unit and, under the terms of the sale, will continue to buy 17 percent of the plant's output through March 2012 at fixed prices. The sale of the unit was consummated on July 31, 2002. Prior to its sale, VY operated at a capacity factor of 91.7 percent during 2002. Although there was no refueling outage in 2002 prior to the sale, a 12 day mid- cycle outage began on May 11, 2002. This outage was undertaken primarily to replace some defective fuel in the reactor.
In conjunction with the sales of Millstone in 2001 and Seabrook in 2002, NU terminated its nuclear insurance related to these plants. However, through its continuing association with Nuclear Electric Insurance Limited (NEIL) and its interests in CYAPC and VYNPC, NU is subject to potential retrospective assessments totaling $0.8 million under the respective NEIL insurance policies.
The NRC has broad jurisdiction over the design, construction and operation of nuclear generating stations, including matters of public health and safety, financial qualifications, antitrust considerations and environmental impact. The NRC also has jurisdiction over the decommissioning activities at Yankee Rowe, CY and MY.
NUCLEAR FUEL
GENERAL
In 1998, an action was initiated by the owners of Millstone in the United States Court of Federal Claims against the United States Department of Energy (DOE) regarding the special annual assessment that the DOE imposes on purchasers of enriched uranium to meet the future costs of decontaminating and decommissioning (D&D) of government owned uranium enrichment facilities. Similar actions for Seabrook and CY were also filed. The lawsuits challenge the imposition of the D&D assessment on federal constitutional grounds and are similar to actions filed by a number of other utilities against DOE. Proceedings in the Millstone, Seabrook and CY cases were stayed pending the final resolution of a similar claim brought against the DOE by MYAPC. In July 1999, the claims court dismissed MYAPC's complaint. In November 2001, the Federal circuit court affirmed the dismissal of MYAPC's claims. On February 6, 2002, MYAPC filed a petition for certiorari, asking the United States Supreme Court to review the decision of the Federal circuit court, which petition was denied on May 28, 2002. The Millstone case was dismissed on July 19, 2002.
Nuclear fuel costs associated with nuclear plant operations include amounts for disposal of spent nuclear fuel. The NU system companies include in their nuclear fuel expense spent fuel disposal costs accepted by the DPUC, NHPUC and DTE in rate case or fuel adjustment decisions. Spent fuel disposal costs also are reflected in the FERC-approved wholesale charges.
HIGH-LEVEL RADIOACTIVE WASTE
The Nuclear Waste Policy Act of 1982 (NWPA) provides that the federal government is responsible for the permanent disposal of spent nuclear reactor fuel (SNF) and other high-level waste. As required by the NWPA, electric utilities generating SNF and high-level waste are obligated to pay fees into a fund which would be used to cover the cost of siting, constructing, developing and operating a permanent disposal facility for this waste. The NU system companies have been paying for such services for fuel burned on or after April 7, 1983, on a quarterly basis since July 1983. The DPUC, NHPUC and DTE permit the fee to be recovered through rates. For nuclear fuel used to generate electricity prior to April 7, 1983 (prior-period fuel), payment must be made upon the first delivery of spent fuel to the DOE. The DOE's current estimate for an available site is 2010 at the earliest.
On July 9, 2002, the United States Senate approved a resolution designating the Yucca Mountain site in Nevada as the nation's repository for used nuclear fuel. With this vote of approval, Congress formally rejected the Nevada disapproval and affirmed President Bush's decision to designate Yucca Mountain as the repository site. The DOE can now prepare and file a license application with the NRC and begin the development of a transportation policy and plan.
In return for payment of the fees prescribed by the NWPA, the federal government is to take title to and dispose of the utilities' high-level wastes and SNF. There have been numerous litigation proceedings involving the DOE's statutory and contractual obligation to accept high-level waste and SNF. While the courts have declined to order the DOE to begin accepting spent fuel for disposal on January 31, 1998, the courts have left open the utilities' ability to bring damage claims against the DOE.
In 1998, YAEC, CYAPC and MYAPC filed separate complaints against the DOE in the United States Court of Federal Claims seeking monetary damages resulting from DOE's failure to accept spent nuclear fuel for disposal. In decisions later that year, the court found liability on the part of DOE to the companies for breach of the standard contract, based upon the DOE's failure to begin disposal of spent nuclear fuel. The damages owed to YAEC, CYAPC and MYAPC as a result of DOE's failure to begin disposing of spent nuclear fuel is in litigation and revised damage claims are expected to be filed in the spring of 2003.
Until the federal government begins accepting nuclear waste for disposal, nuclear generating plants will need to retain high-level waste and spent fuel onsite or make some other provisions for its storage.
Construction of dry spent fuel storage facilities, to hold the spent nuclear fuel and other high level waste generated at those facilities until the DOE accepts this waste, is in progress at CY, MY and Yankee Rowe. No fuel has yet been moved to the dry storage facility site at CY, as this move is expected to begin by the fourth quarter of 2003 and targeted completion of the facility is by the end of 2004. Approximately 20 percent of the spent fuel has been transferred to the storage facility at MY, with completion estimated during late 2003 or early 2004. Approximately 85 percent of the spent fuel at Yankee Rowe has been moved to the storage site, with completion estimated during the second quarter of 2003.
DECOMMISSIONING
Pursuant to the Purchase and Sale Agreement with FPL for the sale of Seabrook, upon the closing of the sale on November 1, 2002, NAEC and CL&P were obligated to deliver to FPL decommissioning funds in the amount of $66.1 million. In addition, a "top off" payment of $36.8 million was made. Upon the closing, FPL assumed full responsibility for decommissioning NU's former interests in Seabrook, and NU shareholders, the NU system companies and their ratepayers have no further obligation related to decommissioning.
CYAPC and MYAPC are currently collecting revenues for the decommissioning of the related sites through their power purchasers. YAEC ceased decommissioning collections in June 2000. The table below sets forth the NU system companies' estimated share of remaining decommissioning costs of the Yankee Companies' units as of December 31, 2002. The estimates are based on the latest decommissioning cost estimates. For information on the equity ownership of the NU system companies in each of the Yankee Companies' units, see "Electric Operations-Nuclear Generation-General."
CL&P PSNH WMECO NU System (Millions)
CY* $126.4 $18.3 $34.8 $179.5 MY* $ 53.0 $22.1 $13.3 $ 88.4 Rowe* $ 55.1 $15.7 $15.7 $ 86.5 ------ ----- ----- ------ Total $234.5 $56.1 $63.8 $354.4 ====== ===== ===== ======
* The costs shown include the expected future revenue requirements associated with the funding of decommissioning, recovery of remaining assets and other closure costs associated with the early retirement of Yankee Rowe, CY and MY as of December 31, 2002, which have been recorded as an obligation on the books of the NU system companies.
As of December 31, 2002, the Yankee Companies' share of the external decommissioning trust fund balances (at market), reflecting the contribution share provided by the NU system companies, is as follows:
CL&P PSNH WMECO NU System (Millions)
CY $ 79.1 $11.4 $21.8 $112.3 Rowe 17.7 5.1 5.1 27.9 MY 13.1 5.4 3.3 21.8 ------ ----- ----- ------ Total $109.9 $21.9 $30.2 $162.0 ====== ===== ===== ======
As part of an ongoing review process, management of CYAPC, YAEC and MYAPC prepared preliminary revised estimates of the cost of the nuclear units owned by those companies. The estimated costs of decommissioning CY, Yankee Rowe and MY have increased by approximately $150 million, $190 million and $40 million, respectively, over prior estimates and are subject to FERC approval prior to recovery in rates by the Yankee Companies. Such prior estimated costs were included in the Yankee Companies' rates which have been approved by the FERC. The new cost estimates will be revised from time to time based on information available to the Yankee Companies regarding future costs and are attributable mainly to increases in the projected costs of spent fuel storage, security and liability and property insurance. The respective shares of the increased costs would be approximately as follows: CL&P: $103 million; PSNH: $23 million; and WMECO: $29 million.
CYAPC is required to file with FERC no later than mid-2004 for increased costs associated with the decommissioning of CYAPC. YAEC is expected to file with FERC in the spring of 2003 to renew decommissioning collections from its sponsor companies. The anticipated decommissioning collection levels, pending FERC approval, are assumed to begin in June 2003. The delay in YAEC's fuel transfer activities is expected to extend the completion of decommissioning activities to 2005. It is also anticipated that MYAPC will file with FERC no later than November 1, 2003 for new rates to be effective January 1, 2004. In the case of each of CYAPC, YAEC and MYAPC, the precise annual collection amounts and duration will be determined as part of the FERC approval process.
In January 2001, NNECO filed a written notification with the NRC reporting that during a reconciliation and verification of Millstone spent nuclear fuel records, personnel concluded that the location of two full-length irradiated fuel pins could not be determined and were not properly tracked in the records. NNECO reported that the two fuel rods are from the same fuel assembly, which was disassembled in 1972 for inspection, and were displaced from the fuel assembly in 1974. NNECO further reported that records indicate that in 1979 and 1980 the displaced rods were physically verified to be stored in a canister in the Millstone 1 spent fuel pool, and that the rods and canister are no longer in the spent fuel pool location documented in 1979 and 1980. NNECO's report indicated that records retrieved to date do not document the relocation or disposition of the two fuel rods.
On October 5, 2001, NU issued a report, following an extensive search, concerning two missing fuel pins at the retired Millstone 1 nuclear unit which was subsequently sold to DNCI. As of December 31, 2002, costs related to this search totaled $9.1 million. The report concluded that the pins are currently located in one of four facilities licensed to store low or high-level nuclear waste and that they are not a threat to public health and safety. A follow-up inspection by the NRC concluded that NU's investigation was thorough and complete and its conclusions were reasonable and supportable. These events have, however, resulted in the issuance of an NRC notice of violation and the imposition of a $288,000 civil penalty. The NRC is expected to conclude its review of this matter in 2003.
OTHER REGULATORY AND ENVIRONMENTAL MATTERS
ENVIRONMENTAL REGULATION
GENERAL
The NU system and its subsidiaries are subject to federal, state and local regulations with respect to water quality, air quality, toxic substances, hazardous waste and other environmental matters. Additionally, the NU system's major generation and transmission facilities may not be constructed or significantly modified without a review by the applicable state agency of the environmental impact of the proposed construction or modification. Compliance with increasingly more stringent environmental laws and regulations, particularly air and water pollution control requirements, may limit operations or require substantial investments in new equipment at existing facilities.
SURFACE WATER QUALITY REQUIREMENTS
The federal Clean Water Act requires every "point source" discharger of pollutants into navigable waters to obtain a National Pollutant Discharge Elimination System (NPDES) permit from the United States Environmental Protection Agency (EPA) or state environmental agency specifying the allowable quantity and characteristics of its effluent. NU system facilities are in the process of obtaining or renewing all required NPDES permits in effect. Compliance with NPDES and state water discharge permits has necessitated substantial expenditures, which are difficult to estimate, and may require further expenditures because of additional requirements that could be imposed in the future. For information regarding civil lawsuits related to alleged violations of certain facilities' NPDES permits, see Item 3, "Legal Proceedings."
The Federal Oil Pollution Act of 1990 (OPA 90) sets out the requirements for facility response plans and periodic inspections of spill response equipment at facilities that can cause substantial harm to the environment by discharging oil or hazardous substances into the navigable waters of the United States and onto adjoining shorelines. The NU system companies are currently in compliance with the requirements of OPA 90. 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 NU system owns facilities and through which the NU 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 NU system currently carries general liability insurance in the total amount of $160 million annual coverage, which includes liability coverage for oil spills.
AIR QUALITY REQUIREMENTS
The Clean Air Act Amendments of 1990 (CAAA), as well as state laws in Connecticut, Massachusetts and New Hampshire, impose stringent requirements on emissions of sulfur dioxide (SO2) and nitrogen oxide (NOX) for the purpose of controlling acid rain and ground level ozone. In addition, the CAAA address the control of toxic air pollutants. Installation of continuous emissions monitors and expanded permitting provisions also are included. Compliance with CAAA requirements has cumulatively cost the NU system approximately $72 million as of December 31, 2002: $11 million for CL&P, $55 million for PSNH, $1 million for WMECO, and $5 million for HWP. In addition, PSNH expects to spend approximately $3 million a year for SO2 allowances and approximately $3 million for annual operational costs for NOX controls.
Massachusetts and New Hampshire are both imposing significant emission reduction requirements on power plants, in addition to the Federal requirements. The cost for Mt. Tom Station to meet current Massachusetts emission limits is estimated to be approximately $7 million. Additional costs for compliance with expected mercury limits are unknown at this time. In New Hampshire, the emissions reduction Clear Air Bill was signed into law in May 2002. This law addresses emissions reductions of four pollutants. Oxides of nitrogen, sulfur dioxide and carbon dioxide have their emission caps established for current compliance beginning in 2007. The mercury emission cap is expected to be set prior to July 1, 2005. Estimates for compliance (excluding mercury control) are between $4 and $5 million dollars and will be better known after the mercury reduction requirement is established.
HAZARDOUS MATERIALS REGULATIONS
As many other industrial companies have done in the past, the NU system companies disposed of residues from operations by depositing or burying such materials on-site or disposing of them at off-site landfills or facilities. Typical materials disposed of include coal gasification waste, fuel oils, ash, gasoline and other hazardous materials that might contain polychlorinated biphenyls (PCBs). It has since been determined that deposited or buried wastes, under certain circumstances, could cause groundwater contamination or create other environmental risks. The NU system has recorded a liability for what it believes is, based upon currently available information, its estimated environmental remediation costs for waste disposal sites for which the NU system companies expect to bear legal liability, and continues to evaluate the environmental impact of its former disposal practices. Under federal and state law, government agencies and private parties can attempt to impose liability on NU system companies for such past disposal. At December 31, 2002, the liability recorded by the NU system for its estimated environmental remediation costs for known sites needing remediation, including those sites described below, exclusive of recoveries from insurance or from third parties, was approximately $42 million, representing 48 sites. This total includes liabilities recorded by Yankee Gas of $19.5 million. All cost estimates were made in accordance with generally accepted accounting principles where remediation costs are probable and reasonably estimable. These costs could be significantly higher if alternative remedies become necessary. These liabilities break down as follows:
1. Under the federal Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended, commonly known as Superfund, EPA has the authority to clean up or order the clean up of hazardous waste sites and to impose the clean up 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. The NU system currently is involved in five Superfund sites: one in Connecticut, one in New Jersey, two in New Hampshire and one in Kentucky, which could have a material impact on the NU system. The NU system has committed in the aggregate approximately $750,000 to its share of the clean up of these sites. For further information on litigation relating to the Connecticut site, see Item 3, "Legal Proceedings."
2. The greatest liabilities currently relate to former manufactured gas plant (MGP) facilities which represent the largest share of future clean up costs. These facilities were owned and operated by predecessor companies to the NU system from the mid-1800's to mid-1900. Byproducts from the manufacture of gas using coal resulted in fuel oils, hydrocarbons, coal tar, metals and other waste products that may pose risks to human health and the environment. The NU system currently has partial or full ownership responsibilities at 29 former MGP sites. Of the total NU system liabilities, $38.5 million has been established to address future remediation costs at MGP sites.
3. Other sites undergoing comprehensive investigations or remedial actions under state programs located in Connecticut, Massachusetts, New Hampshire or New Jersey include two former fuel oil releases, two landfills, two asbestos hazard abatement projects and nine miscellaneous projects. To date, approximately $2.75 million has been established to address future remediation costs at these sites.
In the past, the NU system has received other claims from government agencies and third parties for the cost of remediating sites not currently owned by the NU system but affected by past NU system disposal activities and may receive more such claims in the future. The NU 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.
ELECTRIC AND MAGNETIC FIELDS
Published reports have discussed the possibility of adverse health effects from electric and magnetic fields (EMF) associated with electric transmission and distribution facilities and appliances and wiring in buildings and homes. Most researchers, as well as numerous scientific review panels considering all significant EMF epidemiological and laboratory studies to date, agree that current information remains inconclusive, inconsistent and insufficient for characterizing EMF as a health risk.
Based on this information, management does not believe that a causal relationship between EMF exposure and adverse health effects has been established or that significant capital expenditures are appropriate to minimize unsubstantiated risks. The NU system companies have closely monitored research and government policy developments for many years and will continue to do so.
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. To date, no courts have concluded that individuals have been harmed by EMF from electric utility facilities, but if utilities were to be found liable for damages, the potential monetary exposure for all utilities, including the NU 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.
FERC HYDROELECTRIC PROJECT LICENSING
New Federal Power Act licenses may be issued for hydroelectric projects for terms of 30 to 50 years as determined by the FERC. Upon the expiration of an existing license, (i) the FERC may issue a new license to the existing licensee, or (ii) the United States may take over the project or the FERC may issue a new license to a new licensee, upon payment to the existing licensee of the lesser of the fair value or the net investment in the project, plus severance damages, less certain amounts earned by the licensee in excess of a reasonable rate of return.
The NU system companies currently hold FERC licenses for 11 hydroelectric projects totaling 16 plants. In addition, the NU system companies own and operate five unlicensed hydroelectric projects that are currently deemed non- jurisdictional by FERC. These licensed and unlicensed hydroelectric projects are located in Connecticut, Massachusetts and New Hampshire and aggregate approximately 1,367 MW of capacity. CL&P's and WMECO's five licensed projects and four unlicensed projects with approximately 1,302 MW of capacity were transferred to NGC in March 2000. As part of the Restructuring Settlement, PSNH has proposed to auction its seven hydroelectric projects (totaling nine plants) with approximately 65 MW of capacity upon approval of the agreement. Subsequently, the New Hampshire legislature deferred the sale of any PSNH fossil or hydroelectric facilities until at least February 2004.
NGC's FERC licenses for operation of the Falls Village and Housatonic hydroelectric projects expired in August 2001. Annual operating licenses allow NGC to continue plant operations until new licenses are granted. NGC filed an application for a new license which proposed to combine both projects under one license, in August 1999. The Connecticut Department of Environmental Protection (CDEP) has issued its Section 401 water quality certification for the combined Housatonic River Project. A draft environmental impact statement for the relicensing is anticipated in April 2003 and a final environmental impact statement is expected in October 2003. A new license for the Housatonic Project is likely to be issued in 2005. At this time, it is impossible to determine the terms and conditions of any new license, or to predict the effect of any terms and conditions on project economics.
PSNH's FERC license for the Merrimack River Hydroelectric Project that consists of the Amoskeag, Hooksett and Garvins Falls hydroelectric generating stations expires on December 31, 2005. In December 2000, PSNH filed a notice of intent with the FERC stating its plan to file an application for a new license by December 31, 2003. PSNH has begun formal consultations with federal and state resource agencies, as well as non-governmental organizations and the public. PSNH plans to file its final license application with the FERC no later than December 31, 2003. The FERC's review of license applications normally takes several years. If a new license is not issued by the expiration of the current license (December 31, 2005), it is expected that FERC will issue an annual license for the project. Annual licenses are commonly issued under the same terms and conditions as the current license, but may include new conditions if such conditions are authorized by the existing license.
Licensed operating hydroelectric projects are not generally subject to decommissioning during the license term in the absence of a specific license provision which expressly permits the FERC to order decommissioning during the license term. However, the FERC has taken the position that under appropriate circumstances it may order decommissioning of hydroelectric projects at relicensing or may require the establishment of decommissioning trust funds as a condition of relicensing. The FERC may also require project decommissioning during a license term if a hydroelectric project is abandoned, the project license is surrendered or the license is revoked.
At this time, it appears unlikely that the FERC will order decommissioning of NGC or PSNH hydroelectric projects at relicensing or that the projects will be abandoned, surrendered or the project licenses revoked. However, it is impossible to predict the outcome of FERC relicensing proceedings with certainty, or to determine the impact of future regulatory actions on project economics. Until such time as a project is ordered to be decommissioned and the terms and conditions of a decommissioning order are known, it is not possible to accurately estimate or predict the cost of project decommissioning.
EMPLOYEES
As of December 31, 2002, the NU system companies had 6,561 employees on their payrolls, excluding temporary employees, of which 2,098 were employed by CL&P, 1,252 by PSNH, 398 by WMECO, 494 by Yankee Gas, 311 by NGS, 1,426 by NUSCO, 141 by Select, 89 by SESI and 352 by SECI. NU, NGC, NAEC, Mode 1, NUEI and Select Energy Portland Pipeline, Inc. have no employees.
In response to the reduced demand for certain services and the increasingly competitive nature of their business environments, NGS and SESI eliminated some of their service lines and reduced their workforce in other parts of their businesses. As a result, during the second quarter of 2002, SESI reduced its workforce by seven employees, during the third quarter of 2002, NGS reduced its workforce by 27 employees and during the fourth quarter of 2002, Select Energy reduced its workforce by seven employees, at a total cost of approximately $1.2 million.
On September 4, 2002, NU announced a reorganization of its administrative and support-related functions to reflect the divestiture of most of its generating facilities. On September 26, 2002, 142 full time equivalent employees of NUSCO and PSNH were involuntarily terminated. Severance and other costs related to the terminations were approximately $4.8 million.
In November 2001, CL&P announced a reorganization to reflect the separation of regulated from competitive services and to refocus the organization on distribution responsibilities. The reorganization began with the selection of new officers in December 2001, with further selection processes at subsequent management levels during the first quarter of 2002. The majority of the costs associated with the reorganization is attributable to restructuring in Connecticut and is not expected to impact earnings. In connection with this process, 60 managerial and other employees of CL&P participated in a voluntary reduction program in 2002, the costs of which were approximately $8.1 million.
Approximately 2,329 employees of CL&P, PSNH, WMECO, HWP, NUSCO and Yankee Gas are covered by 16 union agreements, three of which were in negotiation as of the end of January 2003, and the remainder of which will expire between September 1, 2004 and May 31, 2006.
ITEM 2.
ITEM 2. PROPERTIES
The physical properties of the NU system are owned or leased by subsidiaries of NU. CL&P's 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 leased space in an office building under a 30- year lease which expired in March of 2002. In March of 2002, PSNH moved its headquarters to a refurbished former PSNH generating station site. A major portion of WMECO's properties are owned in fee. In 2002, NAEC sold its 35.98 percent interest in Seabrook. In addition, CL&P, PSNH and WMECO lease certain data processing equipment, vehicles, and office space. Also CL&P and WMECO lease certain substation equipment. With few exceptions, the NU system companies' lines are located on or under streets or highways, or on properties either owned or leased, or in which they have appropriate rights, easements, licenses or permits from the owners or the appropriate governmental authorities.
Yankee Gas' property consists primarily of its gas distribution facilities including distribution lines (mains and services), meter, valves, pressure regulators and flow controllers. Yankee Gas owns various propane facilities with a combined storage capacity equivalent to approximately 245,000 Mcf. Yankee Gas also owns service buildings in Meriden, Waterbury, Norwalk, and Danielson, Connecticut. Yankee Gas rents buildings in Ansonia, Danbury and Waterford, Connecticut, and leases a service building in East Windsor, Connecticut, from an affiliate, NorConn. Yankee Gas' customer information center is located in Wethersfield, Connecticut and its corporate headquarters are located in Berlin, Connecticut.
CL&P, PSNH, NGC and Yankee Gas' properties are subject to the lien of each company's respective first mortgage indentures. In addition, CL&P's interest in transmission assets is subject to a second mortgage lien for the benefit of the PCRBs. Various properties are also subject to minor encumbrances which do not substantially impair the usefulness of the properties to the owning company.
The NU system companies' properties are well maintained and are in good operating condition.
TRANSMISSION AND DISTRIBUTION SYSTEM
At December 31, 2002, the NU system companies owned 105 transmission and 351 distribution substations that had an aggregate transformer capacity of 17,221,990 kilovoltamperes (kVa) and 9,077,962 kVa, respectively; 3,075 circuit miles of overhead transmission lines ranging from 69 kilovolt (kV) to 345 kV, and 196 cable miles of underground transmission lines ranging from 69 kV to 138 kV; 33,334 pole miles of overhead and 2,331 conduit bank miles of underground distribution lines; and 433,588 line transformers in service with an aggregate capacity of 18,990,000 kVa.
ELECTRIC GENERATING PLANTS
As of December 31, 2002, the electric generating plants of the NU system companies and the NU system companies' entitlement in the generating plant of VYNPC were as follows (See "Item 1. Business - Nuclear Generation" for information on ownership and operating results for the year):
Claimed Year Capability* Owner Name of Plant (Location) Type Installed (kilowatts) ----- ------------------------ ---- --------- -----------
PSNH Total - Fossil-Steam Plants (6 units) 1952-74 986,805 Total - Hydro-Conventional (20 units) 1917-83 67,690 Total - Internal Combustion (5 units) 1968-70 102,792 --------- Total PSNH Generating Plant (31 units) 1,157,287 =========
HWP Total - Fossil-Steam Plants (1 unit) 1960 147,000 =========
NGC Total - Hydro-Conventional (36 units) 1903-55 157,930 Total - Hydro-Pumped (7 units) 1928-73 1,109,000 Storage Total - Internal Combustion (1 unit) 1969 20,800 ---------
Total NGC Generating Plant (44 units) 1,287,730 =========
NU System Total - Fossil-Steam Plants (7 units) 1952-74 1,133,805 Total - Hydro-Conventional (56 units) 1903-83 225,620 Total - Hydro-Pumped (7 units) 1928-73 1,109,000 Storage Total - Internal Combustion (6 units) 1968-70 123,592 ---------
Total NU System Generating Plant (76 units) 2,592,017 =========
*Claimed capability represents winter ratings as of December 31, 2002.
FRANCHISES
CL&P. Subject to the power of alteration, amendment or repeal by the General Assembly of Connecticut and subject to certain approvals, permits and consents of public authority and others prescribed by statute, CL&P has, subject to certain exceptions not deemed material, valid franchises free from burdensome restrictions to provide electric transmission and distribution services in the respective areas in which it is now supplying such service.
In addition to the right to provide electric transmission and distribution services as set forth above, the franchises of CL&P include, among others, limited rights and powers, as set forth in Title 16 of the Connecticut General Statutes and the special acts of the General Assembly constituting its charter, to manufacture, generate, purchase and sell electricity at retail, including to provide standard offer, backup, and default service, to sell electricity at wholesale to other utility companies and municipalities and to erect and maintain certain facilities on public highways and grounds, all subject to such consents and approvals of public authority and others as may be required by law. The franchises of CL&P include the power of eminent domain.
PSNH. The NHPUC, pursuant to statutory requirement, has issued orders granting PSNH exclusive franchises free from burdensome restrictions to distribute electricity in the respective areas in which it is now supplying such service.
In addition to the right to distribute electricity as set forth above, the franchises of PSNH include, among others, rights and powers to manufacture, generate, purchase, and transmit electricity, to sell electricity at wholesale to other utility companies and municipalities and to erect and maintain certain facilities on certain public highways and grounds, all subject to such consents and approvals of public authority and others as may be required by law. The franchises of PSNH include the power of eminent domain.
NNECO. Subject to the power of alteration, amendment or repeal by the General Assembly of Connecticut and subject to certain approvals, permits and consents of public authority and others prescribed by statute, NNECO has a valid franchise free from burdensome restrictions to sell electricity to utility companies doing an electric business in Connecticut and other states.
In addition to the right to sell electricity as set forth above, the franchise of NNECO includes, among others, rights and powers to manufacture, generate and transmit electricity, and to erect and maintain facilities on certain public highways and grounds, all subject to such consents and approvals of public authority and others as may be required by law. With the sale of the Millstone in 2001, NNECO is inactive except for minor transactions associated with post-sale matters.
WMECO. WMECO is authorized by its charter to conduct its electric business in the territories served by it, and has locations in the public highways for transmission and distribution lines. Such locations are granted pursuant to the laws of Massachusetts by the Department of Public Works of Massachusetts or local municipal authorities and are of unlimited duration, but the rights thereby granted are not vested. Such locations are for specific lines only, and, for extensions of lines in public highways, further similar locations must be obtained from the Department of Public Works of Massachusetts or the local municipal authorities. In addition, WMECO has been granted easements for its lines in the Massachusetts Turnpike by the Massachusetts Turnpike Authority.
Pursuant to the Massachusetts restructuring legislation, the DTE is required to define service territories for each distribution company, including WMECO, based on the service territories actually served on July 1, 1997, and following municipal boundaries to the extent possible. The DTE has not yet defined service territories. After these service territories are established by the DTE, until they are terminated by effect of law or otherwise, the distribution company shall have the exclusive obligation to provide distribution service to all retail customers within its service territory, and no other person shall provide distribution service within such service territory without the written consent of such distribution company.
HWP and Holyoke Power and Electric Company (HP&E). HWP, and its wholly owned subsidiary HP&E, are authorized by their charters to conduct their businesses in the territories served by them. HWP's electric business is subject to the restriction that sales be made by written contract in amounts of not less than 100 horsepower to purchasers who use the electricity in their own business in the counties of Hampden or Hampshire, Massachusetts and cities and towns in these counties, and customers who occupy property in which HWP has a financial interest, by ownership or purchase money mortgage. The two companies have locations in the public highways for their transmission and distribution lines. Such locations are granted pursuant to the laws of Massachusetts by the Department of Public Works of Massachusetts or local municipal authorities and are of unlimited duration, but the rights thereby granted are not vested. Such locations are for specific lines only and, for extensions of lines in public highways, further similar locations must be obtained from the Department of Public Works of Massachusetts or the local municipal authorities. HP&E has no retail service territory area and sells electric power exclusively at wholesale. In connection with the sale of certain of HWP's and HP&E's assets to the city of Holyoke Gas and Electric Department (HG&E) effective December 2001, HWP agreed to cause the charters of HWP and HP&E to be amended to eliminate their rights to distribute electricity at retail in Holyoke and surrounding towns unless other sellers can legally compete with HG&E, and not to exercise such rights prior to such amendment.
NGC. NGC is an exempt wholesale generator and, as it currently operates its business, is not regulated by the DPUC or the DTE. FERC's authorization for exempt wholesale generators such as NGC (EWG) to sell wholesale electric power at market-based rates typically contains an exemption from much of the traditional public utility company rate regulation. As an EWG, NGC is a "public utility" subject to the Federal Power Act. The market-based rate authorization that NGC has received from FERC exempts NGC from some, but not all, of Federal Power Act regulations, including traditional cost-based rate regulation. However, NGC is required to file summary information concerning its power transactions on a quarterly basis with FERC.
Yankee Gas. Yankee Gas and its predecessors in interest hold valid franchises to sell gas in the areas in which Yankee Gas supplies gas service. Generally, Yankee Gas holds franchises to serve customers throughout Connecticut, so long as the area is not served by another gas utility. Such franchises are perpetual but remain subject to the power of alteration, amendment or repeal by the General Assembly of the State of Connecticut, the power of revocation by the DPUC and certain approvals, permits and consents of public authorities and others prescribed by statute. Yankee Gas' franchises include, among other rights and powers, rights and powers to manufacture, generate, purchase, transmit and distribute gas, to sell gas at wholesale to other utility companies and municipalities and to erect and maintain certain facilities on public highways and grounds, all subject to such consents and approvals of public authorities and others as may be required by law. The franchises include the power of eminent domain.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
1. Con Edison, Inc. v. NU - Merger Appeals and Related Litigation
On October 13, 1999, Consolidated Edison, Inc. (Con Edison) and NU entered into an Agreement and Plan of Merger (as amended and restated as of January 11, 2001, the Merger Agreement), providing for the acquisition of NU by Con Edison, subject to the approval of various state and federal regulatory agencies.
On March 5, 2001, Con Edison advised NU that it was unwilling to close its merger with NU on the terms set forth in the Merger Agreement. That same day, NU notified Con Edison that it would treat Con Edison's refusal to proceed with the merger as a repudiation and breach of the Merger Agreement and would file suit to obtain the benefits of the transaction for NU shareholders. On March 6, 2001, Con Edison filed suit in the United States District Court for the Southern District of New York (the District Court) seeking a declaratory judgment that it had been relieved of its obligation to proceed with the merger due to, among other things, NU's alleged breach of the Merger Agreement and the alleged occurrence of a "Material Adverse Change" with respect to NU, as that term is defined in the Merger Agreement. On March 12, 2001, NU filed suit against Con Edison in the District Court seeking to recover monetary damages arising from Con Edison's breach of the Merger Agreement including, but not limited to, the amount of the acquisition premium (estimated to be $1.2 billion) together with interest at the rate established by law (9 percent).
On May 11, 2001, in accordance with a stipulation of the parties and order of the District Court, Con Edison filed an amended complaint in which it added claims seeking damages for breach of contract, fraudulent inducement and negligent misrepresentation. Con Edison has claimed that it is entitled to recover 82 percent of the synergy savings estimated by the parties to have been achievable over ten years following consummation of the merger. Con Edison contends that these estimated synergies totaled $1.754 billion and have a present value of $707 million. NU contends that Con Edison is not entitled to any damages as a matter of law.
On June 1, 2001, NU answered Con Edison's amended complaint, denying all of its material allegations and asserting affirmative defenses, and asserted a counterclaim seeking to recover monetary damages as described above against Con Edison for breach of the Merger Agreement. NU subsequently dismissed its March 12 complaint, without prejudice, since it was duplicative of the June 1 counterclaim. On June 8, 2001, Con Edison answered NU's counterclaim, denying its material allegations and asserting affirmative defenses.
In addition, separate petitions were filed with the DPUC asking that its merger approval be rescinded or reversed. The DPUC reopened its docket approving the merger and asked parties to comment on the question of whether a date certain should be imposed for consummation of the merger and whether that date should be January 31, 2002. On January 30, 2002, the DPUC issued a decision establishing January 31, 2002 as the deadline for merger consummation.
The companies completed discovery in the litigation and submitted cross motions for summary judgment. The District Court has denied Con Edison's motion in its entirety, leaving intact NU's claim for breach of the Merger Agreement and has partially granted NU's motion for summary judgment by eliminating Con Edison's claims against NU for fraud and negligent misrepresentation. No trial date has been set. At this stage of the litigation, management can predict neither the outcome of this matter nor its ultimate effect on NU.
2. Millstone - Damage to Fish Population Lawsuits
On April 20, 2000, two fishermen, Aldred Madeira, Jr. and Timothy F. Madieros, brought a lawsuit against NNECO and NUSCO in New London Superior Court alleging two counts: common law nuisance and tortious interference with a business expectancy. DNCI has since been added as an additional defendant. The lawsuit alleges that Millstone has engaged in various actions, including entrainment of winter flounder, that have caused the two fishermen to suffer damages. The suit initially sought temporary and permanent injunctions to suspend Millstone operations during the winter flounder spawning season, conversion of Millstone to a closed-cooling system, or in the alternative, permanent shutdown, as well as compensatory and punitive damages. However, the injunctive relief claims were dismissed by the Court on March 11, 2002.
On August 23, 2001, two additional fishermen, James Engelmann and Michael Stepski, brought a lawsuit similar to the Madeira and Madieros action against NNECO, NUSCO and DNCI in Superior Court alleging two counts: common law nuisance and tortious interference with a business expectancy. Like the earlier suit, plaintiffs' injunctive relief claims have been dismissed.
On December 16, 2002, the court heard argument on defendants' motion to strike both counts of the second revised complaint. A decision is pending. On February 24, 2003, the court denied plaintiffs' motion to amend the complaint to add a claim for violation of the Connecticut Unfair Trade Purchase Act.
On April 26, 2000, another lawsuit was filed in Connecticut Superior Court against NUSCO, NNECO and the Commissioner of the CDEP challenging the validity of previously issued CDEP emergency and temporary authorizations allowing Millstone to discharge wastewater not expressly authorized by the facility's NPDES permit. The suit sought a temporary and permanent injunction against operations at Millstone 1, 2 and 3. On August 30, 2000, NNECO filed a motion to dismiss, and on October 16, 2000, NNECO's motion was granted. On November 22, 2000, the Connecticut Coalition Against Millstone (CCAM) and the Long Island Coalition Against Millstone filed an appeal with the Connecticut Appellate Court. Subsequently, on May 3, 2002, NNECO and NUSCO filed a motion to dismiss the appeal on the grounds of mootness. On June 26, 2002, this motion was granted and the appeal dismissed. On November 6, 2002, plantiffs' petition to the Connecticut Supreme Court for certification to appeal this matter further was denied. This matter is now considered closed.
3. Sale of Millstone to DNCI
On February 20, 2001, the CCAM filed in Connecticut Superior Court an appeal of the DPUC's decision approving the sale of Millstone to DNCI. CCAM alleges that the final decision violates the Connecticut general statutes on multiple grounds and requests that the decision be reversed and vacated. On March 26, 2001, CCAM's appeal was dismissed. On April 16, 2001, plaintiffs filed an appeal with the Connecticut Appellate Court. On February 21, 2002, the court dismissed CCAM's appeal.
On March 8, 2001, CCAM and other parties also filed a lawsuit in Connecticut Superior Court against the CDEP, NNECO and DNCI challenging (1) the validity of Millstone's NPDES permit (Permit) and a previously issued CDEP emergency authorization allowing Millstone to discharge wastewater not expressly authorized by the facility's Permit, and (2) CDEP's authority to transfer both Millstone's permit and emergency authorization to DNCI. On March 29, 2001, CCAM's request for a temporary restraining order enjoining CDEP from transferring both the Permit and emergency authorization to DNCI prior to a full hearing was denied. Subsequently, on July 19, 2001, the entire matter was dismissed. On September 20, 2002, the Connecticut Supreme Court assigned the matter to itself. The suit has not yet been scheduled for oral argument.
4. FERC - Installed Capability (ICAP) Deficiency Charge
In July 2001, NU filed an appeal of the FERC orders imposing a $0.17 per kilowatt-month ICAP charge rate from August 1, 2000 to April 1, 2001. In December 2001, FERC denied rehearing its order allowing the $0.17 rate during the court stay period, April through August 2001. NU appealed this decision to the First Circuit Court of Appeals (First Circuit) and on October 4, 2002, the First Circuit denied the appeal.
In its December 3, 2001 report on alternatives to the ICAP requirement, ISO-New England proposed an interim advance ICAP purchase requirement but indicated that other ICAP improvements would be implemented with SMD (scheduled for late 2002 or early 2003) and that it intended to develop a forward reserves market thereafter. The ISO's interim advance purchase requirement proposal was filed with FERC in late December 2001. Subsequently, ISO-New England published the results of its study on the cost of new peaking units in New England which suggests that the level of a cost based ICAP deficiency charge would be $6.15 rather than $4.87.
5. Retirement Plan Litigation
This matter involves four separate but related federal court lawsuits by nineteen former employees of NUSCO, WMECO and CL&P who retired between 1991 and 1994. The complaints generally allege that the Company breached its fiduciary duties to the plaintiffs by making affirmative misrepresentations that caused them to retire prematurely, since as a result of these alleged misrepresentations they came to believe incorrectly that no particular future enhancement of employee benefits was being seriously considered at the time by the Company.
The cases were tried together in a summary bench trial in the United States District Court in Hartford, Connecticut in April-May 2002; post-trial briefs have been filed and the parties are awaiting the judge's decision.
6. HP&E
In July of 1998, HP&E entered into a contract with Bridgeport Energy, LLC (Bridgeport), a subsidiary of Duke Energy, to purchase ICAP at a rate of $3.125 per kilowatt per month through April 30, 2004. This contract was subsequently assigned to Select Energy. The contract contains a clause that allowed either party to terminate the contract upon 30 days prior notice if FERC, NEPOOL or ISO-New England (1) eliminates ICAP or (2) makes material changes to ICAP that materially adversely affect the parties and such changes can't be resolved through negotiation.
When ISO-New England filed with FERC in May 2000 to eliminate the ICAP product, Select Energy sought to terminate the contract. Pending the resolution of the ICAP issues at FERC and in court, the parties entered into a series of agreements to preserve their rights to argue whether the contract should be terminated, during which time Bridgeport continued to supply, and Select Energy continued to pay for, the ICAP. In June 2001, Select Energy discontinued purchasing the ICAP from Bridgeport. In July 2001, Select Energy filed a complaint in Connecticut Superior Court, requesting the court to declare that the contract was terminated as of June 2000, asking for an order that the contract was effectively terminated in June 2000 and requesting damages for the above-market portion of its payment. Bridgeport filed a complaint in Connecticut Superior Court shortly thereafter, alleging that Select Energy is in default under the contract and owes damages from June of 2000 through the remainder of the term of the contract. A settlement in this matter was reached on November 12, 2002.
7. Wisvest-Connecticut, LLC (Wisvest) v. Select Energy
Wisvest filed suit in July 2002 against Select Energy in the Superior Court at New Britain, Connecticut. In its complaint, Wisvest alleges that Select Energy breached its Load Asset Contract for Electrical Load dated November 23, 1999 (the Agreement) by unilaterally reducing the amount of electricity it proposed to purchase from Wisvest. Wisvest alleged that the Agreement obligated Select Energy to purchase from Wisvest 11.5 percent of the CL&P Standard Offer Service Load (Load) during the term of the Agreement, but that in February 2002 it unilaterally announced that it would thereafter purchase only 9.4 percent of the CL&P Load. The complaint seeks monetary damages and a declaratory judgment declaring that Select Energy has no right to unilaterally alter its obligation to receive and purchase 11.5 percent of the CL&P Load.
Select Energy has filed an Answer to the complaint, denying any liability. It has also filed several special defenses and counterclaims. No trial date has been set.
8. NRG - Credit Rating Status
Recent changes in the credit status of NRG have impacted the contractual relationships between NRG and CL&P, Yankee Gas and Select Energy. On July 26 and 29, 2002, the three major ratings agencies lowered the ratings of NRG to below investment grade. Concurrently, the potential, but now postponed, deactivation of NRG owned generating units in the state of Connecticut further called into question NRG's financial viability and the long term availability of power to serve CL&P's standard offer customers. On September 16, 2002, NRG announced its failure to meet a September 13, 2002 deadline by which it was to post collateral in excess of $1 billion and that it had not made payments on certain debt issues dues on September 16, 2002. On November 22, 2002, an involuntary bankruptcy case was filed against NRG by seven former NRG executives. A proposed settlement between NRG and the former executives is scheduled for hearing on March 27, 2003 and objections to the dismissal of the case pursuant to the settlement must be filed on or before March 20, 2003. In addition, on February 27, 2003, lenders under a revolving credit agreement accelerated the repayment of $1 billion of NRG debt. On February 28, 2003, two NRG creditors filed to join the pending involuntary case.
Yankee Gas
On November 12, 2002, NRG affiliate Meriden Gas Turbines, LLC (MGT) filed suit against Yankee Gas in Superior Court in Meriden, Connecticut. MGT claims, among other things, that Yankee Gas breached its obligations under a transportation, construction and interconnection service agreement (MGT Agreement) entered into in December 2001 in connection with a Meriden power plant project. MGT seeks a declaratory ruling from the court that Yankee Gas was not entitled to draw down a $16 million letter of credit issued in its favor in connection with the MGT Agreement. Yankee Gas intends to defend this case vigorously and will file a response to the complaint early in 2003.
CL&P
On December 20, 2002, FERC issued an order in connection with a dispute between CL&P and NRG concerning the provision of station service to Connecticut generating plants purchased from CL&P by NRG affiliates in December 1999. CL&P filed a complaint at FERC seeking interpretation of a FERC-filed interconnection agreement in which NRG agreed to pay CL&P's applicable retail rates for station service power (if procured from CL&P) and delivery of such power (whether procured from CL&P or a third party supplier). FERC further affirmed the language in its Order 888 concerning state jurisdiction over the delivery of power to end users, even in the absence of distribution facilities, and the state's authority to impose certain charges on end users, such as those associated with stranded cost recovery. CL&P has made a demand upon NRG for payment of $13.3 million in station service charges through January 2003 and is preparing to take any steps necessary to collect the unpaid balance.
Select Energy
Select Energy, also concerned about NRG's solvency and ability to continue to meet the terms of its contracts, terminated its contractual relationships with NRG and its affiliates on August 15, 2002 as a result of NRG's failure to provide adequate financial assurances. Subsequent to this date, Select Energy calculated its damages and forwarded final payment to NRG. On November 1, 2002, Select Energy received NRG's protest to Select Energy's calculation of damages, to which Select Energy responded that its calculations were in accord with the underlying contracts.
9. Enron Power Marketing, Inc. (Enron)/Select Energy
On January 13, 2003, Select Energy received notice from the United States Bankruptcy Court of an adverse proceeding filed by Enron against Select Energy for approximately $2.5 million. In its complaint, Enron alleges that Select Energy improperly set off pre-petition debt arising from the termination of transactions entered into under a power purchase agreement between Select Energy and Enron against post-petition amounts owed for deliveries of power under transactions entered into under the same agreement. On February 19, 2003, in substitution of an answer to the complaint, Select Energy filed a motion for relief from the automatic stay and to compel arbitration, or, alternatively, to dismiss. On March 4, 2003, the Court issued an order directing mediation of all adversary proceedings involving trading agreements, including those of Select Energy, and further stayed all pending motions seeking to modify the automatic stay in order to seek arbitration. In accordance with the Court's Order, Select Energy filed a brief summary of the essential issues in its proceedings with the mediation judge and subsequently participated in the initial mediation conference on March 12, 2003.
10. Hawkins, Delafield & Wood (Hawkins) v. NU, NUSCO and CL&P
On December 12, 2002, Hawkins, a New York law firm sued by the Connecticut Resources Recovery Authority (CRRA) as a result of the Enron bankruptcy, brought an apportionment complaint against a number of former Enron officers, directors and outside accountants. In addition to the Enron defendants, Hawkins also named as defendants in its complaint NU, NUSCO and CL&P. Hawkins asserts in its complaint that in the event it is found liable to CRRA, then the apportionment defendants, including NU, NUSCO and CL&P, are responsible for some or all of the $220 million claimed as damages. The NU defendants will file their appearance in the case by January 28, 2003, and will file a response to the complaint, in the form of a pre-answer dispositive motion, on or before February 27, 2003.
The case is proceeding along three broad tracks: (a) an attempt by various defendants to persuade the Multi-District Litigation (MDL) Judicial Panel to transfer the case to the United States District Court for the Southern District of Texas; (b) an attempt to consolidate this case with a case now pending, which itself is subject to a conditional order of the MDL Panel transferring it to the Southern District of Texas; and (c) an attempt to remand this case to Connecticut's state court. No further action in this case is anticipated until the MDL Panel rules, as the United States District Court judge has stayed all proceedings pending such ruling. The NU defendants had not yet responded to the apportionment complaint at the time the proceedings were stayed.
11. Environmental Litigation
On September 25, 2002, NUSCO, among other defendants, was sued by the Joseph A. Schiavone Corporation (Schiavone) under the Comprehensive Environmental Response, Compensation and Liability Act of 1980 for the costs associated with the investigation and remediation of a commercial property owned by Schiavone in North Haven, Connecticut. Schiavone alleges that from 1968 through 1978, NUSCO sold transformers containing PCBs to a company named H. Kasden & Sons, a co-defendant, which owned the property before Schiavone and operated a scrap yard at the site. The property is currently involved in an EPA and CDEP monitored investigation and remediation of PCB contamination and related costs are estimated at approximately $4 million.
NUSCO has answered the complaint denying the material allegations. Discovery will commence in January. After a status conference held on February 13, 2003, a United States Magistrate entered a case management plan and ordered the parties to report back by March 13, 2003 regarding settlement potential.
12. Other Legal Proceedings
The following sections of Item 1, "Business" discuss additional legal proceedings: See "Rates and Electric Industry Restructuring" for information about various state restructuring proceedings and civil lawsuits related thereto and the implementation of SMD; "Regulated Electric Operations" and "Regulated Gas Operations" for information about proceedings relating to power, transmission and pricing issues; "Regulated Electric Operations - Nuclear Generation" for information related to nuclear plant performance, nuclear fuel enrichment pricing, high-level and low-level radioactive waste disposal, decommissioning matters, and NRC regulation; "Other Regulatory and Environmental Matters" for information about proceedings involving surface water and air quality, toxic substances and hazardous waste, EMF, licensing of hydroelectric projects, and other matters.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No event that would be described in response to this item occurred with respect to NU, PSNH or WMECO.
CL&P. In a written Consent in Lieu of a Special Meeting of Stockholders of CL&P (Company) (Consent) dated October 25, 2002, the stockholders voted to sell the Company's ownership interest in the Seabrook Nuclear Power Station (Seabrook) pursuant to that Purchase and Sale Agreement dated April 13, 2002 (Agreement) by and among the Company, certain other owners of Seabrook, North Atlantic Energy Service Corporation, and the buyer, FPL Energy Seabrook, LLC (Buyer), in consideration of the total purchase price of $836,610,000, subject to adjustment as provided in the Agreement. The vote authorizing the sale was 6,035,205 shares in favor, representing 100 percent of the issued and outstanding shares of common stock of CL&P.
PART II
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANTS' COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
NU. The common shares of NU are listed on the New York Stock Exchange. The ticker symbol is "NU," although it is frequently presented as "Noeast Util" and/or "NE Util" in various financial publications. The high and low closing sales prices for the past two years, by quarters, are shown below.
Year Quarter High Low ---- ------- ---- ---
2002 First $19.87 $17.61 Second 20.57 18.05 Third 18.45 13.84 Fourth 16.97 13.20
2001 First $23.56 $16.80 Second 20.75 17.35 Third 20.79 18.30 Fourth 19.25 16.95
As of January 31, 2003, there were 65,176 common shareholders of record of NU. As of the same date, there were a total of 131,161,040 common shares issued, including 3,755,714 unallocated Employee Stock Ownership Plan (ESOP) shares held in the ESOP trust.
On January 13, 2003, the NU Board of Trustees approved the payment of a 13.75 cent per share dividend, payable on March 31, 2003, to shareholders of record as of March 1, 2003.
On January 8, 2002, the NU Board of Trustees approved the payment of a 12.5 cent per share dividend, payable on March 29, 2002, to shareholders of record as of March 1, 2002.
On April 19, 2002, the NU Board of Trustees approved the payment of a 12.5 cent per share dividend, payable on June 28, 2002, to shareholders of record as of June 1, 2002.
On May 14, 2002, the NU Board of Trustees approved the payment of a 13.75 cent per share dividend, payable on September 30, 2002, to shareholders of record as of September 1, 2002.
On October 8, 2002, the NU Board of Trustees approved the payment of a 13.75 cent per share dividend, payable on December 31, 2002, to shareholders of record as of December 1, 2002.
On January 9, 2001, the NU Board of Trustees approved the payment of a 10 cent per share dividend, payable on March 31, 2001, to shareholders of record as of March 1, 2001.
On April 9, 2001, the NU Board of Trustees approved the payment of a 10 cent per share dividend, payable on June 29, 2001, to shareholders of record as of June 1, 2001.
On June 28, 2001, the NU Board of Trustees approved the payment of a 12.5 cent per share dividend, payable on September 28, 2001, to shareholders of record as of September 1, 2001.
On October 9, 2001, the NU Board of Trustees approved the payment of a 12.5 cent per share dividend, payable on December 31, 2001, to shareholders of record as of December 1, 2001.
Information with respect to dividend restrictions for NU and its subsidiaries is contained in Item 1. Business under the caption "Financing Program - Financing Limitations" and in Note (a) to the "Consolidated Statements of Shareholders' Equity" on page 37 of NU's 2002 Annual Report to Shareholders, which information is incorporated herein by reference.
CL&P, PSNH and WMECO. There is no established public trading market for the common stock of CL&P, PSNH and WMECO. The common stock of CL&P, PSNH and WMECO is held solely by NU.
During 2002 and 2001, CL&P approved and paid approximately $60.1 million of common stock dividends to NU.
During 2002 and 2001, PSNH approved and paid approximately $45 million and $27 million of common stock dividends, respectively, to NU.
During 2002 and 2001, WMECO approved and paid approximately $16 million and $22 million of common stock dividends, respectively, to NU.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
NU. Reference is made to information under the heading "Selected Consolidated Financial Data" contained on page 63 of NU's 2002 Annual Report to Shareholders, which information is incorporated herein by reference.
CL&P. Reference is made to information under the heading "Selected Consolidated Financial Data" contained on page 25 of CL&P's 2002 Annual Report, which information is incorporated herein by reference.
PSNH. Reference is made to information under the heading "Selected Consolidated Financial Data" contained on page 24 of PSNH's 2002 Annual Report, which information is incorporated herein by reference.
WMECO. Reference is made to information under the heading "Selected Consolidated Financial Data" contained on page 22 of WMECO's 2002 Annual Report, which information is incorporated herein by reference.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS;
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
NU. Reference is made to information under the heading "Management's Discussion and Analysis and Results of Operations" and Note 3, "Derivative Instruments, Market Risk and Risk Management," contained on pages 15 through 31 and pages 47 through 49, respectively, of NU's 2002 Annual Report to Shareholders, which information is incorporated herein by reference.
CL&P. Reference is made to information under the heading "Management's Discussion and Analysis of Financial Condition and Results of Operations" contained on pages 1 through 8 of CL&P's 2002 Annual Report, which information is incorporated herein by reference.
PSNH. Reference is made to information under the heading "Management's Discussion and Analysis of Financial Condition and Results of Operations" contained on pages 1 through 7 of PSNH's 2002 Annual Report, which information is incorporated herein by reference.
WMECO. Reference is made to information under the heading "Management's Discussion and Analysis of Financial Condition and Results of Operations" contained on pages 1 through 6 of WMECO's 2002 Annual Report, which information is incorporated herein by reference.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
NU. Reference is made to information under the headings "Company Report," "Independent Auditor's Report," "Report of Independent Public Accountants," "Consolidated Balance Sheets," "Consolidated Statements of Income," "Consolidated Statements of Comprehensive Income," "Consolidated Statements of Shareholders' Equity," "Consolidated Statements of Cash Flows," "Consolidated Statements of Capitalization," "Consolidated Statements of Income Taxes," "Notes to Consolidated Financial Statements," and "Consolidated Statements of Quarterly Financial Data" contained on pages 32 through 62 of NU's 2002 Annual Report to Shareholders, which information is incorporated herein by reference.
CL&P. Reference is made to information under the headings "Independent Auditor's Report," "Report of Independent Public Accountants," "Consolidated Balance Sheets," "Consolidated Statements of Income," "Consolidated Statements of Comprehensive Income," "Consolidated Statements of Common Stockholder's Equity," "Consolidated Statements of Cash Flows," "Notes to Consolidated Financial Statements," and "Consolidated Quarterly Financial Data" contained on pages 9 through 25 of CL&P's 2002 Annual Report, which information is incorporated herein by reference.
PSNH. Reference is made to information under the headings "Independent Auditor's Report," "Report of Independent Public Accountants," "Consolidated Balance Sheets," "Consolidated Statements of Income," "Consolidated Statements of Comprehensive Income," "Consolidated Statements of Common Stockholder's Equity," "Consolidated Statements of Cash Flows," "Notes to Consolidated Financial Statements," and "Consolidated Quarterly Financial Data" contained on pages 8 through 24 of PSNH's 2002 Annual Report, which information is incorporated herein by reference.
WMECO. Reference is made to information under the headings "Independent Auditor's Report," "Report of Independent Public Accountants," "Consolidated Balance Sheets," "Consolidated Statements of Income," "Consolidated Statements of Comprehensive Income," "Consolidated Statements of Common Stockholder's Equity," "Consolidated Statements of Cash Flows," "Notes to Consolidated Financial Statements," and "Consolidated Quarterly Financial Data" contained on pages 7 through 22 of WMECO's 2002 Annual Report, which information is incorporated herein by reference.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
No unreported event that would be described in response to this item has occurred with respect to NU, CL&P, PSNH or WMECO.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS
NU.
In addition to the information provided below concerning the executive officers of NU, incorporated herein by reference is the information contained in the sections "Proxy Statement", "Election of Trustees", "Board Committees and Responsibilities", and "Section 16(a) Beneficial Ownership Reporting Compliance", of the definitive proxy statement for solicitation of proxies by NU's Board of Trustees, dated March 27, 2003, which will be filed with the Commission pursuant to Rule 14a-6 under the Securities Exchange Act of 1934.
Positions Name Held - ------------------------ ---------
Gregory B. Butler (*) VP, SEC, GC John H. Forsgren (*) EVP, CFO, VC, T Cheryl W. Grise (*) P Bruce D. Kenyon (*)(**) P Michael G. Morris (*) CHB, P, CEO, T Charles W. Shivery (*) P
CL&P.
Positions Name Held - ------------------------ ---------
David H. Boguslawski VP, D Gregory B. Butler (*) OTH John H. Forsgren (*) OTH Cheryl W. Grise (*) CEO, D Michael G. Morris (*) OTH Leon J. Olivier (*) P, COO, D
PSNH.
Positions Name Held - ------------------------ ---------
David H. Boguslawski VP, D Gregory B. Butler (*) OTH John C. Collins (***) D John H. Forsgren (*) OTH, D Cheryl W. Grise (*) CEO, D Gerald Letendre (***) D Gary A. Long (*) P, COO, D Michael G. Morris (*) CH, D Jane E. Newman (***) D
WMECO.
Positions Name Held - ------------------------ ---------
David H. Boguslawski VP, D Gregory B. Butler (*) OTH James E. Byrne (***) D John H. Forsgren (*) OTH, D Cheryl W. Grise (*) CEO, D Kerry J. Kuhlman (*) P, COO, D Paul J. McDonald (***) D Michael G. Morris (*) CH, D Melinda M. Phelps (***) D
* Executive Officer ** Retired as of the close of business on December 31, 2002. *** Resigned as of the close of business on December 31, 2002.
Key: CEO - Chief Executive Officer OTH - Executive Officer of CFO - Chief Financial Officer Registrant because of policy- CH - Chairman making function for NU system CHB - Chairman of the Board P - President COO - Chief Operating Officer SEC - Secretary D - Director SVP - Senior Vice President EVP - Executive Vice President T - Trustee GC - General Counsel VP - Vice President VC - Vice Chairman
Name Age Business Experience During Past 5 Years - ----------------------- --- ---------------------------------------
David H. Boguslawski 48 Vice President - Transmission Business of CL&P, PSNH and WMECO since May 1, 2001 and a Director of CL&P, PSNH and WMECO since June 30, 1999; previously Vice President - Energy Delivery of CL&P, PSNH and WMECO from September 1996 to May 2001.
Gregory B. Butler 45 Vice President, Secretary and General Counsel of NU since May 1, 2001 and a Director of Northeast Utilities Foundation, Inc. since December 1, 2002; previously Vice President- Governmental Affairs of NUSCO from January 1997 to May 2001; Vice President of Federal Affairs at New England Electric System from January 1995 to December 1996; and senior counsel for Niagara Mohawk Power Corporation from December 1992 to January 1995.
James E. Byrne 48 Partner, Finneran, Byrne & Dreshsler, L.L.P., since 1982. Director of WMECO from September 1999 through December 2002.
John C. Collins (1) 57 Chief Executive Officer, Dartmouth- Hitchcock Clinic, Dartmouth-Hitchcock Medical Center since 1977. Director of PSNH from October 1992 through December 2002.
John H. Forsgren (2) 56 Vice Chairman of NU since May 1, 2001; Executive Vice President and Chief Financial Officer of NU since February 1, 1996; Executive Vice President and Chief Financial Officer of CL&P, PSNH, and WMECO since February 27, 2003 and from February 1996 to June 1999; Director of WMECO since June 10, 1996 and of PSNH since August 5, 1996 and a Director of Northeast Utilities Foundation, Inc. since September 23, 1998; Director of CL&P from June 1996 to June 1999.
Cheryl W. Grise (3) 50 President - Utility Group of NU since May 2001, Chief Executive Officer of CL&P, PSNH and WMECO since September 10, 2002 a Director of CL&P since May 1, 2001, PSNH since May 14, 2001 and WMECO since June 2001, and a Director of Northeast Utilities Foundation, Inc. since September 23, 1998; previously President of CL&P from May 2001 to September 2001, Senior Vice President, Secretary and General Counsel of NU from July 1998 to May 2001, Senior Vice President, Secretary and General Counsel of CL&P, and PSNH and Senior Vice President, Secretary, Assistant Clerk and General Counsel of WMECO from July 1998 to June 1999 and Senior Vice President, Secretary and General Counsel of NGC from January 1999 to June 1999; previously Director of CL&P and WMECO (January 1994 through November 1997) and PSNH (February 1995 through November 1997); Senior Vice President and Chief Administrative Officer of CL&P and PSNH, and Senior Vice President of WMECO from 1995 to 1998.
Bruce D. Kenyon 60 Retired January 1, 2003; previously President-Generation Group of NU from March 1999 through December 2002 and a Director of Northeast Utilities Foundation, Inc. from September 1998 through December 2002; President-Generation Group of CL&P, PSNH and WMECO from March 1999 to June 1999; President-Nuclear Group of NU, CL&P, PSNH and WMECO from September 1996 to March 1999, a Director of CL&P and WMECO from September 1996 to June 1999, and a Director of PSNH from November 1997 to June 1999.
Kerry J. Kuhlman 52 President and Chief Operating Officer and a Director of WMECO since April 1999; previously Vice President-Customer Operations of WMECO from October 1998 to April 1999; Vice President-Central Region of CL&P from August 1997 to October 1998; and Vice President- Eastern Region of CL&P from July 1994 to August 1997.
Gerald Letendre (4) 61 President, Diamond Casting & Machine Co., Inc. since 1972. Director of PSNH from October 1992 through December 2002.
Gary A. Long 51 President and Chief Operating Officer and a Director of PSNH since July 1, 2000; previously Senior Vice President-PSNH of PSNH from February 2000 through June 2000 and Vice President-Customer Service and Economic Development of PSNH from January 1994 to February 2000.
Paul J. McDonald (5) 59 Advisor to the Board of Directors, Friendly Ice Cream Corporation since January 2000; Director of WMECO from September 1999 through December 2002; previously Senior Executive Vice President and Chief Financial Officer, Friendly Ice Cream Corporation from 1986 to 1999.
Michael G. Morris (6) 56 Chairman of the Board, President and Chief Executive Officer and a Trustee of NU and Chairman and a Director of PSNH and WMECO since August 19, 1997 and a Director of Northeast Utilities Foundation, Inc. since September 23, 1998; previously Chief Executive Officer of PSNH from August 19, 1997 through March 1, 2000 and from July 1, 2000 through September 10, 2002; Chief Executive Officer of WMECO from June 30, 1999 to September 10, 2002; Chairman and a Director of CL&P from August 1997 to June 1999; and President and Chief Executive Officer of Consumers Power Company from 1994 to 1997.
Jane E. Newman (7) 57 Executive Dean, Harvard University's John F. Kennedy School of Government since July 2000; Director of PSNH from October 1992 through December 2002. Previously Managing Director, The CommerceGroup, LLC, a strategic communications company, from January 1999 to July 2000; and Dean, Whittemore School of Business and Economics of the University of New Hampshire from January 1998 to January 1999; Executive Vice President and Director of Exeter Trust Company from 1995 to 1997.
Leon J. Olivier 54 President and Chief Operating Officer and a Director of CL&P since September 2001; previously Senior Vice President of Entergy Nuclear Corp. from April 2001 to September 2001; Senior Vice President and Chief Nuclear Officer of Northeast Nuclear Energy Company from October 1998 to May 2001; and Senior Vice President, Nuclear of Boston Edison Company from 1997 to October 1998.
Melinda M. Phelps 46 Partner, Bulkley, Richardson & Gelinas, LLP since January 1, 2001; Director of WMECO from September 1999 through December 2002. Previously of counsel to Bulkley, Richardson & Gelinas, LLP, from May 2000 through December 2000 and partner, Keyes and Donnellan, P.C., from 1992 to 2000.
Charles W. Shivery 57 President-Competitive Group of NU and President and Chief Executive Officer of NU Enterprises, Inc., since June 2002; previously Co- President of Constellation Energy Group, Inc. from October 2000 to February 2002; President and Chief Executive Officer of Constellation Power Source Holdings, Inc., from July 2000 to February 2002; Chief Executive Officer and President of Constellation Enterprises, Inc. from 1998 to February 2002; and Chairman of the Board, President and Chief Executive Officer of Constellation Power Source, Inc., from 1997 to February 2002.
(1) Mr. Collins is a Director of Blue Cross and Blue Shield of Vermont, The Vermont Health Plan, and Hamden Assurance Company Limited. (2) Mr. Forsgren is a Director of NEON Communications, Inc. and CuraGen Corporation, and a member of the Board of Regents of Georgetown University. (3) Mrs. Grise is a Director of Dana Corporation, University of Connecticut Foundation and American Red Cross, Greater Hartford Chapter. (4) Mr. Letendre is a Director of the National Association of Manufacturers (Washington, DC). (5) Mr. McDonald is a Director of CIGNA Investments Inc. and Polytainer's, LLC (Toronto, Canada). (6) Mr. Morris is a Director of the Edison Electric Institute, the American Gas Association, Nuclear Electric Insurance Limited, St. Francis Care, Inc., Connecticut Business & Industry Association, the Webster Financial Corporation, and the Spinnaker Exploration Co. Mr. Morris is also a Regent of Eastern Michigan University. (7) Ms. Newman is a Director of Citizens Advisors.
There are no family relationships between any director or executive officer and any other director or executive officer of NU, CL&P, PSNH or WMECO.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
NU
Incorporated herein by reference is the information contained in the sections "Executive Compensation," "Long-Term Incentive Plans - Awards in Last Fiscal Year," "Pension Benefits," "Trustee Compensation," "Employment Contracts and Termination of Employment Arrangements," "Compensation Committee Report on Executive Compensation" and "Share Performance Chart" of the definitive proxy statement for solicitation of proxies by NU's Board of Trustees, dated March 27, 2003, which will be filed with the Commission pursuant to Rule 14a-6 under the Securities Exchange Act of 1934.
SUMMARY COMPENSATION TABLE CL&P, PSNH, WMECO
The following tables present the cash and non-cash compensation received by the Chief Executive Officer and the next four highest paid executive officers of CL&P, PSNH, and WMECO accordance with rules of the SEC:
AGGREGATED OPTIONS/SAR EXERCISES IN LAST FISCAL YEAR AND FY-END OPTION/SAR VALUES
Notes to Summary Compensation and Option/SAR Grants Tables:
1. Other annual compensation for Mr. Morris includes personal use of the Company's airplane, having a cost to the Company of $180,886 in 2002, $219,088 in 2001, and $173,357 in 2000.
2. At December 31, 2002, the aggregate restricted stock holdings by the individuals named in the table were 36,978 shares with a value of $560,956. No restricted shares were awarded as incentive compensation to these individuals in 2002; payment of 50 percent of the 2001 annual bonus of each of Mr. Morris, Mr. Forsgren, and Mrs. Grise was made on February 25, 2002 in the form of restricted shares vesting one-third on February 25, 2003, February 25, 2004, and February 25, 2005. Dividends on restricted stock are paid out.
3. "All Other Compensation" for 2002 consists of employer matching contributions under the Northeast Utilities Service Company 401k Plan, generally available to all eligible employees (each of Messrs. Morris, Forsgren, Butler and Mrs. Grise - $6,000, Mr. Long - $5,345 and Ms. Kuhlman - $5,193) and matching contributions under the Deferred Compensation Plan for Executives (Mr. Morris - $21,462, Mrs. Grise - $6,277 and Mr. Olivier - $9,117). For Mr. Forsgren and Mrs. Grise, it also includes vested deferred compensation paid out on June 28, 2002 of $173,674 and $168,246 respectively (See Employment Contracts and Termination of Employment and Change in Control Arrangements, Below).
4. These options were granted on February 25, 2002 under the Northeast Utilities Incentive Plan (Incentive Plan). All options granted vest one-third on February 25, 2003, one-third on February 25, 2004 and one-third on February 25, 2005. Valued using the Black-Scholes option pricing model, discounted by 5.88% to reflect the risk of forfeiture, with the following assumptions: Volatility: 24.33 percent (36 months of monthly data); Risk-free rate: 5.18 percent; Dividend yield: 1.82 percent; Exercise date: February 25, 2012.
5. These options were granted on November 1, 2002 under the Incentive Plan. All options granted vest one-third on November 1, 2003, one- third on November 1, 2004 and one-third on November 1, 2005. Valued using the Black-Scholes option pricing model, discounted by 14.13% to reflect the risk of forfeiture, with the following assumptions: Volatility: 23.09 percent (36 months of monthly data); Risk-free rate: 4.47 percent; Dividend yield: 2.44 percent; Exercise date: November 1, 2012.
LONG-TERM INCENTIVE PLANS - AWARDS IN LAST FISCAL YEAR
Grants of performance units were made during 2002 under the Incentive Plan to the Company's officers. Payments will be made in cash following the close of the performance period. Threshold, target, and maximum payouts will be determined based on average annual rate of growth in net earnings over the performance period. Grants to the executive officers named in the Summary Compensation Table were as follows:
PENSION BENEFITS
The tables on the following pages show the estimated annual retirement benefits payable to an executive officer of Northeast Utilities upon retirement, assuming that retirement occurs at age 65 and that the officer is at that time not only eligible for a pension benefit under the Northeast Utilities Service Company Retirement Plan (the Retirement Plan) but also eligible for either the make-whole benefit or the make-whole benefit plus the target benefit under the Supplemental Executive Retirement Plan for Officers of Northeast Utilities System Companies (the Supplemental Plan). The Supplemental Plan is a non-qualified pension plan providing supplemental retirement income to system officers. The make-whole benefit under the Supplemental Plan, available to all officers, makes up for benefits lost through application of certain tax code limitations on the benefits that may be provided under the Retirement Plan, and includes as "compensation" awards under the executive incentive plans and deferred compensation (as earned). The target benefit further supplements these benefits and is available to officers at the Senior Vice President level and higher who are selected by the Board of Trustees to participate in the target benefit and who remain in the employ of Northeast Utilities companies until at least age 60 (unless the Board of Trustees sets an earlier age).
Mr. Morris's Employment Agreement provides that upon retirement (or upon disability or termination or following a change of control, as defined) he will be entitled to receive a special retirement benefit calculated by applying the benefit formula of the CMS Energy/Consumers Energy Company (CMS) Supplemental Executive Retirement Plan to all compensation earned from the Company and to all service rendered to the Company and CMS. If Mr. Morris retires after age 60, his special retirement benefit will be no less than that which he would have received had he been eligible for a make-whole benefit plus a target benefit under the Supplemental Plan.
Mr. Forsgren and Mrs. Grise are currently eligible for a make-whole plus a target benefit. Messrs. Butler, Olivier and Long and Mrs. Kuhlman are eligible for the make-whole benefit but not the target benefit.
Mr. Forsgren's Employment Agreement provides for supplemental pension benefits based on crediting up to ten years additional service and providing payments equal to 25 percent of final average compensation (not to exceed 170 percent of highest average base compensation received in any 36 month period) for up to 15 years following retirement, reduced by four percentage points for each year that his age is less than 65 years at retirement. In addition, if Mr. Forsgren retires after age 58, he will be eligible for a make-whole plus a target benefit under the Supplemental Plan based on crediting three extra years of service, unreduced for early commencement.
ANNUAL BENEFIT FOR OFFICERS ELIGIBLE FOR MAKE-WHOLE BENEFIT
Final Years of Credited Service Average Compensation 15 20 25 30 35
$200,000 $43,521 $58,028 $72,535 $87,042 $101,549 $250,000 $54,771 $73,028 $91,285 $109,542 $127,799 $300,000 $66,021 $88,028 $110,035 $132,042 $154,049 $350,000 $77,271 $103,028 $128,785 $154,542 $180,299 $400,000 $88,521 $118,028 $147,535 $177,042 $206,549 $450,000 $99,771 $133,028 $166,285 $199,542 $232,799 $500,000 $111,021 $148,028 $185,035 $222,042 $259,049 $600,000 $133,521 $178,028 $222,535 $267,042 $311,549 $700,000 $156,021 $208,028 $260,035 $312,042 $364,049 $800,000 $178,521 $238,028 $297,535 $357,042 $416,549 $900,000 $201,021 $268,028 $335,035 $402,042 $469,049 $1,000,000 $223,521 $298,028 $372,535 $447,042 $521,549 $1,100,000 $246,021 $328,028 $410,035 $492,042 $574,049 $1,200,000 $268,521 $358,028 $447,535 $537,042 $626,549
ANNUAL BENEFIT FOR OFFICERS ELIGIBLE FOR MAKE-WHOLE PLUS TARGET BENEFIT
Final Years of Credited Service Average Compensation 15 20 25 30 35 $ 200,000 $ 72,000 $ 96,000 $120,000 $120,000 $120,000 250,000 90,000 120,000 150,000 150,000 150,000 300,000 108,000 144,000 180,000 180,000 180,000 350,000 126,000 168,000 210,000 210,000 210,000 400,000 144,000 192,000 240,000 240,000 240,000 450,000 162,000 216,000 270,000 270,000 270,000 500,000 180,000 240,000 300,000 300,000 300,000 600,000 216,000 288,000 360,000 360,000 360,000 700,000 252,000 336,000 420,000 420,000 420,000 800,000 288,000 384,000 480,000 480,000 480,000 900,000 324,000 432,000 540,000 540,000 540,000 1,000,000 360,000 480,000 600,000 600,000 600,000 1,100,000 396,000 528,000 660,000 660,000 660,000 1,200,000 432,000 576,000 720,000 720,000 720,000
The benefits presented in the tables above are based on a straight life annuity beginning at age 65 and do not take into account any reduction for joint and survivorship annuity payments. Final 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. Final average compensation for purposes of calculating the make- whole benefit is the highest average annual compensation of the participant during any 60 consecutive months compensation was earned. Compensation for these benefits includes the annual salary and bonus shown in the Summary Compensation Table and, for officers hired before November 1, 2001, an amount that represents the annual value of long term incentive compensation. Compensation for purposes of these benefits does not include employer matching contributions under the 401k Plan. In the event that an officer's employment terminates because of disability, the retirement benefits shown above would be offset by the amount of any disability benefits payable to the recipient that are attributable to contributions made by Northeast Utilities and its subsidiaries under long term disability plans and policies.
Mr. Morris is not eligible to participate in the Supplemental Plan, but he does participate in the Retirement Plan. The amount of his annual compensation covered by the Retirement Plan was limited by the IRS to $200,000 for 2002. The compensation covered by the Supplemental Plan in 2002 for Mr. Forsgren, Mrs. Grise, Mr. Butler, Mr. Olivier, Mr. Long, and Mrs. Kuhlman was $933,084, $826,155, $307,699, $484,360, $270,840, and $258,191, respectively.
As of December 31, 2002, the executive officers named in the Summary Compensation Table had approximately the following years of credited service for purposes of the Supplemental Plan: Mr. Kenyon - 8, Mr. Forsgren - 6, Mrs. Grise - 22, Mr. Butler - 6, -Mr. Olivier - 4, Mr. Long - 27, and Mrs. Kuhlman - - 22. Mr. Morris had 24 years of service for purpose of his special retirement benefit. In addition, Mr. Forsgren had 12 years of service for purposes of his supplemental pension benefit and would have 25 years of service for such purpose if he were to retire at age 65.
COMPENSATION OF DIRECTORS
During 2002 each non-employee Director of PSNH and WMECO was compensated at an annual rate of $10,000 cash, and received $500 for each meeting attended of the Board of Directors or, in the case of PSNH, its committees. A non-employee Director who participates in a meeting of the Board of Directors or any of its committees by conference telephone receives $300 per meeting. Also, committee chairs were compensated at an additional annual rate of $1,500.
EMPLOYMENT CONTRACTS AND TERMINATION OF EMPLOYMENT ARRANGEMENTS
Northeast Utilities has entered into an employment agreement with Mr. Morris and NUSCO has entered into employment agreements with Mr. Forsgren and Mrs. Grise; each of the other named executive officers participates in the Special Severance Program for Officers of Northeast Utilities Companies. The agreements and the Special Severance Program are also binding on Northeast Utilities and on each majority-owned subsidiary of Northeast Utilities.
Each agreement obligates the officer to perform such duties as may be directed by the NUSCO Board of Directors or the Northeast Utilities Board of Trustees, protect the Company's confidential information, and refrain, while employed by the Company and for a period of time thereafter, from competing with the Company in a specified geographic area. Each agreement provides that the officer's base salary will not be reduced below certain levels without the consent of the officer, and that the officer will participate in specified benefits under the Supplemental Executive Retirement Plan or other supplemental retirement programs (see Pension Benefits, above) and/or in certain executive incentive programs at specified incentive opportunity levels.
Each agreement provides for a specified employment term and for automatic one-year extensions of the employment term unless at least six months' notice of non-renewal is given by either party. The employment term may also be ended by the Company for "cause", as defined, at any time (in which case no supplemental retirement benefit, if any, shall be due), or by the officer on thirty days' prior written notice for any reason. Absent "cause", the Company may remove the officer from his or her position on sixty days' prior written notice, but in the event the officer is so removed and signs a release of all claims against the Company, the officer will receive one or two years' base salary and annual incentive payments, specified employee welfare and pension benefits, and vesting of stock appreciation rights, options and restricted stock.
Under the terms of the agreements and the Special Severance Program, upon any termination of employment following a change of control, as defined, between (a) the earlier of the date shareholders approve a change of control transaction or a change of control transaction occurs and (b) the earlier of the date, if any, on which the Board of Trustees abandons the transaction or the date two years following the change of control, if the officer signs a release of all claims against the Company, the officer will be entitled to certain payments including a multiple (not to exceed three) of annual base salary, annual incentive payments, specified employee welfare and pension benefits, and vesting of stock appreciation rights, options and restricted stock. Certain of the change of control provisions may be modified by the Board of Trustees prior to a change of control, on at least two years' notice to the affected officer(s).
Besides the terms described above, the agreements of Messrs. Morris and Forsgren provide for a specified salary, cash, restricted stock and/or stock options upon employment, special incentive programs and/or special retirement benefits. See Pension Benefits, above, for further description of these provisions. The agreements of Mr. Forsgren and Mrs. Grise were supplemented during 2001 to provide for special deferred compensation of $520,000 and $500,000, respectively, vesting in even installments (adjusted to reflect investment performance) on June 28, 2002, 2003 and 2004, so long as such officer remains in the employ of Northeast Utilities Service Company, and vesting sooner in the event of a change of control of the Company or involuntary termination without cause.
Letter agreements reflecting the terms of employment of Messrs. Butler, Boguslawski, and Olivier provide for specified salary, cash, restricted stock, stock options or other benefits upon employment.
The descriptions of the various agreements set forth above are for purpose of disclosure in accordance with the proxy and other disclosure rules of the SEC and shall not be controlling on any party; the actual terms of the agreements themselves determine the rights and obligations of the parties.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
NU.
Incorporated herein by reference is the information contained in the sections "Common Stock Ownership of Certain Beneficial Owners", "Common Stock Ownership of Management", and "Securities Authorized for Issuance Under Equity Compensation Plans" of the definitive proxy statement for solicitation of proxies by NU's Board of Trustees, dated March 27, 2003, which will be filed with the Commission pursuant to Rule 14a-6 under the Securities Exchange Act of 1934.
CL&P, PSNH, and WMECO.
NU owns 100% of the outstanding common stock of registrants CL&P, PSNH, and WMECO. As of March 14, 2003, the Directors and Executive Officers of CL&P, PSNH, and WMECO beneficially owned the number of shares of each class of equity securities of NU listed below. No equity securities of CL&P, PSNH, or WMECO are owned by the Directors and Executive Officers of CL&P, PSNH, and WMECO. Unless otherwise noted, each Director and Executive Officer of CL&P, PSNH, and WMECO has sole voting and investment power with respect to the listed shares.
Title of Amount and Nature of Percent of Class Name Beneficial Ownership Class
NU Common David H. Boguslawski (1) 34,373 (2) NU Common Gregory B. Butler (3) 49,018 (2) NU Common John H. Forsgren (4) 187,567 (2) NU Common Cheryl W. Grise (5) 128,135 (2) NU Common Kerry J. Kuhlman (6) 32,555 (2) NU Common Gary A. Long (7) 30,871 (2) NU Common Michael G. Morris (8) 1,067,100 (2) NU Common Leon J. Olivier (9) 16,683 (2)
Amount beneficially owned by Directors and Executive Officers as a group:
Amount and Nature of Percent of Company Number of Persons Beneficial Ownership Outstanding
CL&P 6 1,482,876 (2) PSNH 6 1,497,064 (2) WMECO 6 1,498,748 (2)
(1) Includes 23,704 shares that could be acquired by Mr. Boguslawski pursuant to currently exercisable options and 5,304 restricted shares, as to which Mr. Boguslawski has sole voting and no dispositive power.
(2) As of March 14, 2003, there were 130,383,840 common shares of NU outstanding. The percentage of such shares beneficially owned by any Director or Executive Officer of CL&P, PSNH, or WMECO and by all of the Directors and Executive Officers of each of CL&P, PSNH and WMECO does not exceed one percent.
(3) Includes 34,182 shares that could be acquired by Mr. Butler pursuant to currently exercisable options and 7,779 restricted shares as to which Mr. Butler has sole voting and no dispositive power.
(4) Includes 143,718 shares that could be acquired by Mr. Forsgren pursuant to currently exercisable options and 39,631 restricted shares as to which Mr. Forsgren has sole voting and no dispositive power.
(5) Includes 73,292 shares that could be acquired by Mrs. Grise pursuant to currently exercisable options, 36,072 restricted as to which Mrs. Grise has sole voting and no dispositive power, and 265 shares held by Mrs. Grise's husband as custodian for her children, with whom she shares voting and dispositive power.
(6) Includes 21,529 shares that could be acquired by Ms. Kuhlman pursuant to currently exercisable options and 4,420 restricted shares, as to which Ms. Kuhlman has sole voting and no dispositive power.
(7) Includes 20,399 shares that could be acquired by Mr. Long pursuant to currently exercisable options and 4,597 restricted shares, as to which Mr. Long has sole voting and no dispositive power.
(8) Includes 979,792 shares that could be acquired by Mr. Morris pursuant to currently exercisable options and 31,732 restricted shares as to which Mr. Morris has sole voting and no dispositive power.
(9) Includes 6,634 shares that could be acquired by Mr. Olivier pursuant to currently exercisable options and 5,552 restricted shares, as to which Mr. Olivier has sole voting and no dispositive power.
SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS
The following table sets forth the number of Common Shares of Northeast Utilities issuable under the equity compensation plans of the Northeast Utilities System, as well as their weighted exercise price, in accordance with the rules of the SEC:
Notes to table:
1. Under the Incentive Plan, 3,873,851 shares were available for issuance as of December 31, 2002. In addition, an amount equal to one percent of the outstanding shares as of the end of each year becomes available for issuance under the Incentive Plan the following year. Under the Northeast Utilities Employee Share Purchase Plan II, 7,438,295 additional shares are available for issuance. Each such plan expires in 2008.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Incorporated herein by reference is the information contained in the section "Certain Relationships and Related Transactions" of the definitive proxy statement for solicitation of proxies by NU's Board of Trustees, dated March 27, 2003, which will be filed with the Commission pursuant to Rule 14a- 6 under the Securities Exchange Act of 1934.
ITEM 14.
ITEM 14. CONTROLS AND PROCEDURES
NU, CL&P, PSNH and WMECO (collectively, the companies) evaluated the design and operation of their disclosure controls and procedures to determine whether they are effective in ensuring that the disclosure of required information is timely made in accordance with the Exchange Act and the rules and forms of the SEC. These evaluations were made under the supervision and with the participation of management, including the companies' principal executive officer and principal financial officer, within the 90-day period prior to the filing of this Annual Report on Form 10-K. The principal executive officer and principal financial officer have concluded, based on their review, that the companies' disclosure controls and procedures, as defined at Exchange Act Rules 13a-14(c) and 15(d)-14(c), are effective to ensure that information required to be disclosed by the companies in reports that it files under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms. No significant changes were made to the companies' internal controls or other factors that could significantly affect these controls subsequent to the date of their evaluation.
PART IV
ITEM 15.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) 1. Financial Statements:
The Report of Independent Public Accountants and financial statements of CL&P, PSNH and WMECO are hereby incorporated by reference and made a part of this report (see "Item 8. Financial Statements and Supplementary Data").
Independent Auditors' Report S-1
Independent Auditors' Consent S-2
2. Schedules:
Financial Statement Schedules for NU (Parent), NU and Subsidiaries, CL&P and Subsidiaries, PSNH and Subsidiaries, and WMECO and Subsidiary are listed in the Index to Financial Statements Schedules S-3
3. Exhibits Index E-1
(b) Reports on Form 8-K:
NU filed a current report on Form 8-K dated January 22, 2002, disclosing:
o NU's earnings press release for the fourth quarter and full year 2001.
NU and PSNH filed current reports on Form 8-K dated January 30, 2002, disclosing:
o The closing on the sale of $50 million of RRBs through PSNH's subsidiary, PSNH Funding LLC 2.
NU, CL&P, PSNH, and WMECO filed current reports on Form 8-K dated March 15, 2002, disclosing:
o NU's change in its certifying accountant.
NU filed a current report on Form 8-K/A dated March 15, 2002, disclosing:
o An amendment to NU's current report on Form 8-K dated March 15, 2002, disclosing NU's change in its certifying accountant.
NU and CL&P filed current reports on Form 8-K dated June 17, 2002, disclosing:
o NU's lowering of its earnings estimates for 2002 and CL&P's criticism of the DPUC's decision on standard offer generation rates.
NU filed a current report on Form 8-K dated August 2, 2002, disclosing:
o NU's submission to the SEC of Statements under Oath of the Principal Executive Officer and Principal Financial Officer in accordance with the SEC's June 27, 2002 Order requiring the filing of sworn statements pursuant to Section 21(a)(1) of the Securities and Exchange Act of 1934.
NU filed a current report on Form 8-K dated August 14, 2002, disclosing:
o NU's submission to the SEC of certain Statements under Oath of the Principal Executive Officer and Principal Financial Officer in accordance with the SEC's June 27, 2002 Order requiring the filing of sworn statements pursuant to Section 21(a)(1) of the Securities and Exchange Act of 1934.
NU, CL&P, PSNH and WMECO filed current reports on Form 8-K dated November 26, 2002, disclosing:
o An increase in the estimated decommissioning costs associated with various nuclear units.
NU, CL&P, PSNH and WMECO filed current reports on Form 8-K/A dated November 26, 2002, providing:
o An amendment to their respective current reports on Form 8-K dated November 26, 2002, disclosing an increase in the estimated decommissioning costs associated with various nuclear units.
NU filed a current report on Form 8-K dated January 28, 2003, disclosing:
o NU's earnings press release for the fourth quarter and full year 2002.
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 21, 2003 By /s/ Michael G. Morris -------------- --------------------- Michael G. Morris Chairman of the Board, President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
Date Title Signature - ---- ----- ---------
March 21, 2003 Chairman of the Board, /s/ Michael G. Morris - -------------- President and ----------------------------- Chief Executive Officer Michael G. Morris and a Trustee
March 21, 2003 Vice Chairman, /s/ John H. Forsgren - -------------- Executive Vice ---------------------------- President and Chief John H. Forsgren Financial Officer and a Trustee
March 21, 2003 Vice President - /s/ John P. Stack - -------------- Accounting and ---------------------------- Controller John P. Stack
March 21, 2003 Trustee /s/ Richard H. Booth - -------------- ---------------------------- Richard H. Booth
March 21, 2003 Trustee /s/ Cotton M. Cleveland - -------------- ---------------------------- Cotton M. Cleveland
March 21, 2003 Trustee /s/ Sanford Cloud, Jr. - -------------- ---------------------------- Sanford Cloud, Jr.
March 21, 2003 Trustee /s/ James F. Cordes - -------------- ---------------------------- James F. Cordes
March 21, 2003 Trustee /s/ E. Gail de Planque - -------------- ---------------------------- E. Gail de Planque
March 21, 2003 Trustee /s/ Elizabeth T. Kennan - -------------- ---------------------------- Elizabeth T. Kennan
March 21, 2003 Trustee /s/ Robert E. Patricelli - -------------- ---------------------------- Robert E. Patricelli
March 21, 2003 Trustee /s/ John F. Swope - -------------- ---------------------------- John F. Swope
CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, Michael G. Morris, Chairman, President and Chief Executive Officer of Northeast Utilities (the Company), certify that:
1. I have reviewed this annual report on Form 10-K of the Company;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the Evaluation Date); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: March 21, 2003
/s/ Michael G. Morris (Signature) Michael G. Morris Chairman, President and Chief Executive Officer
CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, John H. Forsgren, Vice Chairman, Executive Vice President and Chief Financial Officer of Northeast Utilities (the Company), certify that:
1. I have reviewed this annual report on Form 10-K of the Company;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the Evaluation Date); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: March 21, 2003
/s/ John H. Forsgren (Signature) John H. Forsgren Vice Chairman, Executive Vice President and Chief Financial Officer
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 21, 2003 By /s/ Cheryl W. Grise -------------- --------------------------- Cheryl W. Grise Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
Date Title Signature - ---- ----- ---------
March 21, 2003 President and /s/ Leon J. Olivier - -------------- Chief Operating ---------------------------- Officer and Leon J. Olivier a Director
March 21, 2003 Chief Executive /s/ Cheryl W. Grise - -------------- Officer and ---------------------------- a Director Cheryl W. Grise
March 21, 2003 Executive Vice /s/ John H. Forsgren - -------------- President and ---------------------------- Chief Financial John H. Forsgren Officer
March 21, 2003 Vice President - /s/ John P. Stack - -------------- Accounting and ---------------------------- Controller John P. Stack
March 21, 2003 Director /s/ David H. Boguslawski - -------------- ---------------------------- David H. Boguslawski
CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, Cheryl W. Grise, Chief Executive Officer of The Connecticut Light and Power Company (the Company), certify that:
1. I have reviewed this annual report on Form 10-K of the Company;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the Evaluation Date); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: March 21, 2003
/s/ Cheryl W. Grise (Signature) Cheryl W. Grise Chief Executive Officer
CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, John H. Forsgren, Executive Vice President and Chief Financial Officer of The Connecticut Light and Power Company (the Company), certify that:
1. I have reviewed this annual report on Form 10-K of the Company;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the Evaluation Date); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: March 21, 2003
/s/ John H. Forsgren (Signature) John H. Forsgren Executive Vice President and Chief Financial Officer
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 21, 2003 By /s/ Cheryl W. Grise -------------- --------------------------- Cheryl W. Grise Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
Date Title Signature - ---- ----- ---------
March 21, 2003 Chairman /s/ Michael G. Morris - -------------- and a Director ---------------------------- Michael G. Morris
March 21, 2003 Chief Executive /s/ Cheryl W. Grise - -------------- Officer and ---------------------------- a Director Cheryl W. Grise
March 21, 2003 President and /s/ Gary A. Long - -------------- Chief Operating ---------------------------- Officer and Gary A. Long a Director
March 21, 2003 Executive Vice /s/ John H. Forsgren - -------------- President and ---------------------------- Chief Financial John H. Forsgren Officer and a Director
March 21, 2003 Vice President - /s/ John P. Stack - -------------- Accounting and ---------------------------- Controller John P. Stack
March 21, 2003 Director /s/ David H. Boguslawski - -------------- ---------------------------- David H. Boguslawski
CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, Cheryl W. Grise, Chief Executive Officer of Public Service Company of New Hampshire (the Company), certify that:
1. I have reviewed this annual report on Form 10-K of the Company;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the Evaluation Date); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: March 21, 2003
/s/ Cheryl W. Grise (Signature) Cheryl W. Grise Chief Executive Officer
CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, John H. Forsgren, Executive Vice President and Chief Financial Officer of Public Service Company of New Hampshire (the Company), certify that:
1. I have reviewed this annual report on Form 10-K of the Company;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the Evaluation Date); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: March 21, 2003
/s/ John H. Forsgren (Signature) John H. Forsgren Executive Vice President and Chief Financial Officer
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 21, 2003 By /s/ Cheryl W. Grise -------------- ----------------------------- Cheryl W. Grise Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
Date Title Signature - ---- ----- ---------
March 21, 2003 Chairman /s/ Michael G. Morris - -------------- and a Director ---------------------------- Michael G. Morris
March 21, 2003 Chief Executive /s/ Cheryl W. Grise - -------------- Officer and ---------------------------- a Director Cheryl W. Grise
March 21, 2003 President and /s/ Kerry J. Kuhlman - -------------- Chief Operating ---------------------------- Officer and Kerry J. Kuhlman a Director
March 21, 2003 Executive Vice /s/ John H. Forsgren - -------------- President and ---------------------------- Chief Financial John H. Forsgren Officer and a Director
March 21, 2003 Vice President - /s/ John P. Stack - -------------- Accounting and ---------------------------- Controller John P. Stack
March 21, 2003 Director /s/ David H. Boguslawski - -------------- ---------------------------- David H. Boguslawski
CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, Cheryl W. Grise, Chief Executive Officer of Western Massachusetts Electric Company (the Company), certify that:
1. I have reviewed this annual report on Form 10-K of the Company;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the Evaluation Date); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: March 21, 2003
/s/ Cheryl W. Grise (Signature) Cheryl W. Grise Chief Executive Officer
CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, John H. Forsgren, Executive Vice President and Chief Financial Officer of Western Massachusetts Electric Company (the Company), certify that:
1. I have reviewed this annual report on Form 10-K of the Company;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the Evaluation Date); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: March 21, 2003
/s/ John H. Forsgren (Signature) John H. Forsgren Executive Vice President and Chief Financial Officer
INDEPENDENT AUDITORS' REPORT
To the Board of Trustees and Shareholders of Northeast Utilities and the Boards of Directors of The Connecticut Light and Power Company, Public Service Company of New Hampshire and Western Massachusetts Electric Company:
We have audited the consolidated financial statements of Northeast Utilities and subsidiaries (the "Company") and The Connecticut Light and Power Company ("CL&P") as of December 31, 2002 and 2001 and for the years then ended, and the consolidated financial statements of Public Service Company of New Hampshire ("PSNH") and Western Massachusetts Electric Company ("WMECO") as of and for the year ended December 31, 2002 (collectively "the Companies"), and have issued our reports thereon dated January 28, 2003 (February 27, 2003 as to Note 8A) for the Company, January 28, 2003 (February 27, 2003 as to Note 6A) for CL&P, and January 28, 2003 for PSNH and WMECO; such financial statements and reports are included in Northeast Utilities' 2002 Annual Report to Shareholders and in CL&P 's, PSNH's and WMECO's 2002 annual reports, all of which are incorporated herein by reference. Our report on the consolidated financial statements of Northeast Utilities expresses an unqualified opinion and includes an explanatory paragraph with respect to the Company's adoption of Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended, effective January 1, 2001, and its adoption in 2002 of Emerging Issues Task Force Issue 02-3, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities," and SFAS No. 142, "Goodwill and Other Intangible Assets." Our report also includes an additional paragraph regarding the audit procedures we applied to certain adjustments made to the Company's 2000 consolidated financial statements for the transitional disclosures required by SFAS No. 142. We do not express an opinion or any form of assurance on the 2000 financial statements taken as a whole.
Our audits also included the 2002 and 2001 financial statement schedules of Northeast Utilities and CL&P and the 2002 financial statement schedules of PSNH and WMECO, listed in Item 15. The 2000 consolidated financial statements and financial statement schedules of Northeast Utilities and CL&P and the 2001 and 2000 financial statements and financial statement schedules of PSNH and WMECO were audited by other auditors who have ceased operations. Those auditors expressed an unqualified opinion on those financial statements and financial statement schedules in their reports dated January 22, 2002. These financial statement schedules are the responsibility of the Companies' management. Our responsibility is to express an opinion based on our audits. In our opinion, such financial statement schedules audited by us, 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/ Deloitte & Touche LLP Deloitte & Touche LLP
Hartford, Connecticut January 28, 2003
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration Statement Nos. 33-34622, 333-55142 and 33-40156 on Forms S-3 and Nos. 33-44814, 33-63023, 333-52413 and 333-52415 on Forms S-8 of Northeast Utilities (the Company) of our reports dated January 28, 2003 (February 27, 2003 as to Note 8A), appearing in and incorporated by reference in this Annual Report on Form 10-K of Northeast Utilities for the year ended December 31, 2002 (which express an unqualified opinion and include explanatory paragraphs with respect to the Company's adoption of Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended, effective January 1, 2001, and its adoption in 2002 of Emerging Issues Task Force Issue 02-3, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities" and SFAS No. 142, "Goodwill and Other Intangible Assets"). Our reports also include an additional paragraph regarding the audit procedures we applied to certain adjustments made to the Company's 2000 consolidated financial statements for the transitional disclosures required by SFAS No. 142. We do not express an opinion or any form of assurance on the 2000 consolidated financial statements taken as a whole.
/s/ Deloitte & Touche LLP Deloitte & Touche LLP
Hartford, Connecticut March 21, 2003
INDEX TO FINANCIAL STATEMENTS SCHEDULES
Schedule
I. Financial Information of Registrant: Northeast Utilities (Parent) Balance Sheets at December 31, 2002 and 2001 S-4
Northeast Utilities (Parent) Statements of Income for the Years Ended December 31, 2002, 2001, and 2000 S-5
Northeast Utilities (Parent) Statements of Cash Flows for the Years Ended December 31, 2002, 2001, and 2000 S-6
II. Valuation and Qualifying Accounts and Reserves for 2002, 2001, and 2000:
Northeast Utilities and Subsidiaries S-7 - S-9 The Connecticut Light and Power Company and Subsidiaries S-10 - S-12 Public Service Company of New Hampshire and Subsidiaries S-13 - S-15 Western Massachusetts Electric Company and Subsidiary S-16 - S-18
All other schedules of the companies' for which provision is made in the applicable regulations of the SEC are not required under the related instructions or are not applicable, and therefore have been omitted.
SCHEDULE I NORTHEAST UTILITIES (PARENT) FINANCIAL INFORMATION OF REGISTRANT BALANCE SHEETS AT DECEMBER 31, 2002 AND 2001 (Thousands of Dollars)
SCHEDULE I NORTHEAST UTILITIES (PARENT) FINANCIAL INFORMATION OF REGISTRANT STATEMENTS OF INCOME YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000 (Thousands of Dollars, Except Share Information)
SCHEDULE I NORTHEAST UTILITIES (PARENT) FINANCIAL INFORMATION OF REGISTRANT STATEMENTS OF CASH FLOWS YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000 (Thousands of Dollars)
EXHIBIT INDEX
Each document described below is incorporated by reference to the files of the SEC, unless the reference to the document is marked as follows:
* - Filed with the 2002 Annual Report on Form 10-K for NU and herein incorporated by reference from the 2002 NU Form 10-K, File No. 1-5324 into the 2002 Annual Reports on Form 10-K for CL&P, PSNH and WMECO.
# - Filed with the 2002 Annual Report on Form 10-K for NU and herein incorporated by reference from the 2002 NU Form 10-K, File No. 1-5324 into the 2002 Annual Report on Form 10-K for CL&P.
@ - Filed with the 2002 Annual Report on Form 10-K for NU and herein incorporated by reference from the 2002 NU Form 10-K, File No. 1-5324 into the 2002 Annual Report on Form 10-K for PSNH.
** - Filed with the 2002 Annual Report on Form 10-K for NU and herein incorporated by reference from the 2002 NU Form 10-K, File No. 1-5324 into the 2002 Annual Report on Form 10-K for WMECO.
Exhibit Number Description
2 Plan of acquisition, reorganization, arrangement, liquidation or succession
2.1 Amended and Restated Agreement and Plan of Merger (Exhibit 1 to NU's Current Report on Form 8-K dated December 2, 1999, File No. 1- 5324).
2.2 Purchase and Sale Agreement for the Seabrook Nuclear Power Station dated April 13, 2002 (Exhibit 10.63 to NU Form 10-Q for the quarter ended March 31, 2002, File No. 1-5324)
3 Articles of Incorporation and By-Laws
3.1 Northeast Utilities
3.1.1 Declaration of Trust of NU, as amended through May 24, 1988. (Exhibit 3.1.1, 1988 NU Form 10-K, File No. 1-5324)
3.2 The Connecticut Light and Power Company
3.2.1 Certificate of Incorporation of CL&P, restated to March 22, 1994. (Exhibit 3.2.1, 1993 NU Form 10-K, File No. 1-5324)
3.2.2 Certificate of Amendment to Certificate of Incorporation of CL&P, dated December 26, 1996. (Exhibit 3.2.2, 1996 NU Form 10-K, File No. 1-5324)
3.2.3 Certificate of Amendment to Certificate of Incorporation of CL&P, dated April 27, 1998. (Exhibit 3.2.3, 1998 NU Form 10-K, File No. 1-5324)
3.2.4 By-laws of CL&P, as amended to January 1, 1997. (Exhibit 3.2.3, 1996 NU Form 10-K, File No. 1-5324)
3.3 Public Service Company of New Hampshire
3.3.1 Articles of Incorporation, as amended to May 16, 1991. (Exhibit 3.3.1, 1993 NU Form 10-K, File No. 1-5324)
3.3.2 By-laws of PSNH, as amended to November 1, 1993. (Exhibit 3.3.2, 1993 NU Form 10-K, File No. 1-5324)
3.4 Western Massachusetts Electric Company
3.4.1 Articles of Organization of WMECO, restated to February 23, 1995. (Exhibit 3.4.1, 1994 NU Form 10-K, File No. 1-5324)
3.4.2 By-laws of WMECO, as amended to April 1, 1999. (Exhibit 3.1, 1999 NU Form 10-Q for the Quarter Ended June 30, 1999, File No. 1-5324)
3.4.3 By-laws of WMECO, as further amended to May 1, 2000. (Exhibit 3.1, 2000 NU Form 10-Q for the Quarter Ended June 30, 2000, File No. 1-5324)
4 Instruments defining the rights of security holders, including indentures
4.1 Northeast Utilities
4.1.1 Indenture dated as of December 1, 1991 between Northeast Utilities and IBJ Schroder Bank & Trust Company, with respect to the issuance of Debt Securities. (Exhibit 4.1.1, 1991 NU Form 10-K, File No. 1-5324)
4.1.1.1 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)
4.1.1.2 Second Supplemental Indenture dated as of March 1, 1992 between Northeast Utilities and IBJ Schroder Bank & Trust Company with respect to the issuance of 8.38% Amortizing Notes. (Exhibit 4.1.3, 1992 NU Form 10-K, File No. 1-5324)
4.1.2 Rights Agreement dated as of February 23, 1999, between Northeast Utilities and Northeast Utilities Service Company, as Rights Agent. (Exhibit 1 to NU's Registration Statement on Form 8-A, filed on April 12, 1999, File No. 001-05324).
4.1.2.1 Amendment to Rights Agreement. (Exhibit 3 to NU's Current Report on Form 8-K dated October 13, 1999, File No. 1-5324).
4.1.2.2 Second Amendment to Rights Agreement. (Exhibit 3 to NU Form 8-A-12B-A dated February 1, 2002, File No. 001-05324 and Exhibit B-3 to NU Rule 35-CERT, dated February 1, 2002, File No. 070-09463).
4.1.3 Indenture dated as of April 1, 2002, between NU and the Bank of New York as Trustee. (Exhibit A-3 to NU 35-CERT filed April 9, 2002, File No. 70-9535)
4.1.3.1 First Supplemental Indenture dated as of April 1, 2002, between NU and the Bank of New York as Trustee, relating to $263M of Senior Notes, Series A, due 2012. (Exhibit A-4 to NU 35-CERT filed April 9 2002, File No. 70-9535)
4.1.4 Revolving Credit Agreement among NU and the Banks named therein, dated November 12, 2002. (Exhibit B-3 to NU 35- CERT filed November 21, 2002, File No. 70-9755)
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:
4.2.1.1 June 1, 1994. (Exhibit 4.2.15, 1994 NU Form 10-K, File No. 1-5324)
4.2.1.2 October 1, 1994. (Exhibit 4.2.16, 1994 NU Form 10-K, File No. 1-5324)
4.2.2 Financing Agreement between Industrial Development Authority of the State of New Hampshire and CL&P (Pollution Control Bonds, 1986 Series) dated as of December 1, 1986. (Exhibit C.1.47, 1986 NU Form U5S, File No. 30-246)
4.2.3 Financing Agreement between Industrial Development Authority of the State of New Hampshire and CL&P (Pollution Control Bonds, 1988 Series) dated as of October 1, 1988. (Exhibit C.1.55, 1988 NU Form U5S, File No. 30-246)
4.2.4 Loan and Trust Agreement among Business Finance Authority of the State of New Hampshire, CL&P and the Trustee (Pollution Control Bonds, 1992 Series A) dated as of December 1, 1992. (Exhibit C.2.33, 1992 NU Form U5S, File No. 30-246)
4.2.5 Loan Agreement between Connecticut Development Authority and CL&P (Pollution Control Bonds - Series A, Tax Exempt Refunding) dated as of September 1, 1993. (Exhibit 4.2.21, 1993 NU Form 10-K, File No. 1-5324)
4.2.6 Loan Agreement between Connecticut Development Authority and CL&P (Pollution Control Bonds - Series B, Tax Exempt Refunding) dated as of September 1, 1993. (Exhibit 4.2.22, 1993 NU Form 10-K, File No. 1-5324)
4.2.7 Amended and Restated Loan Agreement between Connecticut Development Authority and CL&P (Pollution Control Revenue Bond - 1996A Series) dated as of May 1, 1996 and Amended and Restated as of January 1, 1997. (Exhibit 4.2.24, 1996 NU Form 10-K, File No. 1-5324)
4.2.7.1 Amended and Restated Indenture of Trust between Connecticut Development Authority and the Trustee (CL&P Pollution Control Revenue Bond-1996A Series), dated as of May 1, 1996 and Amended and Restated as of January 1, 1997. (Exhibit 4.2.24.1, 1996 NU Form 10-K, File No. 1-5324)
4.2.7.2 Standby Bond Purchase Agreement among CL&P, Bank of New York as Purchasing Agent and the Banks Named therein, dated October 24, 2000. (Exhibit 4.2.24.2 of 2000 NU Form 10-K, File No. 1-5324)
4.2.7.3 AMBAC Municipal Bond Insurance Policy issued by the Connecticut Development Authority (CL&P Pollution Control Revenue Bond- 1996A Series), effective January 23, 1997. (Exhibit 4.2.24.3, 1996 NU Form 10-K, File No. 1-5324)
4.2.7.4 Amendment No. 2 to the Standby Bond Purchase Agreement dated as of September 9, 2002, among CL&P, The Bank of New York, and the Participating Banks referred to therein. (Exhibit 4.2.7.4, 2002 NU Form 10-Q for the Quarter Ended September 30, 2002, File No. 1- 5324)
4.2.8 Amended and Restated Receivables Purchase and Sale Agreement dated as of March 30, 2001 (CL&P and CL&P Receivables Corporation (CRC)). (Exhibit 10.1, 2001 NU 10-Q for the Quarter Ended September 30, 2001 (File No. 1- 5324)
#4.2.8.1 Amendment No. 2 to the Purchase and Sale Agreement dated as of July 10, 2002 (CL&P and CRC).
4.2.9 Purchase and Contribution Agreement (CL&P and CRC), dated as of September 30, 1997 (Exhibit 10.49.1, 1997 NU Form 10-K, File No. 1-5324)
#4.2.9.1 Amendment No. 2 to the Purchase and Contribution Agreement between CL&P and CRC dated as of March 30, 2001.
4.2.10 Revolving Credit Agreement among WMECO, CL&P, PSNH and Yankee and the banks named therein, dated November 12, 2002. (Exhibit B-4 to 35-CERT filed November 21, 2002, File No. 70-9755)
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, now First Union National Bank, Trustee, (Composite including all amendments to May 16, 1991). (Exhibit 4.4.1, 1992 NU Form 10-K, File No. 1-5324)
4.3.1.1 Tenth Supplemental Indenture dated as of May 1, 1991 between PSNH and First Fidelity Bank, National Association, now First Union National Bank. (Exhibit 4.1, PSNH Current Report on Form 8-K dated February 10, 1992, File No. 1- 6392)
4.3.1.2 Twelfth Supplemental Indenture dated as of December 1, 2001 between PSNH and First Union National Bank. (Exhibit 4.3.1.2, 2001 NU Form 10-K, File No. 1-5324)
4.3.2 Series D (Tax Exempt Refunding) Amended and Restated PCRB Loan and Trust Agreement dated as of April 1, 1999. (Exhibit 4.3.6, 1999 NU Form 10-K, File No. 1-5324)
4.3.3 Series E (Tax Exempt Refunding) Amended & Restated PCRB Loan and Trust Agreement dated as of April 1, 1999. (Exhibit 4.3.7, 1999 NU Form 10-K, File No. 1-5324)
4.3.4 Series A Loan and Trust Agreement among Business Finance Authority of the State of New Hampshire and PSNH and State Street Bank and Trust Company, as Trustee (Tax Exempt Pollution Control Bonds) dated as of October 1, 2001. (Exhibit 4.3.4, 2001 NU Form 10-K, File No. 1- 5324)
4.3.5 Series B Loan and Trust Agreement among Business Finance Authority of the State of New Hampshire and PSNH and State Street Bank and Trust Company, as Trustee (Tax Exempt Pollution Control Bonds) dated as of October 1, 2001. (Exhibit 4.3.5, 2001 NU Form 10-K, File No. 1- 5324)
4.3.6 Series C Loan and Trust Agreement among Business Finance Authority of the State of New Hampshire and PSNH and State Street Bank and Trust Company, as Trustee (Tax Exempt Pollution Control Bonds) dated as of October1, 2001. (Exhibit 4.3.6, 2001 NU Form 10-K, File No. 1-5324)
4.3.7 Revolving Credit Agreement among WMECO, CL&P, PSNH and Yankee and the banks named therein, dated November 12, 2002. (Exhibit B-4 to 35-CERT filed November 21, 2002, File No. 70-9755)
4.4 Western Massachusetts Electric Company
4.4.1 Loan Agreement between Connecticut Development Authority and WMECO, (Pollution Control Bonds - Series A, Tax Exempt Refunding) dated as of September 1, 1993. (Exhibit 4.4.13, 1993 NU Form 10-K, File No. 1-5324)
4.4.2 Revolving Credit Agreement among WMECO, CL&P, PSNH and Yankee and the banks named therein, dated November 12, 2002. (Exhibit B-4 to 35-CERT filed November 21, 2002, File No. 70-9755)
10 Material Contracts
10.1 Stockholder Agreement dated as of July 1, 1964 among the stockholders of CYAPC. (Exhibit 10.1, 1994 NU Form 10-K, File No. 1-5324)
10.2 Form of Power Contract dated as of July 1, 1964 between CYAPC and each of CL&P, HELCO, PSNH and WMECO. (Exhibit 10.2, 1994 NU Form 10-K, File No. 1-5324)
10.2.1 Form of Additional Power Contract dated as of April 30, 1984, between CYAPC and each of CL&P, PSNH and WMECO. (Exhibit 10.2.1, 1994 NU Form 10-K, File No. 1-5324)
10.2.2 Form of 1987 Supplementary Power Contract dated as of April 1, 1987, between CYAPC and each of CL&P, PSNH and WMECO. (Exhibit 10.2.6, 1987 NU Form 10-K, File No. 1- 5324)
10.3 Capital Funds Agreement dated as of September 1, 1964 between CYAPC and CL&P, HELCO, PSNH and WMECO. (Exhibit 10.3, 1994 NU Form 10-K, File No. 1-5324)
10.4 Stockholder Agreement dated December 10, 1958 between YAEC and CL&P, HELCO, PSNH and WMECO. (Exhibit 10.4, 1993 NU Form 10-K, File No. 1-5324)
10.5 Form of Amendment No. 3, dated as of April 1, 1985, to Power Contract between YAEC and each of CL&P, PSNH and WMECO, including a composite restatement of original Power Contract dated June 30, 1959 and Amendment No. 1 dated April 1, 1975 and Amendment No. 2 dated October 1, 1980. (Exhibit 10.5, 1988 NU Form 10-K, File No. 1- 5324.)
10.5.1 Form of Amendment No. 4 to Power Contract, dated May 6, 1988, between YAEC and each of CL&P, PSNH and WMECO. (Exhibit 10.5.1, 1989 NU Form 10-K, File No. 1-5324)
10.5.2 Form of Amendment No. 5 to Power Contract, dated June 26, 1989, between YAEC and each of CL&P, PSNH and WMECO. (Exhibit 10.5.2, 1989 NU Form 10-K, File No. 1-5324)
10.5.3 Form of Amendment No. 6 to Power Contract, dated July 1, 1989, between YAEC and each of CL&P, PSNH and WMECO. (Exhibit 10.5.3, 1989 NU Form 10-K, File No. 1-5324)
10.5.4 Form of Amendment No. 7 to Power Contract, dated February 1, 1992, between YAEC and each of CL&P, PSNH and WMECO. (Exhibit 10.5.4, 1993 NU Form 10-K, File No. 1- 5324)
10.6 Stockholder Agreement dated as of May 20, 1968 among stockholders of MYAPC. (Exhibit 10.6, 1997 NU Form 10-K, File No. 1-5324)
10.7 Form of Power Contract dated as of May 20, 1968 between MYAPC and each of CL&P, HELCO, PSNH and WMECO. (Exhibit 10.7, 1997 Form 10-K, File No. 1-5324)
10.7.1 Form of Amendment No. 1 to Power Contract dated as of March 1, 1983 between MYAPC and each of CL&P, PSNH and WMECO. (Exhibit 10.7.1, 1993 NU Form 10-K, File No. 1- 5324)
10.7.2 Form of Amendment No. 2 to Power Contract dated as of January 1, 1984 between MYAPC and each of CL&P, PSNH and WMECO. (Exhibit 10.7.2, 1993 NU Form 10-K, File No. 1- 5324)
10.7.3 Form of Amendment No. 3 to Power Contract dated as of October 1, 1984 between MYAPC and each of CL&P, PSNH and WMECO. (Exhibit No. 10.7.3, 1994 NU Form 10-K, File No. 1-5324)
10.7.4 Form of Additional Power Contract dated as of February 1, 1984 between MYAPC and each of CL&P, PSNH and WMECO. (Exhibit 10.7.4, 1993 NU Form 10-K, File No. 1-5324)
10.8 Capital Funds Agreement dated as of May 20, 1968 between MYAPC and CL&P, PSNH, HELCO and WMECO. (Exhibit 10.8, 1997 NU Form 10-K, File No. 1-5324)
10.8.1 Amendment No. 1 to Capital Funds Agreement, dated as of August 1, 1985, between MYAPC, CL&P, PSNH and WMECO. (Exhibit No. 10.8.1, 1994 NU Form 10-K, File No. 1-5324)
10.9 Sponsor Agreement dated as of August 1, 1968 among the sponsors of VYNPC. (Exhibit 10.9, 1997 NU Form 10-K, File No. 1-5324)
10.10 Form of Power Contract dated as of February 1, 1968 between VYNPC and each of CL&P, HELCO, PSNH and WMECO. (Exhibit 10.10, 1997 NU Form 10-K, File No. 1-5324)
10.10.1 Form of Amendment to Power Contract dated as of June 1, 1972 between VYNPC and each of CL&P, HELCO, PSNH and WMECO. (Exhibit 5.22, File No. 2-47038)
10.10.2 Form of Second Amendment to Power Contract dated as of April 15, 1983 between VYNPC and each of CL&P, PSNH and WMECO. (Exhibit 10.10.2, 1993 NU Form 10-K, File No. 1- 5324)
10.10.3 Form of Third Amendment to Power Contract dated as of April 24, 1985 between VYNPC and each of CL&P, PSNH and WMECO. (Exhibit No. 10.10.3, 1994 NU Form 10-K, File No. 1-5324)
10.10.4 Form of Fourth Amendment to Power Contract dated as of June 1, 1985 between VYNPC and each of CL&P, PSNH and WMECO. (Exhibit No. 10.10.4, 1996 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, NU Form 10-K, File No. 1- 5324)
10.10.6 Form of Sixth Amendment to Power Contract dated as of May 6, 1988 between VYNPC and each of CL&P, PSNH and WMECO. (Exhibit 10.10.6, 1990 NU Form 10-K, File No. 1- 5324)
10.10.7 Form of Seventh Amendment to Power Contract dated as of June 15, 1989 between VYNPC and each of CL&P, PSNH and WMECO. (Exhibit 10.10.7, 1990 NU Form 10-K, File No. 1- 5324)
10.10.8 Form of Eighth Amendment to Power Contract dated as of December 1, 1989 between VYNPC and each of CL&P, PSNH and WMECO. (Exhibit 10.10.8, 1990 NU Form 10-K, File No. 1- 5324)
10.10.9 Form of Additional Power Contract dated as of February 1, 1984 between VYNPC and each of CL&P, PSNH and WMECO. (Exhibit 10.10.9, 1993 NU Form 10-K, File No. 1-5324)
*10.10.10 Form of Amendatory Agreement, dated as of September 21, 2001 between VYNPC and each of CL&P, PSNH and WMECO.
10.11 Capital Funds Agreement dated as of February 1, 1968 between VYNPC and CL&P, HELCO, PSNH and WMECO. Exhibit 10.11, 1997 NU Form 10-K, File No. 1-5324)
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 10.11.1, 1997 NU Form 10-K, File No. 1-5324)
10.11.2 Form of Second Amendment to Capital Funds Agreement dated as of September 1, 1993 between VYNPC and CL&P, HELCO, PSNH and WMECO. (Exhibit 10.11.2, 1993 NU Form 10-K, File No. 1-5324)
10.12 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)
10.13 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)
10.14 Rate Agreement by and between NUSCO, on behalf of NU, and the Governor of the State of New Hampshire and the New Hampshire Attorney General dated as of November 22, 1989. (Exhibit 10.44, 1989 NU Form 10-K, File No. 1-5324)
10.14.1 First Amendment to Rate Agreement dated as of December 5, 1989. (Exhibit 10.16.1, 1995 NU Form 10-K, File No. 1-5324)
10.14.2 Second Amendment to Rate Agreement dated as of December 12, 1989. (Exhibit 10.16.2, 1995 NU Form 10-K, File No. 1-5324)
10.14.3 Third Amendment to Rate Agreement dated as of December 3, 1993. (Exhibit 10.16.3, 1995 NU Form 10-K, File No. 1-5324)
10.14.4 Fourth Amendment to Rate Agreement dated as of September 21, 1994. (Exhibit 10.16.4, 1995 NU Form 10-K, File No. 1-5324)
10.14.5 Fifth Amendment to Rate Agreement dated as of September 9, 1994. (Exhibit 10.16.5, 1995 NU Form 10-K, File No. 1-5324)
10.15 Agreement to Settle PSNH Restructuring. (Exhibit 10.2, 1999 NU Form 10-Q for the Quarter Ended June 30, 1999, File No. 1-5324)
10.15.1 Revised and Conformed Agreement to Settle PSNH Restructuring, dated August 2, 1999, conformed June 23 and executed on September 22, 2000. (Exhibit 10.15.1, 2001 NU Form 10-K, File No. 1-5324)
10.16 Merger Settlement Agreement between NU, Con Edison and NHPUC dated as of December 6, 2000. (Exhibit O.1, to NU's U-1 Application, File No. 70-9711)
10.17 Form of Seabrook Power Contracts between PSNH and NAEC, as amended and restated. (Exhibit 10.45, 1992 NU Form 10-K, File No. 1-5324)
10.18 Agreement (composite) for joint ownership, construction and operation of New Hampshire nuclear unit, as amended through the November 1, 1990 twenty-third amendment. (Exhibit No. 10.17, 1994 NU Form 10-K, File No. 1-5324)
10.18.1 Memorandum of Understanding dated November 7, 1988 between PSNH and Massachusetts Municipal Wholesale Electric Company. (Exhibit 10.17, PSNH 1989 Form 10-K, File No. 1-6392)
10.18.2 Agreement of Settlement among Joint Owners dated as of January 13, 1989. (Exhibit 10.13.21, 1988 NU Form 10-K, File No. 1-5324)
10.18.2.1 Supplement to Settlement Agreement, dated as of February 7, 1989, between PSNH and Central Maine Power Company. (Exhibit 10.18.1, PSNH 1989 Form 10-K, File No. 1-6392)
10.19 Amended and Restated Agreement for Seabrook Project Disbursing Agent dated as of November 1, 1990. (Exhibit 10.4.7, File No. 33- 35312)
10.19.1 Form of First Amendment to Exhibit 10.22. (Exhibit 10.4.8, File No. 33-35312)
10.19.2 Form (Composite) of Second Amendment to Exhibit 10.22. (Exhibit 10.18.2, 1993 NU Form 10-K, File No. 1- 5324)
10.20 Agreement dated November 1, 1974 for Joint Ownership, Construction and Operation of William F. Wyman Unit No. 4 among PSNH, Central Maine Power Company and other utilities. (Exhibit 5.16, File No. 2- 52900)
10.20.1 Amendment to Exhibit 10.20 dated June 30, 1975. (Exhibit 5.48, File No. 2-55458)
10.20.2 Amendment to Exhibit 10.20 dated as of August 16, 1976. (Exhibit 5.19, File No. 2-58251)
10.20.3 Amendment to Exhibit 10.20 dated as of December 31, 1978. (Exhibit 5.10.3, File No. 2-64294)
10.21 Form of Service Contract dated as of July 1, 1966 between each of NU, CL&P and WMECO and NUSCO. (Exhibit 10.20, 1993 NU Form 10-K, File No. 1-5324)
10.21.1 Service Contract dated as of June 5, 1992 between PSNH and NUSCO. (Exhibit 10.12.4, 1992 NU Form 10-K, File No. 1-5324)
10.21.2 Form of Annual Renewal of Service Contract. (Exhibit 10.20.3, 1993 NU Form 10-K, File No. 1-5324)
10.22 Service Contract dated as of January 4,1999 between NUSCO and NGC. (Exhibit 10.7 to NGC Registration Statement S-4 dated December 6, 2001, File No. 333-74636)
10.22.1 Form of Service Agreement Renewals, dated December 31, 1999 and December 31, 2000, of Service Contract, dated as of January 4, 1999, between NUSCO and NGC. (Exhibit 10.7.1 to NGC Registration Statement S-4 dated December 6, 2001, File No. 333-74636)
10.23 Management and Operating Agreement, dated February 1, 2000, between NGC and NGS. (Exhibit 10.6 to NGC Registration Statement S-4 dated December 6, 2001, File No. 333-74636)
10.23.1 Amendment No. 1, dated March 1, 2000, to Management and Operating Agreement, dated February 1, 2000, between NGC and NGS. (Exhibit 10.6.1 to NGC Registration Statement S-4 dated December 6, 2001, File No. 333-74636)
10.24 Memorandum of Understanding between CL&P, HELCO, HP&E, HWP and WMECO dated as of June 1, 1970 with respect to pooling of generation and transmission. (Exhibit 13.32, File No. 2-38177)
10.24.1 Amendment to Memorandum of Understanding between CL&P, HELCO, HP&E, HWP and WMECO dated as of February 2, 1982 with respect to pooling of generation and transmission. (Exhibit 10.21.1, 1993 NU Form 10-K, File No. 1-5324)
10.24.2 Amendment to Memorandum of Understanding between CL&P, HELCO, HP&E, HWP and WMECO dated as of January 1, 1984 with respect to pooling of generation and transmission. (Exhibit 10.21.2, 1994 NU Form 10-K, File No. 1-5324)
10.24.3 Second Amendment to Memorandum of Understanding between CL&P, HELCO, HP&E, HWP and WMECO dated as of June 8, 1999 with respect to pooling of generation and transmission. (Exhibit 10.23.3, 1999 NU Form 10-K, File No. 1-5324)
10.25 Restated NEPOOL Power Pool Agreement. (restated by the Sixty-Ninth Agreement dated as of December 31, 2000, and includes the Restated NEPOOL Open Access Transmission Tariff)
10.25.1 Form of Interim ISO Agreement (Attachment to Thirty-Third Amendment to Exhibit 10.26 dated as of December 31, 1996). (Exhibit 10.23.6, 1996 NU Form 10-K, File No. 1-5324)
*10.25.1.1 Amendment No. 3 to Interim ISO Agreement dated as of April 30, 2002.
10.25.2 Seventieth Agreement Amending NEPOOL Agreement (ISO Capital Funding Tariff) (FERC Docket ER-01-1460-000) dated as of February 2, 2001. (Exhibit 10.23.2, 2001 NU Form 10-K, File No. 1-5324)
10.25.3 Seventy-First Agreement Amending NEPOOL Agreement (Late Payment Fees) (FERC Docket ER-01-1460-000) dated as of February 2, 2001. (Exhibit 10.23.3, 2001 NU Form 10-K, File No. 1-5324)
10.25.4 Seventy-Second Agreement Amending NEPOOL Agreement (Net Commitment Period Compensation "NCPC") (FERC Docket ER-01- 1891-000) dated as of April 6, 2001. (Exhibit 10.23.4, 2001 NU Form 10-K, File No. 1-5324)
10.25.5 Seventy-Third Agreement Amending NEPOOL Agreement (Schedule 2 Changes) (FERC Docket ER-01-2161-000) dated as of May 9, 2001. (Exhibit 10.23.5, 2001 NU Form 10-K, File No. 1-5324)
10.25.6 Seventy-Fourth Agreement Amending NEPOOL Agreement (Review Bond Amendment) (FERC Docket ER-01-2140-000) dated as of May 9, 2001. (Exhibit 10.23.6, 2001 NU Form 10-K, File No. 1-5324)
10.25.7 Seventy-Sixth Agreement Amending NEPOOL Agreement (Compliance with June 13, 2001 Orders) (FERC Dockets EL00- 62-004, et al. and ER-98-3853-005) dated as of June 29, 2001. (Exhibit 10.23.7, 2001 NU Form 10-K, File No. 1- 5324)
10.25.8 Seventy-Eighth Agreement Amending NEPOOL Agreement (Revised Sections 18.4 and 18.5) (FERC Docket EL00-62- 036) dated as of September 24, 2001. (Exhibit 10.23.8, 2001 NU Form 10-K, File No. 1-5324)
10.25.9 Seventy-Ninth Agreement Amending NEPOOL Agreement (ICA Compliance Amendment) (FERC Docket EL00-62-036) dated as of September 24, 2001. (Exhibit 10.23.9, 2001 NU Form 10-K, File No. 1-5324)
10.25.10 Eightieth Agreement Amending NEPOOL Agreement (Generation Information System "GIS" Agreement) dated as of October 12, 2001. (Exhibit 10.23.10, 2001 NU Form 10-K, File No. 1-5324)
10.25.11 Eighty-First Agreement Amending NEPOOL Agreement (Restatement of Financial Assurance Policies) dated as of December 7, 2001. (Exhibit 10.23.11, 2001 NU Form 10-K, File No. 1-5324)
*10.25.12 Eighty-Second Agreement Amending NEPOOL Agreement (Amendment to Schedule 16) dates as of January 18, 2002.
*10.25.13 Eighty-Third Agreement Amending NEPOOL (Financial Assurance and Billing Policies) dated as of March 8, 2002.
*10.25.14 Eighty-Fourth Agreement Amending NEPOOL (Integration of Merchant Transmission Facilities) dated as of April 5, 2002.
*10.25.15 Eighty-Fifth Agreement Amending NEPOOL (Non Participant FTR Financial Assurance Policy) dated as of May 9, 2002.
*10.25.16 Eighty-Sixth Agreement Amending NEPOOL (Interruptible/Dispatchable Loads for Objective Capability) dated as of May 3, 2002.
*10.25.17 Eighty-Seventh Agreement Amending NEPOOL (Financial Assurance Policies and Billing Procedures) dated as of June 21, 2002.
*10.25.18 Eighty-Eighth Agreement Amending NEPOOL (Schedule 16 Amendment) dated as of October 4, 2002).
*10.25.19 Eighty-Ninth Agreement Amending NEPOOL (Technical Committee Voting Changes) dated as of October 4, 2002.
*10.25.20 Ninetieth Agreement Amending NEPOOL (Excess Financial Assurance) dated as of October 4, 2002.
*10.25.21 Ninety-First Agreement Amending NEPOOL (Demand Response Provider Changes) dated as of November 1, 2002.
*10.25.22 Ninety-Second Agreement Amending NEPOOL (NEPOOL SMD - Conforming RNA Changes) dated as of November 1, 2002.
*10.25.23 Ninety Third Agreement Amending NEPOOL (NEPOOL SMD - Conforming Tariff Charges) dated as of November 1, 2002.
10.26 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.)
10.27 Lease dated as of April 14, 1992 between RRR and NUSCO with respect to the Berlin, Connecticut headquarters (office lease). (Exhibit 10.29, 1992 NU Form 10-K, File No. 1-5324)
10.27.1 Lease dated as of April 14, 1992 between RRR and NUSCO with respect to the Berlin, Connecticut headquarters (project lease). (Exhibit 10.29.1, 1992 NU Form 10-K, File No. 1-5324)
10.28 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.)
10.29 Note Agreement dated April 14, 1992, by and between 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)
10.29.1 Amendment to Note Agreement, dated September 26, 1997. (Exhibit 10.31.1, 1997 NU Form 10-K, File No. 1-5324)
10.29.2 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)
10.29.2.1 Extension of Note Guaranty, dated September 26, 1997. (Exhibit 10.31.2.1, 1997 NU Form 10-K, File No. 1-5324)
10.29.3 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, 1997 NU Form 10-K, File No. 1-5324)
10.29.3.1 Modification of and Confirmation of Assignment of Leases, Rents and Profits, Security Agreement and Negative Pledge, dated as of September 26, 1997. (Exhibit 10.31.3.1, 1997 NU Form 10-K, File No. 1-5324)
10.29.4 Purchase and Sale Agreement, dated July 28, 1997 by and between RRR and the Sellers and Purchasers named therein. (Exhibit 10.31.4, 1997 NU Form 10-K, File No. 1-5324)
10.29.5 Purchase and Sale Agreement, dated September 26, 1997 by and between RRR and the Purchaser named therein. (Exhibit 10.31.5, 1992 NU Form 10-K, File No. 1-5324)
10.30 NU Executive Incentive Plan, effective as of January 1, 1991. (Exhibit 10.44, NU 1991 Form 10-K, File No. 1-5324)
10.31 Northeast Utilities Incentive Plan, effective as of January 1, 1998. (Exhibit 10.35.1, 1998 NU Form 10-K, File No. 1-5324)
10.31.1 Amendment to Northeast Utilities Incentive Plan, effective as of February 23, 1999. (Exhibit 10.35.1.1, 1998 NU Form 10-K, File No. 1-5324)
10.32 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)
10.32.1 Amendment 1 to Supplemental Executive Retirement Plan, effective as of August 1, 1993. (Exhibit 10.35.1, 1993 NU Form 10-K, File No. 1-5324)
10.32.2 Amendment 2 to Supplemental Executive Retirement Plan, effective as of January 1, 1994.(Exhibit 10.35.2, 1993 NU Form 10-K, File No. 1-5324)
10.32.3 Amendment 3 to Supplemental Executive Retirement Plan, effective as of January 1, 1996. (Exhibit 10.36.3, 1995 NU Form 10-K, File No. 1-5324)
10.32.4 Amendment 4 to Supplemental Executive Retirement Plan, effective as of February 26, 2002. (Exhibit 10.35.4, 2001 NU Form 10-K, File No. 1-5324)
10.32.5 Amendment 5 to Supplemental Executive Retirement Plan, effective as of November 1, 2001. (Exhibit 10.35.5, 2001 NU Form 10-K, File No. 1-5324)
*10.33 Trust under Supplemental Executive Retirement Plan dated May 2, 1994.
10.34 Special Severance Program for Officers of NU system companies, as adopted on July 15, 1998. (Exhibit 10.37, 1998 NU Form 10-K, File No. 1-5324)
10.34.1 Amendment to Special Severance Program, effective as of February 23, 1999. (Exhibit 10.37.1, 1998 NU Form 10-K, File No. 1-5324)
10.34.2 Amendment to Special Severance Program, effective as of September 14, 1999. (Exhibit 10.3, 1999 NU Form 10-Q for the Quarter Ended September 30, 1999, File No. 1-5324)
10.35 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, 1991 NU Form 10-K, File No. 1-5324)
10.35.1 First Amendment to Loan Agreement dated February 7, 1992. (Exhibit 10.36.1, 1993 NU Form 10-K, File No. 1-5324)
10.35.2 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)
10.35.3 Second Amendment to Loan Agreement dated April 9, 1992. (Exhibit 10.36.3, 1993 NU Form 10-K, File No. 1-5324)
10.36 Indenture Mortgage, dated as of October 18, 2001 between NGC and The Bank of New York, as trustee. (Exhibit 4.1 to NGC Registration Statement S-4 dated December 6, 2001, File No. 333-74636)
10.36.1 First Supplemental Indenture Mortgage, dated as of October 18, 2001 between NGC and The Bank of New York, as trustee. (Exhibit 4.2 to NGC Registration Statement S-4 dated December 6, 2001, File No. 333-74636)
10.37 Employment Agreement with Michael G. Morris. (Exhibit 10.39, 1997 NU Form 10-K, File No. 1-5324)
10.37.1 Amendment to Morris Employment Agreement, dated as of February 23, 1999. (Exhibit 10.39.1, 1998 NU Form 10-K, File No. 1-5324)
10.37.2 Amendment to Morris Employment Agreement, dated as of June 28, 2001. (Exhibit 10.41.2 to 2001 NU Form 10-Q for the Quarter Ending September 30, 2001, File No. 1-5324)
10.37.3 Amendment to Morris Employment Agreement, dated as of September 11, 2001. (Exhibit 10.41.3 to 2001 NU Form 10Q for the Quarter Ending September 30, 2001, File No. 1-5324)
10.37.4 Employment Agreement with Michael G. Morris dated as of August 20, 2002. (Exhibit 10.38.4 to 2002 NU Form 10-Q for the Quarter Ending September 30, 2002, File No. 1- 5324)
10.38 Arrangement with Michael G. Morris with Respect to Seabrook. (Exhibit 10.38.4 to 2002 NU Form 10-Q for the Quarter Ending September 30, 2002, File No. 1-5324)
10.39 Arrangement with Michael G. Morris with respect to use of corporate airplane.
10.40 Transition and Retirement Agreement with Bernard M. Fox. (Exhibit 10.39, 1996 NU Form 10-K, File No. 1-5324)
10.41 Employment Agreement with Bruce M. Kenyon. (Exhibit 10.40, 1996 NU Form 10-K, File No. 1-5324)
10.41.1 Amendment to Kenyon Employment Agreement, dated as of January 13, 1998. (Exhibit 10.41.1, 1998 NU Form 10-K, File No. 1-5324)
10.41.2 Amendment to Kenyon Employment Agreement, dated as of February 23, 1999. (Exhibit 10.41.2, 1998 NU Form 10-K, File No. 1-5324)
10.41.3 Amendment to Kenyon Employment Agreement, dated as of May 14, 1999. (Exhibit 10.1, 1999 NU Form 10-Q for the Quarter Ended March 31,1999, File No. 1-5324)
10.41.4 Amendment to Kenyon Employment Agreement, dated as of March 21, 2000. (Exhibit 10.1, 2000 NU Form 10-Q for the Quarter Ended March 31, 2000, File No. 1-5324)
10.41.5 Consulting Agreement with Bruce M. Kenyon, dated as of December 21, 2002.
10.42 Employment Agreement with John H. Forsgren. (Exhibit 10.41, 1996 NU Form 10-K, File No. 1-5324)
10.42.1 Amendment to Forsgren Employment Agreement Exhibit 10.43, dated as of January 13, 1998. (Exhibit 10.42.1, 1998 NU Form 10-K, File No. 1-5324)
10.42.2 Amendment to Forsgren Employment Agreement, dated as of February 23, 1999. (Exhibit 10.42.2, 1998 NU Form 10-K, File No. 1-5324)
10.42.3 Amendment to Forsgren Employment Agreement, dated as of May 10, 1999. (Exhibit 10.1, 1999 NU Form 10-Q for the Quarter Ended March 31, 1999, File No. 1-5324)
10.42.4 Amendment to Forsgren Employment Agreement, dated as of September 14, 1999. (Exhibit 10.4, 1999 NU Form 10-Q for the Quarter Ended September 30, 1999, File No. 1-5324)
10.42.5 Amendment to Forsgren Employment Agreement, dated as of September 19, 2001. (Exhibit 10.44.7 to 2001 NU Form 10-Q for the Quarter Ending September 30, 2001, File No. 1-5324).
10.43 Supplemental Retirement Benefit with John H. Forsgren, dated as of August 8, 2001. (Exhibit 10.44.5, 2001 NU Form 10-Q for Quarter Ended September 30, 2001, File No. 1-5324)
10.44 Supplemental Compensation Arrangement with John J. Forsgren, dated as of September 5, 2001. (Exhibit 10.44.6, 2001 NU Form 10-Q for Quarter Ended September 30, 2001, File No. 1-5324).
10.45 Employment Agreement with Cheryl W. Grise. (Exhibit 10.44, 1998 NU Form 10-K, File No. 1-5324)
10.45.1 Amendment to Grise Employment Agreement, dated as of January 13, 1998. (Exhibit 10.44.1, 1998 NU Form 10-K, File No. 1-5324)
10.45.2 Amendment to Grise Employment Agreement, dated as of February 23, 1999. (Exhibit 10.44.2, 1998 NU Form 10-K, File No. 1-5324)
10.45.3 Amendment to Grise Employment Agreement, dated as of September 14, 1999. (Exhibit 10.5, 1999 NU Form 10-Q for the Quarter Ended September 30, 1999, File No. 1-5324)
10.45.4 Amendment to Grise Employment Agreement dated as of September 19, 2001. (Exhibit 10.46.5 to 2001 NU Form 10-Q for the Quarter Ending September 30, 2001, File No. 1-5324)
10.45.5 Supplemental Compensation Arrangement with Cheryl W. Grise, dated as of September 17, 2001. (Exhibit 10.46.4, 2001 NU Form 10-Q for Quarter Ended September 30, 2001, File No. 1-5324)
10.46 Agreement with Gary D. Simon dated March 16, 1998. (Exhibit 10.45, 2001 NU Form 10-K, File No. 1-5324)
10.47 Employment Agreement with Charles W. Shivery, dated as of June 1, 2002. (Exhibit 10.64 to NU Form 10-Q for the quarter ended June 30, 2002, File No. 1-5324)
10.48 Northeast Utilities Deferred Compensation Plan for Trustees, Amended and Restated December 13, 1994. (Exhibit 10.39, 1995 NU Form 10-K, File No. 1-5324)
10.48.1 Amendment to Deferred Compensation Plan, effective November 5, 2001. (Exhibit 10.46.1, 2001 NU Form 10-K, File No. 1-5324)
10.49 Deferred Compensation Plan for Officers of Northeast Utilities System Companies adopted September 23, 1986. (Exhibit 10.40, 1995 NU Form 10-K, File No. 1-5324)
10.50 Northeast Utilities Deferred Compensation Plan for Executives, adopted January 13, 1998. (Exhibit A.5, File No. 70-09185)
10.51 Reciprocal Support Agreement Among NNECO, NAESCO, CYAPC, YAEC and NUSCO dated January 1, 1996. (Exhibit 10.41, 1995 NU Form 10-K, File No. 1-5324)
10.52 Indenture of Mortgage and Deed of Trust dated July 1, 1989 between Yankee Gas and the Connecticut National Bank, as Trustee (Exhibit 4.7, 1990 YES Form 10-K, File No. 0-10721)
10.53 Power Purchase and Sales Agreement, dated December 27, 1999 between NGC and Select Energy (Exhibit 10.1 to NGC Registration Statement S-4 dated December 6, 2001)
10.53.1 Consent and Agreement, dated as of October 18, 2001, among NU, Select Energy, The Bank of New York, as trustee and NGC, dated as of October 18, 2001 between NGC. (Exhibit 10.3 to NGC Registration Statement on Form S-4 dated December 6, 2001)
10.53.2 Security Agreement, dated as of October 18, 2001, between NGC and The Bank of New York, as trustee. (Exhibit 10.4 to NGC Registration Statement on Form S-4 dated December 6, 2001)
10.53.3 Form of Mortgage, Assignment of Leases and Rents, Security Agreement and Fixture Filing, dated as of October 18, 2001, by NGC in favor of The Bank of New York, as Trustee. (Exhibit 10.5 to NGC Registration Statement on Form S-4 dated December 6, 2001)
10.54 CL&P Transition Property Purchase and Sale Agreement dated as of March 30, 2001. (Exhibit 10.55, 2001 CL&P Form 10-K, File No. 0- 11419)
10.55 CL&P Transition Property Servicing Agreement dated as of March 30, 2001. (Exhibit 10.56, 2001 NU Form 10-K, File No. 1-5324)
10.56 PSNH Purchase and Sale Agreement with PSNH Funding LLC dated as of April 25, 2001. (Exhibit 10.57, 2001 NU Form 10-K, File No. 1- 5324)
10.57 PSNH Servicing Agreement with PSNH Funding LLC dated as of April 25, 2001. (Exhibit 10.58, 2001 NU Form 10-K, File No. 1- 5324)
10.58 PSNH Purchase and Sale Agreement with PSNH Funding LLC2 dated as of January 30, 2002. (Exhibit 10.59 2001 NU Form 10-K, File No. 1- 5324)
10.59 PSNH Servicing Agreement with PSNH Funding LLC2 dated as of January 30, 2002. (Exhibit 10.60, 2001 NU Form 10-K, File No. 1- 5324)
10.60 WMECO Transition Property Purchase and Sale Agreement dated as of May 17, 2001. (Exhibit 10.61, 2001 NU Form 10-K, File No. 1-5324)
10.61 WMECO Transition Property Servicing Agreement dated as of May 17, 2001. (Exhibit 10.62, 2001 NU Form 10-K, File No. 1-5324)
12 Ratio of Earnings to Fixed Charges
13 Annual Report to Security Holders (Each of the Annual Reports is filed only with the Form 10-K of that respective registrant.)
13.1 Portions of the Annual Report to Shareholders of NU (pages 15 to 64) 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.
*21 Subsidiaries of the Registrant.
99.1 Certification of Michael G. Morris, Chairman, President and Chief Executive Officer of Northeast Utilities and John H. Forsgren, Vice Chairman, Executive Vice President and Chief Financial Officer of Northeast Utilities, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated March 21, 2003
#99.2 Certification of Cheryl W. Grise, Chief Executive Officer of CL&P and John H. Forsgren, Executive Vice President and Chief Financial Officer of CL&P, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated March 21, 2003
@99.3 Certification of Cheryl W. Grise, Chief Executive Officer of PSNH and John H. Forsgren, Executive Vice President and Chief Financial Officer of PSNH, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated March 21, 2003
**99.4 Certification of Cheryl W. Grise, Chief Executive Officer of WMECO and John H. Forsgren, Executive Vice President and Chief Financial Officer of WMECO, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated March 21, 2003