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 420 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 192,000 residential, commercial and industrial customers in 71 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.), Mode 1 Communications, Inc. (Mode 1) and Woods Network Services, Inc. (Woods Network). Holyoke Water Power Company (HWP), a subsidiary of NU, is a resource of NUEI through an output contract with Select Energy. For information regarding the activities of these subsidiaries, see "Competitive System Businesses."
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, 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. In 2002, a four-year process of selling the regulated generating assets of CL&P and WMECO was completed. CL&P and WMECO have divested all of their generation assets and are now acting as transmission and distribution companies. CL&P, PSNH and WMECO have divested all ownership of nuclear generation. The mandate for divestiture of PSNH's fossil and hydro generation has been markedly changed by state statute enacted during 2003. PSNH may not divest its assets until April 2006 at the earliest; thereafter, divestiture may occur only if the NHPUC determines that such divestiture is in the economic interest of retail customers of PSNH.
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. CL&P, PSNH and WMECO have received regulatory orders allowing each to recover all or substantially all of their 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 the costs of securitization through rates. As of December 31, 2003, CL&P had fully recovered all stranded costs except those being recovered through RRB-related charges, ongoing independent power producer 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.
All electric operating company customers are now able to choose their energy suppliers, with the electric companies furnishing "standard offer," "default" or "transition" service to those customers who do not choose a competitive supplier. 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 competitive 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 Connecticut, Massachusetts and New Hampshire will permit timely recovery.
In accordance with amendments passed in 2003 to Connecticut's electric restructuring legislation, CL&P signed fixed-price contracts with five wholesale suppliers who together will serve all of CL&P's transitional standard offer (TSO) requirements in 2004. CL&P's obligation to provide "standard offer service" to its customers ended on December 31, 2003, but under the 2003 amendments, an equivalent obligation to provide TSO began on January 1, 2004. One of these suppliers is the company's competitive marketing affiliate, Select Energy. The other four suppliers are unaffiliated with CL&P. CL&P is fully recovering all of the payments it is making to those suppliers and has financial guarantees from each supplier to shield CL&P from risk in the event any of the suppliers encounters financial difficulties. CL&P has filled a portion of its TSO requirements for 2005 and 2006, and will initiate a new solicitation process in the future to procure generation supply for the unfilled portion of its TSO load obligation for those years. See "Connecticut Rates and Restructuring."
After a competitive solicitation, WMECO signed supply agreements for standard offer service in October 2003 for the period January 1, 2004 through February 28, 2005 (the transition period in which standard offer service is to be available terminates on February 28, 2005). Select Energy was one of two winning bidders; the second was an unaffiliated supplier. 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. Pursuant to a DTE order issued in 2003, there are now two separate solicitations for default service. For larger customers, WMECO default service rates are set for a three-month period. For smaller customers, WMECO default service rates are set for a six-month period. Accordingly, default service has been solicited and rates approved for larger customers for the period January 1, 2004 through March 31, 2004. A single unaffiliated entity is the supplier. Default service has been solicited and rates have been approved for smaller customers for the period January 1, 2004 through June 30, 2004. Two unaffiliated entities will provide this service. WMECO will solicit default service for the remainder of calendar 2004 at appropriate times.
Retail competition for all PSNH customers began on May 1, 2001. PSNH provides transition service (TS) energy to its retail customers from its generating plants, from power purchased under long-term contracts and from open market purchases. PSNH reconciles its cost and rate recovery in its annual stranded cost recovery case. See "New Hampshire Rates and Restructuring."
CONNECTICUT RATES AND RESTRUCTURING
Since retail competition began in Connecticut in 2000, most of CL&P's customers have chosen to buy their power from CL&P at standard offer rates and only a small number of CL&P customers (nearly 25,000 out of 1.2 million) have opted for a competitive retail supplier. Through December 2003, 50 percent of CL&P's standard offer supply requirements were purchased from Select Energy, 45 percent from NRG Power Marketing, Inc. (NRG-PMI), and 5 percent from Duke Energy.
On June 25, 2003, Public Act 03-135, An Act Concerning Revisions To The Electric Restructuring Legislation (Act) became law. The Act, among other things: (i) approved a three-year TSO service to replace CL&P's standard offer service, which was set to expire on December 31, 2003; (ii) directed CL&P to file a rate case on or before January 1, 2004, including a four-year plan to provide electric distribution and transmission services; (iii) authorized CL&P to recover from customers its Federally Mandated Congestion Costs (FMCCs), which are essentially costs resulting from the FERC-approved Standard Market Design (SMD) for the New England electricity market and other wholesale power market costs administered by ISO New England Inc. under rules approved by the FERC; and (iv) authorized CL&P's total TSO rate to be up to 11.1 percent higher than the company's standard offer rates (Rate Cap), but clarified that certain costs, including FMCCs and costs recovered under CL&P's Energy Adjustment Clause (EAC), are exempt from the Rate Cap. In addition, the Act also authorizes CL&P to recover a fixed fee of five-tenths of one mill per kilowatt hour for power supplied under the company's TSO load obligation. The Act potentially allows CL&P to earn an additional incentive fee of one-quarter of one mill per kilowatt hour if the DPUC concludes that CL&P's actual TSO power supply contract prices fall below a price threshold as specified in the Act.
In furtherance of the Act, on July 1, 2003, CL&P filed with the DPUC an application to establish its three-year TSO rates. On December 19, 2003, the DPUC issued a final decision that set CL&P's TSO rates for January 1 through December 31, 2004, approved the critical elements of CL&P's proposal and confirmed that the Act exempted FMCCs, EAC charges and certain other costs from the Rate Cap. The total base rate change from 2003 to 2004 is an increase of 7.1 percent. The DPUC could not set CL&P's total TSO rates for 2005 and 2006 because CL&P has not yet procured all of the power supply necessary to satisfy its TSO load obligation for those years. The Connecticut Office of Consumer Counsel (OCC) filed multiple appeals of this decision with the Connecticut Superior Court during February 2004. The OCC claims that the decision improperly implements an energy adjustment charge under Connecticut law, fails to properly define and identify the fees that CL&P will be allowed to collect from customers and improperly calculates base rates for purposes of determining the Rate Cap.
Also in furtherance of the Act, on August 1, 2003, CL&P filed an application with the DPUC to set the distribution and transmission components of its retail rates. The final decision, issued December 17, 2003 and effective January 1, 2004, authorized rate recovery of approximately $900 million over four years for its distribution capital program; approved incremental distribution rate increases totaling approximately $42.1 million between January 1, 2004 and December 31, 2007; applied $120 million of prior year Generation Service Charge overcollections as credits against the authorized rate increases in the amount of $30 million per year; authorized a transmission rate increase of $28.4 million for 2004 with the understanding that CL&P could seek DPUC approval to reflect any future transmission-related revenue requirement increases in rates; and approved a return on equity (ROE) of 9.85 percent with earnings above that level to be shared 50/50 between customers and shareholders. These rates are included in CL&P's total TSO rates. On December 31, 2003, CL&P filed a petition for reconsideration (Petition) of the DPUC's final decision on the grounds that the final decision improperly (i) disallowed $15.73 million of CL&P's pension-related costs, (ii) concluded that the Connecticut statute of limitations does not apply to claims alleging that the Company over-billed municipalities for streetlighting costs, and (iii) failed to implement additional revenue requirement adjustments equal to approximately $5.27 million, $3.57 million, $4.04 million and $4.08 million in 2004-2007, respectively. On January 21, 2004, the DPUC reopened the CL&P rate case for the limited purpose of reconsidering the issues raised in CL&P's petition. On January 30, 2004, CL&P initiated an appeal of the December 17 decision on the issues of pension-related costs and streetlight over-billings, as a precaution in the event the DPUC does not act favorably on these issues in CL&P's reconsideration petition. There is conflicting law in Connecticut with respect to whether the initial agency decision or the decision after reconsideration is the one from which the appeal must be taken.
In light of the deteriorating financial condition of NRG Energy, Inc., (NRG), the parent company of NRG-PMI, one of CL&P's standard offer suppliers through 2003, CL&P exercised its contractual right to withhold past due congestion costs from the August 5, 2002 standard offer payment to NRG-PMI 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-PMI were similarly reduced to reflect continued withholding of congestion costs.
On May 14, 2003, NRG and 25 affiliates, including NRG-PMI, filed for Chapter 11 bankruptcy protection in the U.S. Bankruptcy Court in the Southern District of New York (Bankruptcy Court). NRG's May 14 filing included a request by NRG-PMI to terminate service to CL&P under its standard offer supply agreement (SOS Agreement). In an effort to prevent NRG-PMI from ceasing to perform its obligations under the SOS Agreement, CL&P participated in proceedings before the FERC, the Bankruptcy Court, the United States District Court for the Southern District of New York, the Second Circuit Court of Appeals and the D.C. Circuit Court of Appeals. On June 2, 2003, the Bankruptcy Court issued an order permitting NRG-PMI to reject the SOS Agreement, but the FERC issued orders on June 25, 2003 and August 15, 2003 directing NRG-PMI to continue to perform under the agreement. Subsequent efforts by NRG-PMI to overturn the FERC order and terminate the SOS Agreement were unsuccessful. On November 4, 2003, CL&P, the Connecticut Attorney General, the DPUC and the Connecticut Office of Consumer Counsel entered into a settlement agreement with NRG-PMI and NRG's Official Committee of Unsecured Creditors that required NRG- PMI to perform its obligations for the remainder of the term of the SOS Agreement with no change in price or terms, in exchange for a commitment by CL&P to make payments for services rendered on a revised schedule. The settlement also provided for an exchange of releases between the parties of all claims associated with the litigation to terminate the SOS Agreement and required NRG-PMI to bear responsibility for replacement power costs incurred by CL&P during a 20-day period after the initial Bankruptcy Court order during which NRG-PMI ceased performing. CL&P's pending litigation with NRG regarding pre-SMD congestion costs, post-SMD locational marginal pricing (LMP) costs and station service were not affected by the settlement. On November 21, 2003, the Bankruptcy Court approved the settlement and the FERC approved the settlement on December 18, 2003.
In October 2002, CL&P filed a complaint at the 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). By order dated December 20, 2002, the FERC 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 subsequently made a demand upon NRG for payment of $13.3 million in station service charges through January 2003 and initiated a proceeding at the DPUC seeking a declaratory ruling that its DPUC approved rates were appropriately charged to NRG. Prior to a DPUC ruling, NRG filed a petition for relief under Chapter 11 of the U.S. Bankruptcy Code. On September 18, 2003, the Bankruptcy Court approved a stipulation between CL&P and NRG to submit the station service dispute to arbitration. As part of the CL&P rate case decision dated December 17, 2003, the DPUC determined that CL&P had appropriately administered its station service rates. Subsequently, however, in unrelated proceedings, the FERC issued a series of orders with conflicting policy direction which call into question its December 20, 2003 NRG order. In July 2004, CL&P filed a request with the FERC for further clarification of this issue. Arbitration proceedings have been initiated by the parties, but no hearing dates have been scheduled. For further information relating to NRG-related litigation, see Item 3, "Legal Proceedings."
On March 1, 2003, New England independent system operator (ISO-NE) implemented SMD. As part of this effort, LMP is utilized to assign value and causation to transmission congestion and losses. Transmission congestion and losses costs are assigned to the load zone in which the congestion and losses occur. Prior to March 1, 2003, those costs were spread across virtually all New England electric customers. In addition, the implementation of SMD has impacted wholesale energy contracts with respect to the energy delivery points contained in these contracts. See "Competitive System Businesses - Retail and Wholesale Marketing."
Connecticut has been designated a single load zone by ISO-NE. Due to transmission constraints and inadequate generation, Connecticut has experienced significant additional congestion costs and losses under SMD. In 2003, congestion and losses under SMD associated with CL&P's standard offer load totaled approximately $186 million. CL&P asserted that under the terms of its 2000-2003 standard offer service contracts with its standard offer suppliers, those costs were the responsibility of its customers, and initiated a proceeding at the DPUC to collect these costs from customers. On May 1, 2003, as supplemented by a second interim decision dated June 30, 2003, the DPUC issued an interim decision allowing CL&P to collect these costs subject to refund, but directing CL&P to commence litigation at the FERC seeking a determination that the standard offer suppliers are responsible for such costs. CL&P initiated the FERC proceeding on May 27, 2003, and the case included two of the suppliers, the DPUC, the Connecticut Attorney General and Office of Consumer Counsel, among others. CL&P subsequently received permission from the Bankruptcy Court to include its third supplier, NRG-PMI, in the FERC proceeding. Following six days of hearings, the parties initiated settlement discussions. The settlement, which allocates 55.6 percent of SMD costs to suppliers and 44.4 percent of costs to customers, was filed with the FERC on March 3, 2004 and is expected to be approved by the FERC in the first half of 2004.
Another factor dampening the level of congestion costs is the designation of certain Connecticut generating units by ISO-NE as units needed for system reliability. During 2003, some of these generating units were found to be "reliability must run" (RMR) units by ISO-NE and, as a result, the FERC allowed the favorable financial treatment. This treatment varied as two of the units received total cost-of-service based payments while a majority of the units only received payments to cover specific maintenance and major repair costs. The units receiving the specific maintenance and repair costs also received benefits from a relaxed form of bid mitigation created by the FERC consisting of a peaking unit safe harbor (PUSH) bid limit, intended to allow applicants to recover their fixed costs in the energy market. Currently all of these existing RMR and PUSH applicants are again before the FERC seeking an extension for their treatment. The RMR contracts have been requested for extension at or near the current rates whereas the PUSH applicants have once again requested full fixed cost recovery methodology allowed in combination with the PUSH methodology. Any cost increase that may result from these current applications would be captured in rates to customers through the federally mandated congestion charge line item on customers' bills.
For further information on SMD and transmission-related issues, see "Regulated Electric Operations - Transmission Access and FERC Regulatory Charges."
On May 17, 2002, CL&P filed an application with the DPUC for approval of the auction results in the sale of Seabrook, a nuclear power plant located in Seabrook, New Hampshire, to the FPL Group, Inc. CL&P was a 4.06 percent owner of Seabrook prior to its sale in 2002. A final decision approving the sale was issued in September 2002 and the sale closed on November 1, 2002. On May 1, 2003, CL&P filed its application for approval of the disposition of proceeds from the sale. The application described and requested DPUC approval for CL&P's treatment of its share of the proceeds from the sale, including CL&P's proposal that $13 million of its $37.2 million (gross) share of the sale proceeds be used to mitigate stranded costs. On March 3, 2004, the DPUC issued a final decision that approved CL&P's application, with the exception that net proceeds of approximately $0.7 million after taxes from the sale of Seabrook Unit 2, which CL&P sought to retain, be applied to stranded costs.
On September 9, 2003, the Connecticut Siting Council (CSC) issued a final decision approving CL&P's proposed $200 million project to build a new 345,000- volt transmission line between Bethel and Norwalk, Connecticut. The decision has been appealed and CL&P has moved for dismissal. A ruling on CL&P's motion is expected in 2004. On October 9, 2003, CL&P filed an application with the CSC for approval to build a 69-mile, 345,000-volt line between Norwalk and Middletown, Connecticut. Public comment sessions on this project concluded in February 2004. Evidentiary hearings will be held in March, April and May, 2004. The two projects are needed to relieve transmission constraints 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 Program."
On August 1, 2002, Yankee Gas filed testimony and exhibits with the DPUC reflecting its proposal for its capital investment ratemaking recovery mechanism (Infrastructure Expansion Rate Mechanism or IERM) and the projects that met certain DPUC defined financial criteria and were expected to be placed in service before December 31, 2003.
Yankee Gas proposed no IERM charge for 2003 and that any over-collection for 2003 be carried forward to the 2004 IERM period. A decision was issued on June 25, 2003 and the DPUC concluded that 10 projects met its IERM requirements, but that all or portions of 12 projects did not meet the relevant criteria. In addition, the DPUC ordered Yankee Gas to refund to customers the estimated over-collection over the three-month period of December 2003 through February 2004. On October 1, 2003, Yankee Gas filed its 2003-2004 IERM application, but on November 20, 2003, the DPUC notified Yankee Gas that the filing was found to be deficient. Yankee Gas filed a motion on December 3, 2003 requesting the DPUC to reconsider its November 20, 2003 letter and on January 12, 2004, the DPUC granted the motion and indicated that it will review Yankee Gas' October 1, 2003 compliance filing and specifically approve it or explain why the DPUC believes the filing does not comply with the DPUC's June 25, 2003 decision. On February 5, 2004, the DPUC permitted Yankee Gas to include projects filed in 2003 provided customers are insulated from any financial shortfall below a 10 percent internal rate of return. The DPUC also stated that if a project did not initially meet a specified financial test, that project will not be allowed as an IERM project. Yankee Gas is currently evaluating the impact of the DPUC clarification. By letter dated February 5, 2004, the DPUC provided clarification of Yankee Gas' December 3, 2003 motion for reconsideration. The DPUC directed Yankee Gas to refile its compliance filing based on the clarification provided in its February 5, 2004 letter; Yankee Gas made this filing on February 27, 2004. No procedural schedule has been set by the DPUC at this time.
Yankee Gas sought rate approval from the DPUC to build a two billion cubic foot liquefied natural gas (LNG) production and storage facility in Waterbury, Connecticut, at an estimated cost of $60 million. On November 12, 2003, the DPUC issued a decision supportive of a 1.2 billion cubic foot LNG facility and authorized Yankee to proceed with issuing a request for proposals (RFP). The DPUC will review the results of the RFP before its final ruling.
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 was dismissed without prejudice by the Supreme Judicial Court in 2001 because the appellant has failed to prosecute the appeal. The second appeal was dismissed on May 27, 2003.
In December 2003, the DTE approved WMECO's proposal to maintain its total overall rates at the 2003 level. See "Rates and Electric Industry Restructuring-General" for information relating to WMECO's standard offer service and default service supply.
On March 31, 2003, WMECO filed its fourth annual stranded cost reconciliation with the DTE for calendar year 2002. This filing was subsequently updated on September 22, 2003. Hearings are scheduled in the matter in the first quarter of 2004.
NEW HAMPSHIRE RATES AND RESTRUCTURING
On January 1, 2004, PSNH acquired 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. PSNH paid CVEC approximately $9 million for its assets and an additional $21 million for intangibles related to termination of a wholesale power contract between CVPS and CVEC. Upon closing, customers of CVEC became customers of PSNH. PSNH will be allowed to recover the $21 million payment with a return consistent with Part 3 stranded cost treatment under the "Agreement to Settle PSNH Restructuring" (Restructuring Settlement). Part 3 stranded costs are non-securitized regulatory assets which must be recovered by a recovery end date determined in accordance with the April 2000 Restructuring Settlement or be written off.
On February 1, 2004, in accordance with New Hampshire law, PSNH raised the TS rate for all retail customers to 5.36 cents per kilowatt-hour (kWh) from 4.60 cents per kWh for residential and small commercial customers and 4.67 cents per kWh for large commercial and industrial customers. PSNH expects those rates to be adequate to recover its generation and purchased power costs, including the recovery of carrying costs on PSNH's generation investment. If recoveries exceed PSNH's costs, the difference will be credited against PSNH's Part 3 stranded cost balance. Part 3 stranded costs are non-securitized regulatory assets which must be recovered by a recovery end date determined in accordance with the Restructuring Settlement or be written off. If actual costs exceed those recoveries, PSNH will defer those costs for future recovery from customers through its Stranded Cost Recovery Charge. PSNH's TS rate may be updated on August 1, 2004 through an interim review ordered by the NHPUC.
PSNH's delivery rates were fixed until February 1, 2004. Pursuant to the Restructuring Settlement and New Hampshire statute, PSNH filed a delivery service rate case on December 29, 2003. PSNH requested a rate increase of $21.4 million (2.6 percent). PSNH also requested annual recovery of the FERC regulated transmission costs through a Transmission Cost Adjustment Mechanism. On December 31, 2003, the NHPUC suspended the new rates subject to hearings. Hearings are scheduled for August 2004; a decision is expected early in the fourth quarter of 2004 with rates retroactively applied to February 1, 2004.
COMPETITIVE SYSTEM BUSINESSES
NU is engaged in a variety of competitive businesses, primarily the retail and wholesale 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.
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 provides high-voltage electrical contracting services, and Select Energy, a corporation engaged in the marketing, transportation, storage and sale of energy commodities, at wholesale and retail, in designated geographical areas. The generation operations of HWP are also included in the results of NUEI. NUEI and its integrated competitive energy business affiliates had aggregate revenues of approximately $2.6 billion in 2003 as compared to approximately $1.8 billion in 2002 and had losses of $3.5 million in 2003 (which includes a fourth quarter after-tax write-off of approximately $36 million associated with the settlement of costs related to a contract between Select Energy and CL&P (SMD settlement)), as compared to a loss of approximately $53.2 million in 2002. For further information on the SMD settlement, see "Rates and Electric Industry Restructuring - Connecticut Rates and Restructuring."
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 sells all its generation output to Select Energy, which in turn markets it to customers. Select Energy also buys and manages the entire generation output of HWP, which consists of approximately 147 megawatts (MW) of coal-fired generation at the Mt. Tom station in Holyoke, Massachusetts under an evergreen contract. 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.
During 2004, NU expects that NUEI will produce net income in the range of $28 million to $38 million, or $0.22 to $0.30 per share. Management estimates that between $24 million and $31 million of those earnings in 2004 will come from the merchant energy business and between $4 million and $7 million form the energy services business. Those ranges are heavily dependent on NUEI's ability to achieve targeted wholesale and retail origination margins, successfully manage its contract portfolio and achieve targeted growth in the services business.
RETAIL AND WHOLESALE 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 1,293 MW for a six-year period. The contract was extended for one year, through December 2006, in December 2003. In addition, during 2003 Select Energy purchased approximately 147 MW of coal generating plant output from its affiliate, HWP, and more than 3,583 MW of electrical supply from various New England generating facilities on a long-term basis to meet its New England load obligations. Select Energy utilizes 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 2003, Select Energy reported revenues of $2.3 billion and had retail and wholesale marketing sales of approximately 40,000 gigawatt-hours (GWh) of electricity and 46 billion cubic feet (BcF) of natural gas to approximately 26,000 customers. During 2002, Select Energy reported revenues of $1.6 billion and had retail and wholesale marketing sales of approximately 26,000 GWh of electricity and 52 BcF of natural gas to approximately 19,000 customers.
There are a number of large energy companies bidding for business in the restructured Northeast market. During 2003, the breadth and depth of the market for energy trading and marketing products in Select Energy's market continued to be 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 2004.
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 has created both challenges and opportunities for Select Energy. The impact of SMD on the wholesale marketing business has been significant. As the market continues to evolve, 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."
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 55 gas distribution companies to provide retail services.
Select Energy's retail marketing business had a $25.9 million improvement in performance during 2003 compared to 2002, with losses of $1.8 million and $27.7 million, respectively. The stronger performance is attributed to increased electric sales and better delivery margins from both electric and gas commodity sales. Select Energy expects its retail marketing business to be modestly profitable in 2004. Changes to the size and operational scope of the retail organization implemented in 2003 are expected to have a continuing impact in 2004. This projection also assumes that Select Energy will be successful in securing and managing a significant amount of new business at acceptable margins.
As of December 31, 2003, Select Energy had contracts with retail electric customers in states throughout the Northeast which produced revenues of approximately $420 million, from over 2,000 MW of peak load at approximately 17,500 locations, including predominately commercial, industrial, institutional and governmental accounts. As over 650 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 accounted for more than ten percent of Select Energy's retail revenues.
During 2003, Select Energy's competitive natural gas business, primarily retail in nature, produced revenues of approximately $285 million, an increase from 2002 revenues of approximately $247 million. This increase was primarily due to changes in gas prices. As of December 31, 2003, Select Energy provided over 37 BcF of natural gas to approximately 8,300 retail gas customers, primarily located in Connecticut, Massachusetts, New York and Pennsylvania. These contracts generally have one-year terms and include primarily commercial, institutional, industrial and governmental accounts. No single retail gas customer accounted for more than ten percent of Select Energy's retail gas revenues. In 2003, Select Energy's retail gas revenues were approximately $228 million, representing approximately a 27 percent increase compared to 2002.
Wholesale Marketing
Select Energy's goal is to be the regional leader in providing electric service to the Northeastern competitive markets. In 2003, Select Energy supplied more than 6,100 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 56 percent of Select Energy's 2003 revenues.
During 2003, the wholesale marketing business line earned $31.8 million (before the SMD settlement write-off) versus a loss of $24.7 million in 2002 (including a $24.3 million loss in the trading business line).
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 equated to approximately 2,500 MW annually for each of the four contract years. Approximately 23 percent of Select Energy's 2003 competitive energy revenues came from CL&P's supply contract. Above-normal river conditions at NGC's hydroelectric plants, in contrast to the near-drought conditions New England experienced during much of 2002, also helped to improve 2003 results. In 2004, Select Energy will continue to focus on management of power supply associated with its full requirements contracts. To meet its profit target in 2004, Select Energy must also secure a significant amount of new business at acceptable margins.
In addition to its contract with CL&P, Select served 2,100 MW of New Jersey's basic generation supply (BGS) load through July 31, 2003, and is serving 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 approximately 450 megawatt standard offer load of its affiliate, WMECO, for a 14-month period. Beginning in 2004, Select Energy will serve approximately 1,875 MW of transition standard offer load of its affiliate, CL&P. There are also approximately 350 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.
During 2003, the trading operations were significantly scaled back, reflecting Select Energy's commitment to focus on its marketing business. In this new role, trading activities are now limited primarily to price discovery, risk management and deal execution for merchant energy activities.
ELECTRIC GENERATION
NGC, NU's competitive electric generating affiliate, owns and operates a portfolio of approximately 1,293 MW of hydroelectric and pumped storage generating assets in Connecticut and Massachusetts. 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 (27 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 (65 MW) located in 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 through 2006. Select also buys and manages the entire generation output of approximately 147 MW from HWP's Mt. Tom generating plant under a contract renewable on an annual basis. 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 2006. About 83 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 17 percent of the revenues are in the form of monthly payments at predetermined rates per unit of actual energy output. NGC currently derives approximately 78 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 2006, 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. The merchant energy business enters contracts of varying lengths of time to buy and sell energy commodities, including electricity, natural gas and oil. Market risk represents the loss that may affect Select Energy's financial results due to adverse changes in commodity market prices.
Risk management within Select Energy is organized to address the market, credit and operational exposures arising from its wholesale marketing business (which includes limited energy trading for market and price discovery purposes) and its retail marketing activities. A significant portion of the 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.
In serving its marketing customers, Select Energy utilizes derivative financial and commodity instruments, including options and forward contracts, to manage the risk of fluctuating market prices. At December 31, 2003, Select Energy had hedging derivative assets of $55.8 million, as compared to derivative assets of $22.8 million at December 31, 2002. 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.
Select Energy's trading portfolio had a net positive $32.5 million fair value at December 31, 2003, as compared to a net positive $41 million fair value at December 31, 2002. Approximately 99 percent of the $32.5 million was priced from external sources and only a nominal amount was based on exchange quotes. Of the $32.5 million of net fair value in the trading portfolio at December 31, 2003, $7.1 million will mature in 2004, $9.7 million in 2005-2007 and $15.7 million after 2007.
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 to address the market, credit and operational exposures arising from the company's primary business segments, including wholesale and retail marketing. 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 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 (Boulos)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, a subsidiary of NUEI, is a network products and services company. Both Woods Electrical and Woods Network were acquired in 2002.
NGS provides consulting services to its customers, including due diligence reviews and environmental regulatory compliance and permitting services and laboratory analyses.
During 2003, NGS's revenues were approximately $103 million and are forecasted to grow by approximately 13 percent in 2004. This anticipated growth is expected to be driven by NGS's increased geographical scope and additional contracts with both new and repeat customers. Forty-two percent of NGS's revenues in 2003 were derived from contracts with its affiliates.
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 is under contract to operate and maintain the plants for at least 20 years. In 2003, federal ESPC work constituted 35 percent of SESI's revenues, which were approximately $52.8 million. In 2004, SESI's revenues are anticipated to grow by approximately three percent based on existing backlog and continuing success in its existing business lines.
TELECOMMUNICATIONS
Mode 1 is a wholly owned exempt telecommunications subsidiary of NUEI. Mode 1 is a licensed competitive local exchange carrier authorized to provide local phone service within the state of Connecticut.
At December 31, 2003, NU's net investment in Mode 1 was approximately $14.7 million, most of which was used to fund Mode 1's investment in NEON Communications, Inc. (NEON). NEON is a wholesale provider of high bandwidth, advanced optical networking solutions and services to communications carriers on intercity, regional and metro networks in the twelve-state Northeast and mid-Atlantic markets, utilizing a portion of the NU system companies' and other electric utilities' transmission and distribution facilities. An officer and trustee of NU is a member of the Board of Directors of NEON.
Under NEON's December 2002 plan of reorganization, Mode 1 acquired seven percent of NEON's common stock for approximately $3.2 million. In July 2003, Mode 1 acquired another one percent of NEON's common stock for approximately $1.4 million.
Mode 1 also provides dark fiber service over a high-speed, fiber-optic network within the city of Hartford, Connecticut and serves the City of Hartford's schools and libraries with an optical network.
FINANCING PROGRAM
2003 FINANCINGS
On January 6, 2003, SESI entered into an assignment of delivery order payments (Assignment) with a financing entity, BFL Funding IV LLC (BFL), to repay an existing financing of the installation of certain energy conservation measures at a federal government facility as referred to in the delivery order issued by the federal government. Pursuant to the Assignment, SESI assigned the payments due under the delivery order to BFL. BFL then issued $9.52 million of trust certificates at an interest rate of 5.95 percent that mature in March 2010. Certain obligations of SESI under the transaction documents and the delivery order payments due from the government are backed by an NU parent guaranty of SESI's performance under the delivery order.
On February 10, 2003, SESI entered into another Assignment with BFL to finance the construction and installation of certain energy conservation measures at three federal government facilities, including an expansion of the above-referenced delivery order, as well as two additional orders issued by the federal government. Pursuant to this Assignment, SESI assigned the payments due under the three delivery orders to BFL. BFL then issued $30.41 million of trust certificates at an interest rate of 5.95 percent that mature in March 2018. Certain obligations of SESI under the transaction documents and the delivery order payments due from the government are backed by an NU parent guaranty of SESI's performance under the delivery orders.
On March 31, 2003, SESI entered into an assignment of certain contract payments (Contract Assignment) with a financing entity, PFG Energy Capital (PFG), to finance the construction and installation of energy conservation measures at a municipal facility in Maine. Pursuant to the Contract Assignment, SESI assigned the fixed portion of the monthly contract payments due under the contract between SESI and the municipal facility. PFG paid SESI $1.85 million for the fixed payment stream which ceases in April 2013. The rate of this financing is 8.929 percent.
On June 3, 2003, NU issued $150 million of fixed rate, senior unsecured notes (the Series B Notes) with a coupon of 3.30 percent and a maturity of June 1, 2008. The proceeds were used to refinance approximately $82 million of short-term debt used to finance the competitive businesses under the existing revolving bank credit facility and invest in the competitive subsidiaries to enable them to refinance their respective short-term debt. The Series B Notes are not callable prior to maturity.
On July 9, 2003, CL&P renewed its accounts receivable securitization bank credit line and extended its termination date to July 7, 2004. The credit line capacity remained the same at $100 million.
On September 30, 2003, WMECO issued $55 million of fixed rate, senior unsecured notes (the Series A Notes) with a coupon of 5.00 percent and a maturity of September 1, 2013. The proceeds were used to refinance a portion of WMECO's short-term debt. The Series A Notes are redeemable at any time and permit redemptions upon WMECO making a make-whole payment.
On October 1, 2003, CL&P converted its $62 million 1996 Series A Pollution Control Revenue Bonds (PCRBs) from a weekly interest rate mode to a multi- annual mode and fixed the rate on the bonds at 3.35 percent for the next five years through October 1, 2008.
On November 10, 2003, CL&P, WMECO, PSNH and Yankee Gas entered into a new unsecured 364-day revolving credit facility for $300 million, replacing a similar $300 million facility that was due to expire on November 11, 2003. 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, this credit facility will expire on November 8, 2004.
On November 10, 2003, NU entered into a new unsecured 364-day revolving credit facility for $350 million, replacing a similar $350 million facility that was due to expire on November 11, 2003. 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 under this facility, amounts up to $350 million are available for advances to NU. Second, subject to the advances outstanding, letters of credit may be issued in an aggregate amount of up to $250 million in the name of NU or any of its subsidiaries. Unless extended, the credit facility will expire on November 8, 2004.
On December 10, 2003, SESI entered into an Assignment with a financing entity, Hannie Mae, LLC (Hannie Mae), to finance the construction and installation of energy conservation measures at two governmental facilities. Pursuant to this Assignment, SESI assigned the payments due under two delivery orders to Hannie Mae for approximately $8.794 million and $10.216 million, respectively. The proceeds will be used to fund the construction of energy conservation projects at the facilities. The interest rate applicable to each is 6.23 percent and the amortizing debt will mature in July 2019 and July 2024, respectively. An NU parent guaranty of SESI's performance under the delivery orders is provided.
On December 29, 2003, Boulos, a subsidiary of NGS, entered into a secured bank revolving credit facility which permits borrowings up to a maximum of $6 million at the prime rate. The facility terminates on June 30, 2004 and may be renewed annually thereafter.
NU paid common dividends totaling $73.1 million in 2003, compared to $67.8 million paid in 2002, reflecting increases in the quarterly dividend rate that were effective September 30, 2002 and September 30, 2003. The higher levels of dividends were easily accommodated by rising general liquidity at the NU parent level, due in part to the continued payment of common dividends from the regulated electric subsidiaries 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 ($24 million in 2004 and $26 million in 2005).
Total NU system debt, including short-term and capitalized lease obligations, but not including RRCs and RRBs, was $2.7 billion as of December 31, 2003, compared with $2.4 billion as of December 31, 2002. The increase was primarily due to new debt issuances by NU, WMECO and SESI.
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."
2004 FINANCING REQUIREMENTS
The NU system's aggregate capital requirements for 2004 are approximately as follows:
Yankee NU CL&P PSNH WMECO Gas Other System ---- ---- ----- ------- ----- ------ (Millions)
Construction $447 $191 $36 $62 $ 39 $775 Maturities 0 0 0 0 0 0 Cash Sinking Funds 0 0 0 1 64 65 ---- ---- --- --- ---- ---- Total $447 $191 $36 $63 $103 $840 ==== ==== === === ==== ====
* 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 2004 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."
2004 FINANCING PLANS
NU projects a moderate level of system financings in 2004.
CL&P is contemplating the issuance of up to $250 million of debt, primarily to finance its distribution and transmission businesses and general corporate purposes. See "Financing Program - Construction and Capital Improvement Program."
PSNH is contemplating the issuance of up to $50 million of debt to refinance portions of its existing short-term debt and to finance other planned capital expenditures for 2004. See "Rates and Electric Industry Restructuring - - New Hampshire Rates and Restructuring."
WMECO is contemplating the issuance of up to $52 million of debt to refinance its pre-1983 spent nuclear fuel obligations, subject to receipt of regulatory authority.
Yankee Gas issued $75 million of ten-year unsecured notes on January 30, 2004 at an interest rate of 4.8 percent and used the proceeds to repay short- term debt. Yankee Gas 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. See "Financing Program - Construction and Capital Improvement Program."
SESI is forecasting the issuance of up to $27 million of long-term debt in 2004 to fund government contracts for the construction and installation of energy conservation measures at certain governmental facilities.
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, 2003, CL&P's, WMECO's, PSNH's, and Yankee Gas's leverage ratios were 47 percent, 50 percent, 55 percent and 32 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, 2003, CL&P's, WMECO's, PSNH's and Yankee Gas' interest coverage ratios were 3.34 to 1, 7.16 to 1, 5.67 to 1 and 2.31 to 1, respectively. These ratios do not include RRBs and RRCs and the leverage ratio for Yankee Gas does not exclude goodwill from capitalization.
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 65 percent. At December 31, 2003, NU's leverage ratio was 5.5 percent. In addition, NU is required to maintain a 12-month consolidated interest coverage ratio of at least 2.0 to 1.0. At December 31, 2003, NU's consolidated interest coverage ratio was 2.33 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, North Atlantic Energy Corporation (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). On June 30, 2003, the SEC extended the short-term debt authority for these companies through June 30, 2006 and authorized these companies to participate in the Northeast Utilities System Money Pool (Pool) through June 30, 2004. The order also authorized the participation of the competitive subsidiaries in the Pool through June 30, 2004. 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, 2003, and the amounts of outstanding short-term debt of those companies at the end of 2003 and as of March 1, 2004 (in millions):
Maximum Authorized Outstanding Short-Term Debt Short-Term Debt (1) --------------- ------------------- December 31, 2003 March 1, 2004 ----------------- ------------- NU $400 $ 0 $ 0 CL&P 375 91.1 152.9 PSNH (2) 100 58.9 47.7 WMECO 200 41.4 50.4 Yankee Gas 100 87.5 3.5 Yankee Energy System 50 0 0 NAEC (3) (4) 10 0 0 NNECO (4) 10 0 0 HWP (4) 5 1.4 0 Other (5) N/A 102.7 73.2 ------ ------ Total $383.0 $327.7 ====== ======
(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 $105 million at December 31, 2003 and $40 million at March 1, 2004.
(2) Under applicable NHPUC regulations, PSNH can incur short-term debt up to ten percent of fixed net plant or such other amount as approved by the NHPUC. Pursuant to an order issued by the NHPUC, PSNH can incur short-term debt up to $100 million.
(3) Under applicable NHPUC regulations, NAEC can incur short-term debt up to ten percent of net fixed plant or such other amount as approved by the NHPUC. NAEC has no plans to incur any future short-term borrowings.
(4) As of June 30, 2003, SEC authorization is limited to borrowings through the Pool.
(5) Pursuant to SEC order, the SEC has limited, 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); SESI ($35 million); The Rocky River Realty Company (RRR) ($30 million); NGS ($25 million); Yankee Financial ($10 million); YESCO ($10 million); Quinnehtuk ($10 million); NorConn Properties, Inc. (NorConn) ($10 million); Boulos ($10 million); Woods Electrical ($10 million); and Select Energy New York, Inc. ($10 million). NU, Yankee, Woods Network, 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, 2003, 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 and $150 million in principal amount of 3.30 percent notes in June 2003 contains a limitation on liens on NU assets and a limitation on sale and leaseback transactions involving those assets.
WMECO's debt indenture, under which it issued $55 million in principal amount of 5.00 percent notes in September 2003, contains similar restrictions.
CL&P's charter contains preferred stock provisions restricting the amount of additional unsecured debt it may incur. At shareholders' meetings on November 25 and 26, 2003, CL&P obtained authorization from its preferred stockholders to issue unsecured indebtedness with a maturity of less than ten years in excess of ten percent of capitalization (but not in excess of 20 percent of capitalization) for a ten-year period expiring March 2014. As of December 31, 2003, the amount of additional unsecured debt it could incur was $366 million.
The indenture securing the outstanding first mortgage bonds of CL&P provides that additional bonds may not be issued, except for certain refunding purposes, unless: (1) net earnings during a period of twelve consecutive calendar months during the period of fifteen consecutive calendar months immediately preceding the first day of the month in which the application for additional bonds is made are at least twice the pro forma annual interest charges on outstanding bonds, certain prior lien obligations and bonds to be issued, and (2) CL&P has available property credits equal to 1662/3 percent of the principal amount of bonds to be issued. The indenture also allows CL&P to issue first mortgage bonds equal to the available amount of bonds previously issued but retired. At December 31, 2003, CL&P could not issue any bonds under the interest/property coverage test, but could issue up to approximately $625 million based on available retired bond credits. As of December 31, 2003, CL&P's net earnings were 11.6 times the annual interest charges on its outstanding bonds.
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, 2003, CL&P's income before interest charges was approximately 2.4 times the pro forma annual interest and dividend requirements. CL&P has no current plans to issue any preferred stock.
The indenture securing the outstanding first mortgage bonds of Yankee Gas provides that additional bonds may not be issued unless it meets an interest coverage test similar to that of CL&P as discussed above. As of December 31, 2003, Yankee's net earnings were 2.02 times the annual interest charges on its outstanding bonds.
Boulos has a $6 million line of credit that prohibits the company from incurring additional indebtedness (including borrowings from the NU money pool) from its parent, NGS, or any other affiliate without prior consent of the lender. In addition, the line of credit must be reduced to $0 for 30 consecutive days of each fiscal year.
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, 2003, retained earnings available for the payment of dividends totaled $810 million.
The Federal Power Act and the 1935 Act both limit the payment of dividends by PSNH, NAEC, CL&P and WMECO to retained earnings. At December 31, 2003, retained earnings for these companies were $224 million, $4 million, $317 million and $72 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, and CL&P has utilized $400 million of this authority through share repurchases in 2001 and 2002.
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 impairment to goodwill would be charged to expense. In 2003, no impairment was charged to expense.
NGC's 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 greater than or equal to (a) 1.35 if contracted generating capacity is greater than 75 percent or (b) 1.70 if contracted generating capacity is less than 75 percent. At December 31, 2003, 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 2004.
Boulos' line of credit has a covenant that restricts dividend payments (including any stock repurchase payments and other distributions or cash advances to the direct or indirect holders of Boulos' stock) to no more than 40 percent of its net income. However, Boulos may pay dividends without this restriction as long as no event of default has occurred and is continuing or would result from the payment of dividends, and there are no unpaid and outstanding borrowings at the time of the dividend payment.
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 CL&P, WMECO and PSNH in 2001, these companies obtained SEC consent for their common equity ratios falling below 30 percent through December 31, 2004. As of December 31, 2003, NU's, CL&P's, WMECO's and PSNH's ratios were 34.2 percent, 30.5 percent, 35.0 percent and 29.0 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 and regulated subsidiaries. NU currently has authorization from the SEC to provide up to $500 million of such guarantees for the benefit of its unregulated subsidiaries through June 30, 2004 and has applied for authority to increase this amount to $750 million and extend the authorization period through September 30, 2007. As of December 31, 2003, the amount of guarantees outstanding in compliance with the SEC limit for the unregulated subsidiaries was $288.5 million. NU has also issued indirect guarantees of its regulated companies by issuing guarantees to surety companies. These guarantees for the regulated companies are subject to a separate $50 million SEC limitation apart from the $500 million guarantee limit. As of December 31, 2003, $48.0 million of guarantees were outstanding for the regulated entities of which $31.1 million is related to surety bonds obtained by CL&P to comply with an LMP order issued by the DPUC. As of December 31, 2003, NU had $106.9 million of letters of credit issued for the benefit of the unregulated subsidiaries.
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 $5.3 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 its two senior secured debt series that can be funded with cash, an NU guarantee or a letter of credit (LOC) from an acceptable counterparty. The account may be funded with a guarantee from NU if NU has an investment grade rating by Standard & Poor's and Moody's. While NU does have investment grade ratings, the debt service reserve account is currently funded with cash.
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 could, under its present contracts, be asked to provide approximately $231 million of collateral or letters of credit to various unaffiliated counterparties and approximately $65 million to several independent system operators (ISO) and unaffiliated local distribution companies, which management believes NU would currently be able to provide. NU's credit ratings outlooks are currently stable or negative, but 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 $738 million in 2004. Of such total amount, approximately $440 million is expected to be expended by CL&P, $160 million by PSNH, $60 million by Yankee Gas, $38 million by WMECO and up to $40 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 2004, 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 2004 in light of future developments, such as restructuring, industry consolidation, performance and other events.
The $40 million in construction expenditures planned for other system entities in 2004 includes $22 million for NUEI which is mostly due to forecast expenditures at NGC's Northfield pumped storage facility.
CL&P has announced plans to invest approximately $696 million by the end of 2008 to construct two new 345,000 volt transmission lines from inland Connecticut to Norwalk, Connecticut and another $45 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 approximately $1.35 billion over the 2004 through 2008 timeframe. 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. See "Rates and Electric Industry Restructuring-Connecticut Rates and Restructuring."
Yankee Gas will continue to emphasize system expansion of its natural gas distribution system in Connecticut and has recently received DPUC support for the installation of a 1.2 billion cubic foot liquid natural gas production and storage facility in Waterbury, Connecticut estimated to cost approximately $54 million. Construction on the facility is expected to begin in mid 2004. 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 2003, CL&P provided retail franchise service to approximately 1.2 million customers in Connecticut, PSNH provided retail service to approximately 456,000 customers in New Hampshire and WMECO served approximately 206,000 retail customers in Massachusetts.
The following table shows the sources of 2003 electric franchise retail revenues based on categories of customers (exclusive of HWP):
Total NU CL&P PSNH WMECO System ---- ---- ----- -------- Residential 47% 42% 45% 46% Commercial 39% 38% 36% 39% Industrial 12% 19% 18% 14% 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 2013 for CL&P, PSNH and WMECO are set forth below:
Forecast 2003-2013 2003 over 2002 over Compound Rate 2002 2001 Of Growth --------- --------- ------------- NU System 3.6% 1.3% 1.9% CL&P 3.3% 1.8% 1.7% PSNH 4.7% -0.1% 2.7% WMECO 2.6% 1.9% 1.2%
Consolidated NU retail sales rose by 3.6 percent in 2003, compared with 2002, primarily due to higher heating and cooling requirements and increased residential usage. In addition, an adjustment to estimated unbilled electric sales in September 2003 increased retail sales. Residential electric sales were up 6.5 percent. Commercial sales were up by 2.6 percent for the year and industrial sales decreased by 0.7 percent. Retail sales for CL&P, WMECO and PSNH were up 3.3 percent, 2.6 percent and 4.7 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 the New England Power Pool (NEPOOL) and a more open, competitive market structure. Under these arrangements, ISO-NE, 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 FERC approved a comprehensive settlement of certain issues concerning the NEPOOL transmission tariff. Among other items, the settlement included a ROE component which set the ROEs for each individual transmission provider owning NEPOOL transmission facilities. NU's ROE was set at 11.75 percent as a result of the settlement. On August 26, 2003, NU filed at the FERC amendments to its transmission tariff to change the rate fixed by the comprehensive settlement to a formula rate methodology that is designed to ensure recovery of NU's entire transmission revenue requirement, including those costs that are not recovered through the NEPOOL transmission tariff. NU also requested that the FERC keep in effect the 11.75 ROE until such time as it is superceded by a RTO transmission tariff. On October 22, 2003, the FERC ordered that the new rate filing (and the ROE) would be effective October 28, 2003, subject to refund after the conclusion of settlement negotiations or a hearing on limited issues raised by intervening parties. On January 23, 2004, the FERC concluded that settlement discussions had proven ineffective and remanded the remaining issues for hearing. Hearings are scheduled to commence on August 24, 2004 and a final order is expected during the fourth quarter of 2004.
Transmission revenues are allocated between CL&P, HWP and its wholly- owned subsidiary, Holyoke Power and Electric Company (HP&E), WMECO and PSNH based upon a net revenue requirement allocation methodology.
TRANSMISSION ACCESS AND FERC REGULATORY CHANGES
Pursuant to FERC Order 888 (issued in April 1996) and the NEPOOL Agreement, NU system companies operate their transmission system under a system of two open access, non-discriminatory transmission tariffs (OATTs). The NEPOOL OATT, which is administered by ISO-NE, covers access to and the operation of regional transmission facilities and the NU companies' OATT covers access to and operation of local transmission facilities.
In December 1999, the FERC issued an order calling on all transmission owners to voluntarily join RTOs in order to advance competition in electric markets (Order 2000).
On October 31, 2003, ISO-NE and the New England transmission owners filed a joint application with the FERC to create a New England RTO (RTO-NE). As proposed, RTO-NE would be an independent operator of all New England transmission facilities, and would perform, among other functions, tariff administration, transmission, planning, construction and reliability management for the region's transmission system and the design and administration of regional markets. Transmission owners would retain rights over their revenue requirements and rate design and share certain other rights with RTO-NE, and elements of the NEPOOL transmission tariff and the individual utilities' tariffs will be combined into a single regional tariff. In conjunction with this filing, on November 4, 2003, the New England transmission owners filed with the FERC a proposed base ROE of 12.8 percent for the combined facilities, with a request for additional basis points for joining an RTO and incentives for future transmission expansions. The total requested ROE is 13.3 percent for existing facilities and 14.3 percent for new facilities. Various parties and state regulatory commissions have challenged both the justification for the formation of RTO-NE and the requested ROEs. An order from the FERC is expected by the second quarter of 2004.
In July 2002, the NEPOOL Participants Committee and ISO-NE management jointly proposed a new NEPOOL market rule to implement SMD in New England. SMD adopts 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 New England SMD proposal was approved by the FERC on December 20, 2002 and was implemented on March 1, 2003. Since that time, changes have been made to SMD as a result of subsequent FERC orders and proceedings, particularly with regard to market mitigation and the utilization of 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. As a result of controversy over NRG and other generators' attempts to utilize cost-based RMR contracts (which are paid for by all transmission customers), the FERC ordered a temporary market solution until the ISO could implement a locational capacity (LICAP) solution in June of 2004. LICAP requires that CL&P support enough generation to meet peak demand (plus a reserve to protect against higher demand than expected or generating plant outages) in its service territory. Connecticut, because of insufficient generation and transmission, is expected to have high LICAP costs. As a result of the FERC order, ISO intends to file with the FERC in March of 2004 market rules changes that will implement some form of LICAP. NU has been working with ISO-NE and state regulators to defer or phase-in LICAP in order to mitigate cost increases for its customers.
On July 31, 2003, NEPOOL and ISO-NE submitted to the FERC amendments to the NEPOOL Tariff and Agreement that implement a comprehensive transmission cost allocation methodology, intended to promote construction of new transmission facilities by using a combination of regional cost support and participant funding, depending on the type of upgrade. On December 18, 2003, the FERC accepted the amendments, which will enable most of the costs of transmission expansion projects already identified in ISO's 2002 and 2003 regional transmission expansion plan as reliability upgrades benefiting the region (including NU's Phase I and Phase II southwest Connecticut projects) to be spread across the New England region. Several parties have challenged these amendments and the FERC has not indicated a date by which it will act.
REGULATED GAS OPERATIONS
In 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 non-utility subsidiaries, 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 2003 was 47.1 billion cubic feet. In 2003, total gas operating revenues of $361 million were comprised of the following: 49 percent residential; 29 percent commercial; 21 percent industrial; and the remaining 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 the FERC's 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 2003, certain NU system companies owned 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), the Vermont Yankee nuclear unit (VY) (prior to sale) and the Yankee Rowe nuclear unit (Yankee Rowe). Yankee Rowe, CY and MY have been permanently removed from service and are being decontaminated and decommissioned. In July 2002, the company that owned VY, Vermont Yankee Nuclear Power Company (VYNPC), sold it to a subsidiary of Entergy Corporation, which assumed responsibility for the decommissioning of that 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. CL&P's, PSNH's and WMECO's stock ownership percentages in the Yankee Companies are set forth below:
CL&P PSNH WMECO NU 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% Yankee Atomic Electric Company (YAEC) 24.5% 7.0% 7.0% 38.5%
CL&P, PSNH and WMECO sold their shares of VYNPC back to VYNPC as of October 31, 2003. Prior to the sale of VY, NU subsidiaries owned 17 percent of VYNPC and, under the terms of the sale, will continue to buy 16 percent of VY's output through March 2012 at a range of fixed prices.
The NRC has broad jurisdiction over the design, construction and operation of nuclear generating stations, including the decommissioning activities at the Yankee Companies.
NUCLEAR FUEL
GENERAL
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 United States Department of Energy (DOE). The DOE's current estimate for an available site is 2010 at the earliest.
In 2002, Congress designated the Yucca Mountain site in Nevada as the nation's repository for used nuclear fuel. 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 a trial date has been set for July 12, 2004.
On January 23, 2004, Dominion Nuclear Connecticut, Inc. (DNCI) and Dominion Resources, Inc., on behalf of themselves, CL&P, WMECO and NUSCO, filed a similar complaint in the United States Court of Federal Claims against the DOE, with respect to the DOE's failure to accept spent nuclear fuel for disposal from the Millstone nuclear power station. The complaint is subject to an automatic stay imposed by the United States Court of Federal Claims until the lead cases (including the case filed by CYAPC) go to trial on their damages claims.
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 spring of 2004 and targeted completion of the facility is by the summer of 2005. Approximately 90 percent of the spent fuel has been transferred to the storage facility at MY, with completion estimated during the first quarter of 2004. All of the spent fuel at Yankee Rowe has been moved to the storage site as of June 2003.
DECOMMISSIONING
As a result of the sales of Millstone in 2001 and Seabrook and the VY nuclear units in 2002, respectively, NU shareholders, the NU system companies and their ratepayers have no further obligation related to decommissioning with respect to those units.
Although the purchasers of NU's ownership shares of the Millstone, Seabrook and VY plants assumed the obligations of decommissioning those plants, NU still has significant decommissioning and plant closure cost obligations to the Yankee Companies. The Yankee Companies collect decommissioning and closure costs through wholesale FERC-approved rates charged under power purchase agreements to CL&P, PSNH and WMECO. These companies in turn pass these costs on to their customers through state regulatory commission-approved retail rates. A portion of these decommissioning and closure costs have already been collected, but a substantial portion relating to the decommissioning of CY has not been filed at and approved for collection by the FERC.
During 2002, NU was notified by CYAPC and YAEC that the estimated cost of decommissioning these units and other closure costs increased over prior estimates due to higher anticipated costs for spent fuel storage, security and liability and property insurance. NU's share of this increase is $177.1 million. Following FERC rate cases by the Yankee Companies, NU expects to recover the higher decommissioning costs from the retail customers of CL&P, PSNH and WMECO.
NU cannot at this time predict the timing or outcome of the FERC proceeding required for the collection of these remaining decommissioning and closure costs. Although management believes that these costs will ultimately be recovered from the customers of CL&P, PSNH and WMECO, there is a risk that the FERC may not allow these costs, the estimates of which have increased significantly in 2003 and 2002, to be recovered in wholesale rates. If the FERC does not allow these costs to be recovered in wholesale rates, NU would expect the state regulatory commissions to disallow those costs in retail rates as well. As owners of equity investments in the Yankee Companies, CL&P, PSNH and WMECO are subject to losses if the Yankee Companies are not successful in rate proceedings at the FERC.
YAEC and MYAPC are currently collecting revenues for the decommissioning of the related sites through their power purchase agreements. YAEC ceased decommissioning collections in June 2000 but began collections again on June 1, 2003. The table below sets forth the NU system companies' estimated share of remaining decommissioning costs of the Yankee Companies' units as of December 31, 2003, net of amounts collected in rates. 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 "Nuclear Generation-General."
CL&P PSNH WMECO NU System ---- ---- ----- --------- (Millions)
CY* $229.9 $33.3 $63.3 $326.5 MY* $ 43.7 $18.2 $11.0 $ 72.9 Rowe* $ 44.4 $12.7 $12.7 $ 69.8 ------ ----- ----- ------ Total $318.0 $64.2 $87.0 $469.2 ====== ===== ===== ======
* 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, 2003, which have been recorded as an obligation on the books of the NU system companies.
As of December 31, 2003, 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 $74.0 $10.7 $20.4 $105.1 MY $ 8.4 $ 3.5 $ 2.0 $ 13.9 Rowe $14.2 $ 4.1 $ 4.1 $ 22.4 ----- ----- ----- ------ Total $96.6 $18.3 $26.5 $141.4 ===== ===== ===== ======
The cost estimate for CY not yet approved for recovery by FERC at December 31, 2003 is $258.2 million.
CYAPC is required to file with the FERC no later than mid-2004 for increased costs associated with the decommissioning of CY. YAEC filed with the FERC in April 2003 for its unrecovered decommissioning costs. A settlement was approved by the FERC on October 2, 2003 and collections began on June 1, 2003. The delay in YAEC's fuel transfer activities is expected to extend the completion of decommissioning activities to 2005. MYAPC filed with the FERC in October 2003 for new rates and is currently negotiating a settlement with the FERC and intervening parties. 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.
For information on litigation between CYAPC and Bechtel Power Corporation (Bechtel) relating to the decommissioning of CY, see Item 3, "Legal Proceedings."
In October 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, 2003, costs related to this search totaled $9.4 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 in 2002. The NRC is expected to conclude its review of this matter in 2004.
OTHER REGULATORY AND ENVIRONMENTAL MATTERS
ENVIRONMENTAL REGULATION
GENERAL
The NU system and its subsidiaries are subject to various federal, state and local requirements 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 agencies 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. States may also require additional permits for discharges into state waters. NU system facilities are in the process of obtaining or renewing all required NPDES or state discharge permits in effect. Compliance with NPDES and state discharge permits has necessitated substantial expenditures, which are difficult to estimate, and may require further significant expenditures because of additional requirements or restrictions 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 $78 million as of December 31, 2003: $11 million for CL&P, $60 million for PSNH, $1 million for WMECO and $6 million for HWP. In addition, PSNH expects to spend approximately $3.8 million a year for SO2 compliance and approximately $3 million for annual operational costs for NOX controls.
Massachusetts and New Hampshire are both imposing significant new emission reduction requirements on power plants, in addition to the Federal requirements. In Massachusetts, new emission standards for power plants were signed into law in September 2001. The four pollutants regulated under these standards are NOX, SO2, carbon dioxide (CO2) and mercury, with emission rates and caps for all but mercury effective in October 2006. Interim levels for NOX and SO2 were also set for HWP. The mercury standards were proposed in October 2003 and are not yet final. The capital cost for Mt. Tom Station to meet current Massachusetts emission limits is estimated to be approximately $2 million Completion of this work, coupled with possible output reductions, will reduce Mt. Tom's NOX emissions, thus lowering the amount of NOX allowances required compared to prior years. SO2 requirements will be controlled by purchasing lower sulfur coals. Additional costs for compliance with expected mercury and carbon dioxide 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 the same four pollutants as in Massachusetts. NOX, SO2 and CO2 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 investigation and/or 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, 2003, the liability recorded by the NU system for its estimated environmental remediation costs for known sites needing investigation and/or remediation, including those sites described below, exclusive of recoveries from insurance or from third parties, was approximately $40.8 million, representing 50 sites. This total includes liabilities recorded by Yankee Gas of $18.9 million. All cost estimates were made in accordance with generally accepted accounting principles where investigation and/or remediation costs are probable and reasonably estimable. These costs could be significantly higher if additional remedial actions 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 matters: 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 established a reserve of approximately $1.3 million to its share of the clean up of these sites. For further information on litigation relating to the Connecticut matter, 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, purifier wastes, 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, a reserve of $36.3 million has been established to address future investigation and/or remediation costs at MGP sites.
3. Other sites undergoing comprehensive investigations or remediation actions under state programs located in Connecticut, Massachusetts or New Hampshire include two former fuel oil releases, two landfills, three asbestos hazard abatement projects and nine miscellaneous projects. To date, a reserve of approximately $3.2 million has been established to address future investigation and/or 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 the 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 the 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.
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) issued its Section 401 water quality certification for the combined Housatonic River Project. A draft environmental impact statement for the relicensing was issued in July 2003. A final environmental impact statement is expected during the first half of 2004. A new license for the Housatonic Project is likely to be issued in late 2004 or 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 2003, PSNH filed an application for a new license for the project. The FERC's tentative relicensing schedule provides for the issuance of a scoping document in July 2004; issuance of notice that the application is ready for environmental review in January 2005; availability of an environmental assessment in June 2005 and readiness for commission decision in December 2005. If a new license is not issued by the expiration of the current license (December 31, 2005), it is expected that the 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 the 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, 2003, the NU system companies had 6,757 employees on their payrolls, excluding temporary employees, of which 2,141 were employed by CL&P, 1,282 by PSNH, 408 by WMECO, 488 by Yankee Gas, 300 by NGS, 1,437 by NUSCO, 159 by Select, 104 by SESI and 438 by SECI. NU, NGC, NAEC, Mode 1 and NUEI have no employees.
In response to changing market conditions and state funding reductions, CL&P and NUSCO eliminated some of their organizational lines and otherwise reduced their workforce in 2003. As a result, NGS reduced its workforce by 12 employees, CL&P reduced its workforce by 17 employees and NUSCO reduced its workforce by 22 employees, at a total cost of approximately $1.7 million.
Approximately 2,445 employees of CL&P, PSNH, WMECO, HWP, NUSCO and Yankee Gas are covered by 17 union agreements, none of which were in negotiation as of the end of January 2004, and the remainder of which will expire between June 1, 2004 and May 31, 2006.
INTERNET INFORMATION
The NU system's website address is http://www.nu.com/investors. The company makes available through its website a link to the SEC's EDGAR site, at which site NU's, CL&P's, WMECO's and PSNH's annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to those reports may be reviewed. Printed copies of these reports may be obtained free of charge by writing to the Company's Investor Relations Department at Northeast Utilities, 107 Selden Street, Berlin, Connecticut 06037.
ITEM 2.
ITEM 2. PROPERTIES
The physical properties of NU 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 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 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, NU's 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 natural gas distribution facilities including distribution lines (mains and services), meters, valves, pressure regulators and flow controllers. Yankee Gas also owns five propane peak-shaving facilities with a combined storage capacity equivalent to approximately 245,000 million cubic feet and service buildings and rents or leases certain other property.
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.
NU's properties are well maintained and are in good operating condition.
TRANSMISSION AND DISTRIBUTION SYSTEM
At December 31, 2003, NU owned 108 transmission and 350 distribution substations that had an aggregate transformer capacity of 17,496,990 kilovoltamperes (kVa) and 9,073,362 kVa, respectively; 3,088 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; 33,351 pole miles of overhead and 2,429 conduit bank miles of underground distribution lines; and 437,470 line transformers in service with an aggregate capacity of 19,436,865 kVa.
ELECTRIC GENERATING PLANTS
As of December 31, 2003, the electric generating plants of NU were as follows:
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 Storage (7 units) 1928-73 1,109,000 Total - Internal Combustion (1 unit) 1969 20,800 --------- Total NGC Generating Plant (44 units) 1,287,730 =========
NU Total - Fossil-Steam Plants (7 units) 1952-74 1,133,805 Total - Hydro-Conventional (56 units) 1903-83 225,620 Total - Hydro-Pumped Storage (7 units) 1928-73 1,109,000 Total - Internal Combustion (6 units) 1968-70 123,592 --------- --------- Total NU Generating Plant (76 units) 2,592,017 ========= =========
*Claimed capability represents winter ratings as of December 31, 2003.
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.
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 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 (EWG) and, as it currently operates its business, is not regulated by the DPUC or the DTE. The FERC's authorization for EWGs such as NGC 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 the 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 occupied and 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. Consolidated Edison, Inc. v. NU - Merger Appeals and Related Litigation
This litigation consists of the consolidated civil lawsuits filed in the United States District Court for the Southern District of New York (District Court) by Consolidated Edison, Inc. (Con Edison) and NU regarding the parties' October 19, 1999 Agreement and Plan of Merger, as amended and restated as of January 11, 2000 (Merger Agreement). In its amended complaint, Con Edison alleges that NU failed to perform material obligations under the Merger Agreement, that there has been a "Material Adverse Change" with respect to NU and that certain conditions precedent to Con Edison's obligation to merge with NU have not been and cannot be satisfied. (Con Edison's amended complaint further asserts claims for fraud and negligent misrepresentation which were dismissed on summary judgment on March 15, 2003.) In its counterclaim, NU seeks damages in excess of $1 billion alleging that Con Edison is in material breach of the Merger Agreement based on its repudiation thereof and its refusal to proceed with the merger.
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.
As of June 19, 2003, the parties' motions in limine were fully briefed and remain pending before the District Court. On December 24, 2003, the District Court issued orders dismissing Con Edison's July 1, 2003 motion to dismiss NU's "lost premium" counterclaim without prejudice and granting Robert Rimkoski's July 24, 2003 motion to intervene. NU has filed a cross-claim against Rimkoski seeking a declaratory ruling that NU's current shareholders are the proper third party beneficiaries under the Merger Agreement. On March 26, 2004, the District Court will hear oral argument on the issue of who are the proper beneficiaries under the Merger Agreement, the March 5, 2001 class Rimkowski seeks to represent or the current shareholders. 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. Sale of Millstone to DNCI
On March 8, 2001, the Connecticut Coalition Against Millstone (CCAM) and other parties 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. On December 23, 2003, the Connecticut Supreme Court dismissed CCAM's appeal. On January 2, 2004, CCAM filed a motion for reconsideration en banc, which was denied on February 4, 2004.
3. Retirement Plan Litigation
This matter involves four separate but related federal court lawsuits brought by nineteen former employees of NUSCO, WMECO and CL&P who retired between 1991 and 1994. The complaints generally allege that the companies breached their 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 companies. Plaintiffs are seeking the benefits of retirement plan enhancements adopted subsequent to their retirements.
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.
4. 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), which contract expired on December 31, 2003, by unilaterally reducing the amount of electricity it proposed to purchase from Wisvest. The complaint seeks monetary damages and a declaratory judgment.
Select Energy has filed an Answer to the complaint, denying any liability. It has also filed several special defenses and counterclaims to recover approximately $5.8 million for congestion charges incurred and paid by Select Energy prior to the implementation of SMD on March 1, 2003. No trial date has been set.
5. NRG Bankruptcy
On May 14, 2003, NRG and certain of its affiliates filed for Chapter 11 protection in the United States Bankruptcy Court for the Southern District of New York (Bankruptcy Court). The filing affects relationships between various NU companies and the NRG companies.
A. CL&P Standard Offer Contract
NRG's May 14, 2003 bankruptcy filing included a request by NRG-PMI to terminate service to CL&P under its standard offer supply agreement (SOS Agreement). The U.S. Bankruptcy Court authorized NRG-PMI to reject the SOS Agreement, but the FERC then directed NRG-PMI to continue to perform under its SOS Agreement until the FERC fully considers the matter.
Subsequently, the U.S. District Court for the Southern District of New York issued a ruling deferring to FERC on this matter. On July 18, 2003, NRG- PMI and the Creditors Committee filed an appeal with the U.S. Court of Appeals for the Second Circuit to enjoin the FERC order. On August 15, 2003, FERC issued an order stating that NRG-PMI had failed to demonstrate that premature termination of its SOS Agreement with CL&P would be in the public interest, and therefore, NRG-PMI must continue to perform under the SOS Agreement.
On November 21, 2003, the Bankruptcy Court approved a settlement between CL&P, the Connecticut Attorney General, the DPUC, the Office of Consumer Counsel, NRG-PMI and the Official Committee of Unsecured Creditors. On December 18, 2003, the settlement was approved by the FERC. The settlement required NRG-PMI to serve out the remainder of the SOS Agreement with no change in price or terms, in exchange for a commitment by CL&P to make payments for services rendered on a revised schedule.
B. Station Service
NRG has disputed its responsibility to pay for the provision of station service by CL&P to NRG's Connecticut generating plants. The FERC issued a decision on December 20, 2002 that NRG had agreed that station service from CL&P would be subject to CL&P's applicable retail rates, and that states (i.e., the DPUC) have jurisdiction over the delivery of power to end users even where, as here, power is not delivered via distribution facilities. NRG refused CL&P's subsequent demand for payment, and on April 3, 2003, CL&P petitioned the DPUC for a declaratory order enforcing the FERC's December 20, 2002 decision. No action was taken by the DPUC prior to NRG's bankruptcy filing.
On September 9, 2003, the Bankruptcy Court approved the parties' stipulation to submit the station service issue to arbitration for a determination of liability and damages which will fix CL&P's claim in bankruptcy. The parties are currently pursuing arbitration of the issues in dispute but no hearing dates have been scheduled. On December 17, 2003, the DPUC issued a decision in CL&P's rate case that addressed the issue that CL&P had first raised to the DPUC in its April 3, 2003 filing. The DPUC affirmatively stated that CL&P has been appropriately administering its station service rates. Subsequently, however, in unrelated proceedings, the FERC issued a series of orders with conflicting policy direction, which call into question its December 20, 2002 NRG order. In January 2004, CL&P filed a request with the FERC for further clarification of this issue.
C. Yankee Gas
On October 9, 2002, NRG informed Yankee Gas that its affiliate, Meriden Gas Turbines, LLC (MGT) was permanently shutting down or abandoning its Meriden power plant project, and requested that Yankee Gas cease its construction activities and begin an orderly wind down of its work relating to the project. Based on NRG's statement that it expected that Yankee Gas would draw on a $16 million LOC, Yankee Gas drew down the full amount of the LOC. On November 12, 2002, MGT filed suit against Yankee Gas in Meriden Superior Court, claiming that Yankee Gas breached the agreement with MGT (MGT Agreement) and seeking a declaratory ruling from the court that Yankee Gas wrongfully drew down the $16 million LOC. In April 2003, Yankee Gas filed its answer to MGT's complaint and asserted several counterclaims to recover its losses arising out of MGT's termination of the MGT Agreement. The parties are currently in the discovery phase of the lawsuit.
For additional information on NRG-related matters, see "Item 1. Business- Rates and Electric Industry Restructuring-Connecticut Rates and Restructuring."
6. Enron Power Marketing, Inc. (Enron)/Select Energy
On January 13, 2003, Select Energy received notice from the United States Bankruptcy Court for the Southern District of New York 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 December 22, 2003, the court approved a Settlement Agreement between the parties resolving all issues in this proceeding.
7. 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 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 Judicial 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 Judicial 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.
8. 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. On June 6, 2003, CL&P was added as a defendant.
NUSCO and CL&P have answered the complaint denying the material allegations. Discovery is ongoing and the parties are awaiting a date to be scheduled for court-ordered remediation.
9. CYAPC Decommissioning Dispute
On June 13, 2003, CYAPC gave notice of the termination of its contract with Bechtel for the decommissioning of the Connecticut Yankee nuclear power plant. CYAPC terminated the contract, after the failure of settlement discussions that occurred over an eight month period, due to Bechtel's history of incomplete and untimely performance and refusal to perform the remaining decommissioning work. Under the agreement, Bechtel had 30 days to remedy its defaults before the termination became effective.
On June 23, 2003, Bechtel filed a complaint against CYAPC in Connecticut Superior Court in Middletown, Connecticut. Bechtel's complaint asserts a number of claims and seeks a variety of remedies, including monetary and punitive damages and rescission of the contract. Bechtel has since amended its complaint to add claims for wrongful termination.
On August 22, 2003, CYAPC filed its answer and counterclaims, including counts for breach of contract, negligent misrepresentation and breach of duty of good faith and fair dealing. Bechtel has departed the site and the decommissioning responsibility has been transitioned to CYAPC, which has recommenced the decommissioning process. Discovery is ongoing and a trial has been tentatively scheduled for 2006. Management cannot predict the outcome of this litigation or its impact on NU.
NU's electric operating subsidiaries collectively own 49.0 percent of CYAPC, as follows: CL&P - 34.5 percent, PSNH - 5.0 percent and WMECO - 9.5 percent.
10. 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 and rate proceedings, 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; "Nuclear Generation" for information related to high-level and low-level radioactive waste disposal and decommissioning matters; "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. A special meeting of the holders of common and preferred stock of CL&P was held on November 25, 2003 (Special Meeting), but such meeting was adjourned to a later date without action being taken by shareholders. At the adjourned session of the Special Meeting held on November 26, 2003, the preferred stockholders voted to waive, for a ten-year period, the ten percent limitation on the issuance of unsecured indebtedness with a maturity of less than ten years. Of the total number of outstanding shares of preferred stock outstanding on the record date and eligible to vote as a single class for this proposal, 1,165,074 shares (50.13 percent) voted in favor, 651,885 shares (28.05 percent) voted against, 28,021 shares (1.20 percent) abstained and 479,020 shares (20.62 percent) were not cast. A proposal to amend CL&P's certificate of incorporation to eliminate the provision which limits CL&P's ability to issue unsecured indebtedness with a maturity of less than ten years to no more than ten percent of CL&P's capitalization and unsecured indebtedness of whatever maturity to twenty percent of capitalization was also considered by the holders of common and preferred stock of CL&P at this meeting, but this proposal failed to pass. Of the total number of outstanding shares of common stock outstanding on the record date and eligible to vote as a single class, 6,035,205 shares (100 percent) voted in favor of this proposal. Of the total number of outstanding shares of preferred stock outstanding on the record date and eligible to vote as a single class for this proposal, 1,090,833 shares (46.93 percent) voted in favor, 729,970 shares (31.41 percent) voted against, 24,177 shares (1.04 percent) abstained and 479,020 shares (20.62 percent) were not cast. PART II
ITEM 5.
ITEM 5. MARKET FOR THE REGISTRANTS' COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
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 ---- ------- ---- ---
2003 First $16.06 $13.38 Second 16.77 13.98 Third 18.28 15.76 Fourth 20.17 18.12
2002 First $19.87 $17.61 Second 20.57 18.05 Third 18.45 13.84 Fourth 16.97 13.20
As of January 31, 2004, there were 63,896 common shareholders of record of NU. As of the same date, there were a total of 131,009,465 common shares issued, including 3,156,377 unallocated Employee Stock Ownership Plan (ESOP) shares held in the ESOP trust.
On January 12, 2004, the NU Board of Trustees approved the payment of a 15 cent per share dividend, payable on March 31, 2004, to shareholders of record as of March 1, 2004.
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 April 8, 2003, the NU Board of Trustees approved the payment of a 13.75 cent per share dividend, payable on June 30, 2003, to shareholders of record as of June 1, 2003.
On May 13, 2003, the NU Board of Trustees approved the payment of a 15 cent per share dividend, payable on September 30, 2003, to shareholders of record as of September 1, 2003.
On October 14, 2003, the NU Board of Trustees approved the payment of a 15 cent per share dividend, payable on December 31, 2003, to shareholders of record as of December 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.
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" within NU's 2003 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 2003 and 2002, CL&P approved and paid $60.1 million of common stock dividends to NU.
During 2003 and 2002, PSNH approved and paid $16.8 million and $45 million of common stock dividends, respectively, to NU.
During 2003 and 2002, WMECO approved and paid approximately $22 million and $16 million of common stock dividends, respectively, to NU.
The table below sets forth the information with respect to purchases made by or on behalf of NU or any "affiliated purchaser" (as defined in Rule 10b- 18(a)(3) under the Securities Exchange Act of 1934), of common stock during the fourth quarter of the year ended December 31, 2003.
(1) Purchases were made in open market transactions as a result of the election by certain members of the Board of Trustees to receive their compensation in NU common shares.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
NU. Reference is made to information under the heading "Selected Consolidated Financial Data" contained within NU's 2003 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 within CL&P's 2003 Annual Report, which information is incorporated herein by reference.
PSNH. Reference is made to information under the heading "Selected Consolidated Financial Data" contained within PSNH's 2003 Annual Report, which information is incorporated herein by reference.
WMECO. Reference is made to information under the heading "Selected Consolidated Financial Data" contained within WMECO's 2003 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 within NU's 2003 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 and Results of Operations" and Note 3, "Derivative Instruments and Risk Management Activities," contained within CL&P's 2003 Annual Report, which information is incorporated herein by reference.
PSNH. Reference is made to information under the heading "Management's Discussion and Analysis and Results of Operations" and Note 4, "Derivative Instruments and Risk Management Activities," contained within PSNH's 2003 Annual Report, which information is incorporated herein by reference.
WMECO. Reference is made to information under the heading "Management's Discussion and Analysis and Results of Operations" and Note 3, "Derivative Instruments and Risk Management Activities," contained within WMECO's 2003 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 Auditors' Report," "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 within NU's 2003 Annual Report to Shareholders, which information is incorporated herein by reference.
CL&P. Reference is made to information under the headings "Independent Auditors' Report," "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 within CL&P's 2003 Annual Report, which information is incorporated herein by reference.
PSNH. Reference is made to information under the headings "Independent Auditors' Report," "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 within PSNH's 2003 Annual Report, which information is incorporated herein by reference.
WMECO. Reference is made to information under the headings "Independent Auditors' Report," "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 within WMECO's 2003 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 events that would be described in response to this item have occurred with respect to NU, CL&P, PSNH or WMECO.
ITEM 9A.
ITEM 9A. 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, as of the end of the period covered by 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-15(e) and 15(d)-15(e), are effective to ensure that information required to be disclosed by the companies in reports that it files under the Exchange Act i) is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms and ii) is accumulated and communicated to management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure. 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 III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS
The information in Item 10 is provided as of March 5, 2004 except where otherwise indicated.
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", "Selection of Trustees", and "Section 16(a) Beneficial Ownership Reporting Compliance", of the definitive proxy statement for solicitation of proxies by NU's Board of Trustees, to be dated April 2, 2004, 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 (*) SVP, SEC, GC John H. Forsgren (*) EVP, CFO, VC, T Cheryl W. Grise (*) 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 (*) EVP, CFO Cheryl W. Grise (*) CEO, D Michael G. Morris (*)(**) OTH Leon J. Olivier (*) P, COO, D Charles W. Shivery (*)(***) OTH
PSNH.
Positions Name Held - --------------------------- ---------
David H. Boguslawski VP, D Gregory B. Butler (*) OTH John H. Forsgren (*) EVP, CFO, D Cheryl W. Grise (*) CEO, D Gary A. Long (*) P, COO, D Michael G. Morris (*)(**) CH, D Charles W. Shivery (*)(***) OTH
WMECO.
Positions Name Held - --------------------------- ---------
David H. Boguslawski VP, D Gregory B. Butler (*) OTH John H. Forsgren (*) EVP, CFO, D Cheryl W. Grise (*) CEO, D Kerry J. Kuhlman (*) P, COO, D Michael G. Morris (*)(**) CH, D Charles W. Shivery (*)(***) OTH
* Executive Officer ** Retired as of the end of 2003. *** Provides corporate oversight and governance as interim President of NU effective January 1, 2004.
Key: CEO - Chief Executive Officer OTH - Listed because of policy- CFO - Chief Financial Officer making function for NU system CH - Chairman P - President CHB - Chairman of the Board SEC - Secretary COO - Chief Operating Officer SVP - Senior Vice President D - Director T - Trustee EVP - Executive Vice President VP - Vice President GC - General Counsel VC - Vice Chairman
(1) Mr. Forsgren is a Director of NEON Communications, Inc. and CuraGen Corporation. (2) Mrs. Grise is a Director of MetLife, Inc., Metropolitan Life Insurance Company, and Dana Corporation. (3) Mr. Morris is a director of Cincinnati Bell, the Webster Financial Corporation, and the Spinnaker Exploration Co.
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.
NU, CL&P, PSNH, WMECO
Each of the registrants has adopted a Code of Ethics for Senior Financial Officers. The registrants undertake to provide a copy of the Code of Ethics to any person without charge upon request made in writing and mailed to:
Mr. Gregory B. Butler, Senior Vice President, Secretary and General Counsel Northeast Utilities Service Company P.O. Box 270 Hartford, CT 06141-0270
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, to be dated April 2, 2004, which will be filed with the Commission pursuant to Rule 14a-6 under the Securities Exchange Act of 1934.
CL&P, PSNH, WMECO
SUMMARY COMPENSATION TABLE
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 in accordance with rules of the SEC:
Notes to Summary Compensation and Option/SAR Grants Tables:
1. Payment of 50 percent of the 2003 bonuses for Mr. Forsgren and Mrs. Grise was made in the form of restricted share units vesting over three years, payable upon vesting.
2. Other annual compensation for Mr. Morris includes personal use of the Company's airplane, having a cost to the Company of $170,984 in 2003, $180,886 in 2002, and $219,088 in 2001.
3. At December 31, 2003, the aggregate restricted stock holdings by the individuals named in the table for CL&P, PSNH and WMECO were 122,439, 119,634 and 119,811 common shares of NU, respectively, with a value of $2,469,595, $2,413,018, and 2,416,588, respectively. Restricted stock was awarded as long term incentive compensation to each of these individuals in 2003, except that Mr. Morris's award was in restricted share units that were forfeited upon his retirement; payment of 50 percent of the 2002 and 2001 annual bonuses of each of Mr. Morris, Mr. Forsgren, and Mrs. Grise was made in the form of restricted shares vesting over three years. Dividends on restricted stock are paid out.
4. "All Other Compensation" for 2003 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 Olivier and Mrs. Grise - $6,000, Mr. Long - $5,555 and Mrs. Kuhlman - $5,400) and matching contributions under the Deferred Compensation Plan for Executives (Mr. Morris - $22,731, Mrs. Grise - $7,546 and Mr. Olivier - $3,513). For Mr. Forsgren and Mrs. Grise, it also includes vested deferred compensation paid out in 2003 of $181,574 and $171,041, respectively (See Employment Contracts and Termination of Employment and Change in Control Arrangements, Below), and for Mr. Olivier it includes $8,830 in non-qualified pension payments in accordance with his employment agreement.
LONG-TERM INCENTIVE PLANS - AWARDS IN LAST FISCAL YEAR
Grants of performance units were made during 2003 under the Northeast Utilities 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 net income 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 CL&P, PSNH or WMECO 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 Northeast Utilities system (the Company) and to all service rendered to the Company and CMS. Mr. Morris's Employment Agreement also provides that if he 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.
Messrs. Butler and Forsgren and Mrs. Grise are currently eligible for a make-whole plus a target benefit. Messrs. 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 of 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.
The terms of Mr. Olivier's employment provide for certain supplemental pension benefits in lieu of a make-whole benefit if certain requirements are met, in order to provide a benefit similar to that provided by his previous employer. If Mr. Olivier remains in continuous employment with the Company until September 10, 2011 (or earlier with the Company's permission), he will be eligible for a special benefit, subject to reduction for termination prior to age 65, of three percent of Final Average Compensation for each of his first 15 years of service since September 10, 2001 plus one percent of Final Average Compensation for each of the second 15 years of service. Alternatively, if he does not voluntarily terminate his employment with the Company prior to his 60th birthday, or upon earlier termination upon a Change of Control, as defined in the Special Severance Program, he may receive upon retirement a lump sum payment of $2,050,000 in lieu of the make-whole benefit and the benefit described in the preceding sentence.
ANNUAL BENEFIT FOR OFFICERS ELIGIBLE FOR MAKE-WHOLE BENEFIT
Final Years of Credited Service Average Compensation 15 20 25 30 35
$200,000 $43,264 $57,686 $72,107 $86,760 $101,413 $250,000 $54,514 $72,686 $90,857 $109,260 $127,663 $300,000 $65,764 $87,686 $109,607 $131,760 $153,913 $350,000 $77,014 $102,686 $128,357 $154,260 $180,163 $400,000 $88,264 $117,686 $147,107 $176,760 $206,413 $450,000 $99,514 $132,686 $165,857 $199,260 $232,663 $500,000 $110,764 $147,686 $184,607 $221,760 $258,913 $600,000 $133,264 $177,686 $222,107 $266,760 $311,413 $700,000 $155,764 $207,686 $259,607 $311,760 $363,913 $800,000 $178,264 $237,686 $297,107 $356,760 $416,413 $900,000 $200,764 $267,686 $334,607 $401,760 $468,913 $1,000,000 $223,264 $297,686 $372,107 $446,760 $521,413 $1,100,000 $245,764 $327,686 $409,607 $491,760 $573,913 $1,200,000 $268,264 $357,686 $447,107 $536,760 $626,413 $1,300,000 $290,764 $387,686 $484,607 $581,760 $678,913 $1,400,000 $313,264 $417,686 $522,107 $626,760 $731,413 $1,500,000 $335,764 $447,686 $559,607 $671,760 $783,913
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 1,300,000 468,000 624,000 780,000 780,000 780,000 1,400,000 504,000 672,000 840,000 840,000 840,000 1,500,000 540,000 720,000 900,000 900,000 900,000
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 the make-whole benefit for officers hired before November 1, 2001, and for the target benefit for officers who were hired before November 1, 2001 and eligible for the target benefit prior to October 2003, 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 2003. The compensation covered by the Supplemental Plan in 2003 for Mr. Forsgren, Mrs. Grise, Mr. Butler, Mr. Olivier, Mr. Long, and Mrs. Kuhlman was $1,871,931, $1,169,601, $508,140, $634,627, $348,005 and $328,233, respectively.
As of December 31, 2003, the executive officers named in the Summary Compensation Table had approximately the following years of credited service for purposes of the Supplemental Plan: Mr. Forsgren - 7, Mrs. Grise - 23, Mr. Butler - 7, Mr. Olivier - 5, Mr. Long - 28, and Mrs. Kuhlman - 23. Mr. Morris had 25 years of service for purpose of his special retirement benefit. In addition, Mr. Forsgren had 15 years of service for purposes of his supplemental pension benefit and would have 28 years of service for such purpose if he were to retire at age 65.
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 or arrangements with Messrs. Butler, Forsgren and Olivier and Mrs. Grise; Mr. Olivier and each of the other named executive officers participate 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 certain majority-owned subsidiaries of Northeast Utilities.
The agreements with Messrs. Morris, Butler and Forsgren and Mrs. Grise obligate 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, refrain, while employed by the Company and for a period of time thereafter, from competing with the Company in a specified geographic area, and provide that the officer's base salary will not be reduced below certain levels without the consent of the officer. These agreements also provide 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, 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 specified long-term incentive compensation.
Under the terms of these 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. 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, to be dated April 2, 2004, 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 percent of the outstanding common stock of registrants CL&P, PSNH, and WMECO. As of March 1, 2004, (except that Mr. Morris's beneficial ownership is given as of December 31, 2003, his last day as an Executive Officer of these companies) 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) 39,807 (2) NU Common Gregory B. Butler (3) 39,832 (2) NU Common John H. Forsgren (4) 150,120 (2) NU Common Cheryl W. Grise (5) 182,553 (2) NU Common Kerry J. Kuhlman (6) 37,222 (2) NU Common Gary A. Long (7) 35,715 (2) NU Common Michael G. Morris (8) 974,832 (2) NU Common Leon J. Olivier (9) 22,498 (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 7 1,436,049 (10) 1.12% PSNH 7 1,449,265 (10) 1.13% WMECO 7 1,450,773 (10) 1.13%
(1) Includes 29,154 shares that could be acquired by Mr. Boguslawski pursuant to currently exercisable options and 3,978 shares as to which Mr. Boguslawski has sole voting and no dispositive power.
(2) As of March 1, 2004, each Director and Executive Officer of CL&P, PSNH, or WMECO owned less than one percent of the shares outstanding.
(3) Includes 25,400 shares that could be acquired by Mr. Butler pursuant to currently exercisable options and 5,835 shares as to which Mr. Butler has sole voting and no dispositive power.
(4) Includes 112,598 shares that could be acquired by Mr. Forsgren pursuant to currently exercisable options and 28,343 shares as to which Mr. Forsgren has sole voting and no dispositive power.
(5) Includes 141,359 shares that could be acquired by Mrs. Grise pursuant to currently exercisable options, 25,426 shares 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 26,230 shares that could be acquired by Mrs. Kuhlman pursuant to currently exercisable options and 3,315 shares as to which Ms. Kuhlman has sole voting and no dispositive power.
(7) Includes 25,349 shares that could be acquired by Mr. Long pursuant to currently exercisable options and 3,448 shares as to which Mr. Long has sole voting and no dispositive power.
(8) Includes 863,124 shares that could have been acquired by Mr. Morris as of December 31, 2003 pursuant to then exercisable options and 31,732 shares as to which Mr. Morris had sole voting and no dispositive power until his retirement in 2004.
(9) Includes 13,266 shares that could be acquired by Mr. Olivier pursuant to currently exercisable options and 5,837 shares as to which Mr. Olivier has sole voting and no dispositive power.
(10) Includes 9,674 shares that could be acquired by an executive officer other than those named in the table pursuant to currently exercisable options, 401 shares held in an ESOP by such officer, as to which he has sole voting power and no dispositive power, and 11,670 shares as to which such officer 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 Northeast Utilities Incentive Plan, 5,385,371 shares were available for issuance as of December 31, 2003. 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, 6,921,265 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, to be dated April 2, 2004, which will be filed with the Commission pursuant to Rule 14a-6 under the Securities Exchange Act of 1934.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
NU
Incorporated herein by reference is the information contained in the sections "Pre-Approval of Services Provided by Principal Auditors" and "Fees Paid to Principal Auditor" of the definitive proxy statement for solicitation of proxies by NU's Board of Trustees, to be dated April 2, 2004, which will be filed with the Commission pursuant to Rule 14a-6 under the Securities Exchange Act of 1934.
CL&P, WMECO, PSNH
None of CL&P, WMECO and PSNH are subject to the audit committee requirements of the SEC, the national securities exchanges or the national securities associations. CL&P, WMECO and PSNH obtain audit services from the independent auditor engaged by the Audit Committee of NU's Board of Trustees. The NU Audit Committee has established policies and procedures regarding the pre-approval of services provided by the principal auditors. Those policies and procedures delegate pre-approval of services to the NU Audit Committee Chair and/or Vice Chair provided that such offices are held by NU Trustees who are "independent" within the meaning of the Sarbanes-Oxley Act of 2002 (SOX) and that all such pre-approvals are presented to the Audit Committee at the next regularly scheduled meeting of the Committee. The following relates to fees and services for the entire Northeast Utilities System, including CL&P, WMECO, and PSNH:
The Company's principal auditor was paid fees aggregating $1,735,113 and $2,236,280 for the years ended December 31, 2003 and 2002, respectively, comprised of the following:
1. Audit Fees
The aggregate fees billed to NU and its subsidiaries by Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu and their respective affiliates (collectively, the Deloitte Entities) for audit services rendered for the years ended December 31, 2003 and 2002 totaled $1,441,700 and $2,045,000, respectively. The audit fees were incurred for audits of the annual consolidated financial statements of NU and its subsidiaries, reviews of financial statements included in quarterly reports on Form 10-Q of NU and its subsidiaries, comfort letters, consents and other costs related to registration statements, and fees for accounting consultations related to the application of new accounting standards and rules. For 2002, this amount also includes fees and expenses of $911,000 in conjunction with performing the reaudit of NU's 2001 consolidated financial statements and those of a principal subsidiary.
2. Audit Related Fees
The aggregate fees billed to NU and its subsidiaries by the Deloitte Entities for audit related services rendered for the years ended December 31, 2003 and 2002 totaled $150,200 and $97,800, respectively, primarily related to certain agreed-upon procedures and other attestation engagements and the audit of the Company's 401k Plan. Included in 2002 audit related fees paid to the Deloitte Entities is $12,800 (0.6 percent of total fees) of services where pre-approval was not required, as such services were de minimis. There were no de minimis audit-related services in 2003.
3. Tax Fees
The aggregate fees billed to NU and its subsidiaries by the Deloitte Entities for tax services for the years ended December 31, 2003 and 2002 totaled $47,500 and $51,932, respectively. There were no de minimis tax services in 2003 or 2002.
4. All Other Fees
The aggregate fees billed to NU and its subsidiaries by the Deloitte Entities for the years ended December 31, 2003 and 2002 for services other than the services described above totaled $95,713 and $41,549, respectively, primarily related to training classes provided by the Deloitte Entities. Included in 2003 and 2002 "all other fees" are $16,620 (1 percent of total fees) and $14,708 (0.7 percent of total fees), respectively, of services where pre-approval was not required, as such services were de minimis.
The NU Audit Committee has considered whether the provision by the Deloitte Entities of the non-audit services described above was allowed under Rule 2-01(c)(4) of Regulation S-X and was compatible with maintaining auditor independence and has concluded that the Deloitte Entities were and are independent of the Company in all respects.
PART IV
ITEM 15.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) 1. Financial Statements:
The Independent Auditors' Reports 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
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-2
3. Exhibits Index E-1
(b) Reports on Form 8-K:
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.
NU and CL&P filed current reports on Form 8-K dated May 14, 2003, disclosing:
o The filing by NRG and certain of its affiliates, including NRG-PMI, of voluntary petitions for reorganization under the bankruptcy code in the southern district of New York.
WMECO filed a current report on Form 8-K dated September 30, 2003, disclosing:
o The completion of the issuance and sale to the public of $55 million of 5 percent Senior Notes, Series A, due 2013.
NU, CL&P, PSNH, and WMECO filed current reports on Form 8-K dated November 25, 2003 disclosing:
o The increase in CY decommissioning costs due to the termination of the decommissioning contractor, Bechtel, in July, 2003.
NU filed a current report on Form 8-K dated December 16, 2003 disclosing:
o The departure of Michael G. Morris, Chairman, President and Chief Executive Officer of NU, announcements regarding management transition and interim senior management transition.
NU and CL&P filed current reports on Form 8-K dated December 17, 2003 disclosing:
o A decision by the DPUC granting CL&P a four-year rate increase.
NU and CL&P filed current reports on Form 8-K dated December 22, 2003 disclosing:
o CL&P and other parties had reached an agreement in principle to settle the SMD dispute, with a definitive settlement agreement to be filed with the hearing judge by January 22, 2004.
NU and CL&P filed current reports on Form 8-K dated January 22, 2004 disclosing:
o The delay in filing the agreement reached in principle to settle the SMD dispute with the FERC.
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 12, 2004 By /s/ Charles W. Shivery -------------- ------------------------------------ Charles W. Shivery President (Principal 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 12, 2004 President /s/ Charles W. Shivery - -------------- (Principal --------------------------------- Executive Officer) Charles W. Shivery
March 12, 2004 Vice Chairman, /s/ John H. Forsgren - -------------- Executive Vice --------------------------------- President and Chief John H. Forsgren Financial Officer and a Trustee
March 12, 2004 Vice President - /s/ John P. Stack - -------------- Accounting and --------------------------------- Controller John P. Stack
March 12, 2004 Trustee /s/ Richard H. Booth - -------------- --------------------------------- Richard H. Booth
March 12, 2004 Trustee /s/ Cotton M. Cleveland - -------------- --------------------------------- Cotton M. Cleveland
March 12, 2004 Trustee /s/ Sanford Cloud, Jr. - -------------- --------------------------------- Sanford Cloud, Jr.
March 12, 2004 Trustee /s/ James F. Cordes - -------------- --------------------------------- James F. Cordes
March 12, 2004 Trustee /s/ E. Gail de Planque - -------------- --------------------------------- E. Gail de Planque
March 12, 2004 Trustee /s/ John G. Graham - -------------- --------------------------------- John G. Graham
March 12, 2004 Trustee /s/ Elizabeth T. Kennan - -------------- --------------------------------- Elizabeth T. Kennan
March 12, 2004 Trustee /s/ Robert E. Patricelli - -------------- --------------------------------- Robert E. Patricelli
March 12, 2004 Trustee /s/ John F. Swope - -------------- --------------------------------- John F. Swope
THE CONNECTICUT LIGHT AND POWER COMPANY
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
THE CONNECTICUT LIGHT AND POWER COMPANY --------------------------------------- (Registrant)
Date: March 12, 2004 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 12, 2004 Chief Executive /s/ Cheryl W. Grise - -------------- Officer and --------------------------------- a Director Cheryl W. Grise
March 12, 2004 President and /s/ Leon J. Olivier - -------------- Chief Operating --------------------------------- Officer and Leon J. Olivier a Director
March 12, 2004 Executive Vice /s/ John H. Forsgren - -------------- President and --------------------------------- Chief Financial John H. Forsgren Officer
March 12, 2004 Vice President - /s/ John P. Stack - -------------- Accounting and ---------------------------------- Controller John P. Stack
March 12, 2004 Director /s/ David H. Boguslawski - -------------- --------------------------------- David H. Boguslawski
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 12, 2004 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 12, 2004 Chief Executive /s/ Cheryl W. Grise - -------------- Officer and --------------------------------- a Director Cheryl W. Grise
March 12, 2004 President and /s/ Gary A. Long - -------------- Chief Operating --------------------------------- Officer and Gary A. Long a Director
March 12, 2004 Executive Vice /s/ John H. Forsgren - -------------- President and --------------------------------- Chief Financial John H. Forsgren Officer and a Director
March 12, 2004 Vice President - /s/ John P. Stack - -------------- Accounting and --------------------------------- Controller John P. Stack
March 12, 2004 Director /s/ David H. Boguslawski - -------------- --------------------------------- David H. Boguslawski
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 12, 2004 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 12, 2004 Chief Executive /s/ Cheryl W. Grise - -------------- Officer and --------------------------------- a Director Cheryl W. Grise
March 12, 2004 President and /s/ Kerry J. Kuhlman - -------------- Chief Operating --------------------------------- Officer and Kerry J. Kuhlman a Director
March 12, 2004 Executive Vice /s/ John H. Forsgren - -------------- President and --------------------------------- Chief Financial John H. Forsgren Officer and a Director
March 12, 2004 Vice President - /s/ John P. Stack - -------------- Accounting and --------------------------------- Controller John P. Stack
March 12, 2004 Director /s/ David H. Boguslawski - -------------- --------------------------------- David H. Boguslawski
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"), The Connecticut Light and Power Company ("CL&P") and Public Service Company of New Hampshire ("PSNH") as of December 31, 2003 and 2002 and for each of the three years in the period ended December 31, 2003, and the consolidated financial statements of Western Massachusetts Electric Company ("WMECO") as of and for the years ended December 31, 2003 and 2002 (collectively "the Companies"), and have issued our reports thereon dated February 23, 2004; such financial statements and reports are included in Northeast Utilities' 2003 Annual Report to Shareholders and in CL&P's, PSNH's and WMECO's 2003 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; its adoption in 2002 of SFAS No. 142, Goodwill and Other Intangible Assets; and its adoption in 2003 of EITF 03-11, Reporting Realized Gains and Losses on Derivative Instruments that are Subject to FASB Statement No. 133 and not "Held for Trading Purposes" as Defined in Issue No. 02-3 (EITF 03-11) and the Financial Accounting Standards Board Interpretation No. 46, Consolidation of Variable Interest Entities. Our report on the consolidated financial statements of PSNH expresses an unqualified opinion and includes an explanatory paragraph with respect to PSNH's adoption of EITF 03-11 in 2003.
Our audits also included the 2003, 2002 and 2001 financial statement schedules of Northeast Utilities, CL&P and PSNH and the 2003 and 2002 financial statement schedules of WMECO, listed in Item 15. 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. The 2001 consolidated financial statements and financial statement schedule of WMECO were audited by other auditors who have ceased operations. Those auditors expressed an opinion, in their report dated January 22, 2002, that such financial statement schedules, when considered in relation to the 2001 basic financial statements taken as a whole, presented fairly, in all material respects, the information set forth therein.
/s/ Deloitte & Touche LLP Deloitte & Touche LLP
Hartford, Connecticut February 23, 2004
INDEX TO FINANCIAL STATEMENTS SCHEDULES
Schedule
I. Financial Information of Registrant: Northeast Utilities (Parent) Balance Sheets at December 31, 2003 and 2002 S-3
Northeast Utilities (Parent) Statements of Income for the Years Ended December 31, 2003, 2002, and 2001 S-4
Northeast Utilities (Parent) Statements of Cash Flows for the Years Ended December 31, 2003, 2002, and 2001 S-5
II. Valuation and Qualifying Accounts and Reserves for 2003, 2002, and 2001:
Northeast Utilities and Subsidiaries S-6 - S-8 The Connecticut Light and Power Company and Subsidiaries S-9 - S-11 Public Service Company of New Hampshire and Subsidiaries S-12 - S-14 Western Massachusetts Electric Company and Subsidiary S-15 - S-17
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, 2003 AND 2002 (Thousands of Dollars)
SCHEDULE I NORTHEAST UTILITIES (PARENT) FINANCIAL INFORMATION OF REGISTRANT STATEMENTS OF INCOME YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001 (Thousands of Dollars, Except Share Information)
SCHEDULE I NORTHEAST UTILITIES (PARENT) FINANCIAL INFORMATION OF REGISTRANT STATEMENTS OF CASH FLOWS AT DECEMBER 31, 2003, 2002 AND 2001 (Thousands of Dollars)
EXHIBIT INDEX
Each document described below is incorporated by reference to the files identified, unless designated with a (*), which exhibits are filed herewith.
Exhibit Number Description
1 Underwriting Agreement
(A) Western Massachusetts Electric Company
1.1 Underwriting Agreement between WMECO and the Underwriters named therein, dated September 25, 2003 (Exhibit 99.1, WMECO Form 8-K filed October 8, 2003, File No. 0-7624)
2 Plan of acquisition, reorganization, arrangement, liquidation or succession
(A) NU
2.1 Amended and Restated Agreement and Plan of Merger (Exhibit 1 to NU Form 8-K dated December 2, 1999, File No. 1-5324).
(B) NU and CL&P
2.1 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
(A) Northeast Utilities
3.1 Declaration of Trust of NU, as amended through May 13, 2003. (Exhibit 4.1 to NU Form S-8 filed June 11, 2003, File No. 333- 106008).
(B) The Connecticut Light and Power Company
3.1 Certificate of Incorporation of CL&P, restated to March 22, 1994. (Exhibit 3.2.1, 1993 NU Form 10-K, File No. 1-5324)
3.1.2 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)
3.1.3 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)
3.4 By-laws of CL&P, as amended to January 1, 1997. (Exhibit 3.2.3, 1996 NU Form 10-K, File No. 1-5324)
(C) Public Service Company of New Hampshire
3.1 Articles of Incorporation, as amended to May 16, 1991. (Exhibit 3.3.1, 1993 NU Form 10-K, File No. 1-5324)
3.2 By-laws of PSNH, as amended to November 1, 1993. (Exhibit 3.3.2, 1993 NU Form 10-K, File No. 1-5324)
(D) Western Massachusetts Electric Company
3.1 Articles of Organization of WMECO, restated to February 23, 1995. (Exhibit 3.4.1, 1994 NU Form 10-K, File No. 1-5324)
3.2 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)
3.1.2 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
(A) Northeast Utilities
4.1 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 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)
4.1.2 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 percent Amortizing Notes. (Exhibit 4.1.3, 1992 NU Form 10-K, File No. 1-5324)
4.2 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).
4.2.1 Amendment to Rights Agreement. (Exhibit 3 to NU Form 8-K dated October 13, 1999, File No. 1-5324).
4.2.2 Second Amendment to Rights Agreement. (Exhibit B-3 to NU 35-CERT, dated February 1, 2002, File No. 070-09463).
4.3 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)
4.3.1 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)
4.3.2 Second Supplemental Indenture dated as of June 1, 2003, between NU and the Bank of New York as Trustee, relating to $150M of Senior Notes, Series B, due 2008. (Exhibit A- 1.3 to NU 35-CERT filed June 6, 2003, File No. 70-10051)
4.4 Credit Agreement among Northeast Utilities, the Banks Named Therein, Union Bank of California, N.A. as Administrative Agent and Bank One, N.A., as Fronting Bank, dated as of November 10, 2003. (Exhibit B-5 to NU 35-CERT filed November 17, 2003, File No. 70- 9755)
(B) The Connecticut Light and Power Company
4.1 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)
4.1.1 Supplemental Indenture to the Composite May 1, 1921 Indenture of Mortgage and Deed of Trust between CL&P and Bankers Trust Company, dated as of June 1, 1994. (Exhibit 4.2.15, 1994 NU Form 10-K, File No. 1-5324)
4.1.2 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 October 1, 1994. (Exhibit 4.2.16, 1994 NU Form 10-K, File No. 1-5324)
4.2 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)
4.3 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)
4.4 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)
4.5 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)
4.6 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)
4.7 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)
4.8 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)
4.9 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)
4.9.1 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)
4.10 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)
4.11 Compensation and Multiannual Mode Agreement among the Connecticut Development Authority and BNY Capital Markets, Inc. dated September 23, 2003 (Exhibit 4.2.7.5, 2003 NU Form 10-Q for the Quarter Ended September 30, 2003, File No. 1-5324)
4.12 Amended and Restated Receivables Purchase and Sale Agreement dated as of March 30, 2001). (Exhibit 4.2.8, 2002 NU Form 10-K, File No. 1-5324)
4.12.1 Amendment No. 2 to the Purchase and Sale Agreement dated as of July 10, 2002 (Exhibit 4.2.24.2, 2002 NU Form 10-K, File No. 1-5324)
4.12.2 Amendment No. 3 to the Amended and Restated Receivables Purchase and Sales Agreement dated as of July 9, 2003 (Exhibit 4.2.8.2, 2003 NU Form 10-Q for the Quarter Ended September 30, 2003, File No. 1-5324)
4.13 Purchase and Contribution Agreement dated as of September 30, 1997 (Exhibit 10.49.1, 1997 NU Form 10-K, File No. 1-5324)
4.13.1 Amendment No. 2 to the Purchase and Contribution Agreement dated as of March 30, 2001 (Exhibit 4.2.9 of 2002 NU Form 10-K, File No. 1-5324)
4.14 Credit Agreement among WMECO, CL&P, PSNH, Yankee Gas, the Banks Named Therein and Citibank, N.A. as Administrative Agent, dated as of November 10, 2003. (Exhibit B-6 to NU 35-CERT filed November 17, 2003, File No. 70-9755).
(C) Public Service Company of New Hampshire
4.1 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)
4.1.1 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 Form 8-K dated February 10, 1992, File No. 1- 6392)
4.1.2 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)
4.2 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 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)
4.4 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)
4.5 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)
4.6 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)
4.7 Credit Agreement among WMECO, CL&P, PSNH, Yankee Gas, the Banks Named Therein and Citibank, N.A. as Administrative Agent, dated as of November 10, 2003. (Exhibit B-6 to NU 35-CERT filed November 17, 2003, File No. 70-9755).
(D) Western Massachusetts Electric Company
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)
4.2 Indenture Agreement between WMECO and the Bank of New York, as Trustee, dated as of September 1, 2003 (Exhibit 99.2, WMECO Form 8-K filed October 8, 2003, File No. 0-7624)
4.3 First Supplemental Indenture Agreement between WMECO and the Bank of New York, as Trustee, dated as of September 1, 2003 (Exhibit 99.3, WMECO Form 8-K filed October 8, 2003, File No. 0-7624)
4.4 Credit Agreement among WMECO, CL&P, PSNH, Yankee Gas, the Banks Named Therein and Citibank, N.A. as Administrative Agent, dated as of November 10, 2003. (Exhibit B-6 to NU 35-CERT filed November 17, 2003, File No. 70-9755).
10 Material Contracts
(A) NU
10.1 Lease dated as of April 14, 1992 between The Rocky River Realty Company and Northeast Utilities Service Company with respect to the Berlin, Connecticut headquarters. (Exhibit 10.29, 1992 NU Form 10-K, File No. 1-5324)
10.2 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)
10.2.1 First Amendment to Loan Agreement dated February 7, 1992. (Exhibit 10.36.1, 1993 NU Form 10-K, File No. 1-5324)
10.2.2 Second Amendment to Loan Agreement dated April 9, 1992. (Exhibit 10.36.3, 1993 NU Form 10-K, File No. 1-5324)
10.3 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)
10.4 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 on Form S-4 dated December 6, 2001, File No. 333-74636)
10.4.1 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 on Form S-4 dated December 6, 2001, File No. 333-74636)
10.5 Indenture of Mortgage and Deed of Trust dated July 1, 1989 between Yankee Gas Services Company and the Connecticut National Bank, as Trustee (Exhibit 4.7, Yankee Form 10-K for the fiscal year ended September 30, 1990, File No. 0-10721)
10.5.1 First Supplemental Indenture of Mortgage and of Trust dated April 1, 1992 between Yankee Gas Services Company and The Connecticut National Bank, as Trustee (YES Registration Statement on Form S-3, dated October 2, 1992 Form 1992 File No. 33-52750).
10.5.2 Second Supplemental Indenture of Mortgage and Deed of Trust dated December 1, 1992 between Yankee Gas Services Company and The Connecticut National Bank, as Trustee (YES Form 10-K for the fiscal year ended September 30, 1992, File No. 0-17605).
10.5.3 Third Supplemental Indenture of Mortgage and Deed of Trust dated June 1, 1995 between Yankee Gas and Shawmut Bank Connecticut, N.A. (formerly The Connecticut National Bank), as Trustee. (Exhibit 4.14 YES Form 10-K for the fiscal year ended September 30, 1995, File No. 0-10721).
10.5.4 Fourth Supplemental Indenture of Mortgage and Deed of Trust dated April 1, 1997 between Yankee Gas and Fleet National Bank (formerly The Connecticut National Bank), as Trustee. (Exhibit 4.15 YES Form 10-K for the fiscal year ended September 30, 1997, File No. 0-10721).
10.5.5 Fifth Supplemental Indenture of Mortgage and Deed of Trust dated January 1, 1999 between Yankee Gas Services Company and The Bank of New York, as Successor Trustee to Fleet Bank (formerly The Connecticut National Bank) (Exhibit 4.2 YES Form 10-Q for the fiscal quarter ended March 31, 1999, File No. 0-10721).
(B) NU, CL&P, PSNH and WMECO
10.1 Service Contract dated as of July 1, 1966 between each of NU, CL&P and WMECO and Northeast Utilities Service Company (NUSCO). (Exhibit 10.20, 1993 NU Form 10-K, File No. 1-5324)
10.2 Form of Annual Renewal of Service Contract. (Exhibit 10.20.3, 1993 NU Form 10-K, File No. 1-5324)
10.3 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)
10.3.1 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)
10.3.2 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)
10.3.3 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)
10.4 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)
10.5 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)
10.6 Power Purchase 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)
10.7 Additional Power Purchase 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)
10.8 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)
*10.9 Form of 1996 Amendatory Agreement between CYAPC and CL&P dated December 4, 1996
*10.9.1 Form of First Supplemental to the 1996 Amendatory Agreement dated as of February 10, 1997.
10.10 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)
10.11 Amended and Restate Power Purchase Contract dated as of April 1, 1985, between YAEC and each of CL&P, PSNH and WMECO. (Exhibit 10.5, 1988 NU Form 10-K, File No. 1-5324.)
10.11.1 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)
10.11.2 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)
10.11.3 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)
10.11.4 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)
*10.11.5 Form of Amendment No. 8 to Power Contract, dated June 1, 2003, between YAEC and each of CL&P, PSNH and WMECO.
10.12 Stockholder Agreement dated as of May 20, 1968 among stockholders of MYAPC. (Exhibit 10.6, 1997 NU Form 10-K, File No. 1-5324)
10.13 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)
10.13.1 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)
10.14 Power Purchase 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)
10.14.1 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)
10.14.2 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)
10.14.3 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)
10.14.4 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)
10.15 Sharing Agreement between CL&P, WMECO, HP&E, HWP and PSNH dated as of June 1, 1992. (Exhibit 10.17, 1992 NU Form 10-K, File No. 1- 5324)
10.16 Agreements among New England Utilities with respect to the Hydro- Quebec interconnection projects. (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)
10.17 NU Incentive Plan, effective as of January 1, 1998. (Exhibit 10.35.1, 1998 NU Form 10-K, File No. 1-5324)
10.17.1 Amendment to NU Incentive Plan, effective as of February 23, 1999. (Exhibit 10.35.1.1, 1998 NU Form 10-K, File No. 1-5324)
10.18 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)
10.18.1 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)
10.18.2 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)
10.18.3 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)
10.18.4 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)
10.18.5 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)
*10.18.6 Amendment 6 to Supplemental Executive Retirement Plan, effective as of December 9, 2003.
10.19 Trust under Supplemental Executive Retirement Plan dated May 2, 1994. (Exhibit 10.33, 2002 NU Form 10-K, File No. 1-5324)
*10.19.1 First Amendment to Trust, effective as of December 10, 2002.
10.20 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)
10.20.1 Amendment to Special Severance Program, effective as of February 23, 1999. (Exhibit 10.37.1, 1998 NU Form 10-K, File No. 1-5324)
10.20.2 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)
10.21 Employment Agreement with Michael G. Morris. (Exhibit 10.39, 1997 NU Form 10-K, File No. 1-5324)
10.21.1 Amendment to Morris Employment Agreement, dated as of February 23, 1999. (Exhibit 10.39.1, 1998 NU Form 10-K, File No. 1-5324)
10.21.2 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)
10.21.3 Amendment to Morris Employment Agreement, dated as of September 11, 2001. (Exhibit 10.41.3 to 2001 NU Form 10-Q for the Quarter Ending September 30, 2001, File No. 1-5324)
10.22 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)
10.23 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)
10.24 Arrangement with Michael G. Morris with respect to use of corporate airplane. (Exhibit 10.39, 2002 NU Form 10-K, File No. 1-5324)
10.25 Consulting Agreement with Bruce M. Kenyon, dated as of December 21, 2002. (Exhibit 10.41.5, 2002 NU Form 10-K, File No. 1-5324)
10.26 Employment Agreement with John H. Forsgren.(Exhibit 10.41, 1996 NU Form 10-K, File No. 1-5324)
10.26.1 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)
10.26.2 Amendment to Forsgren Employment Agreement, dated as of February 23, 1999. (Exhibit 10.42.2, 1998 NU Form 10-K, File No. 1-5324)
10.26.3 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)
10.26.4 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)
10.26.5 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)
10.26.6 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)
10.26.7 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)
10.27 Employment Agreement with John H. Forsgren, dated as of April 1, 2003 (Exhibit 10.42.6 to 2003 NU Form 10-Q for Quarter Ended March 31, 2003, File No. 1-5324)
10.28 Employment Agreement with Cheryl W. Grise. (Exhibit 10.44, 1998 NU Form 10-K, File No. 1-5324)
10.28.1 Amendment to Grise Employment Agreement, dated as of January 13, 1998. (Exhibit 10.44.1, 1998 NU Form 10-K, File No. 1-5324)
10.28.2 Amendment to Grise Employment Agreement, dated as of February 23, 1999. (Exhibit 10.44.2, 1998 NU Form 10-K, File No. 1-5324)
10.28.3 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)
10.28.4 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)
10.28.5 Supplemental Compensation Arrangement with Cheryl W. Grise, dated as of September 17, 2001. (Exhibit 10.46.4 to 2001 NU Form 10-Q for Quarter Ended September 30, 2001, File No. 1-5324)
10.29 Employment Agreement with Cheryl W. Grise, dated as of April 1, 2003 (Exhibit 10.45.6 to 2003 NU Form 10-Q for Quarter Ended March 31, 2003, File No. 1-5324)
10.30 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)
*10.31 Employment Agreement with Gregory B. Butler, dated as of October 1, 2003.
10.32 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)
10.32.1 Amendment to Deferred Compensation Plan, effective November 5, 2001. (Exhibit 10.46.1, 2001 NU Form 10-K, File No. 1-5324)
10.33 Northeast Utilities Deferred Compensation Plan for Executives, adopted January 13, 1998. (Exhibit A.5 to NU Form U-1 filed March 5, 1998, File No. 70-09185)
(C) NU and CL&P
10.1 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)
10.2 CL&P Transition Property Servicing Agreement dated as of March 30, 2001. (Exhibit 10.56, 2001 NU Form 10-K, File No. 1-5324)
*10.3 Description of terms of employment of Leon J. Olivier.
(D) NU and PSNH
10.1 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)
10.2 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)
10.3 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)
10.4 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)
10.5 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)
10.6 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)
(E) NU and WMECO
10.1 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)
10.2 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)
10.3 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 that have been incorporated by reference into this Form 10-K.
13.2 Annual Report of CL&P
13.3 Annual Report of PSNH
13.4 Annual Report of WMECO
*21 Subsidiaries of the Registrant
*23 Independent Auditors' Consent
*31
(a) Northeast Utilities
Certification of Charles W. Shivery, President of NU, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated March 12, 2004
(b) The Connecticut Light and Power Company
Certification of Cheryl W. Grise, Chief Executive Officer of CL&P, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated March 12, 2004
(c) Public Service Company of New Hampshire
Certification of Cheryl W. Grise, Chief Executive Officer of PSNH, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated March 12, 2004
(d) Western Massachusetts Electric Company
Certification of Cheryl W. Grise, Chief Executive Officer of WMECO, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated March 12, 2004
*31.1
(a) Northeast Utilities
Certification of John H. Forsgren, Vice Chairman, Executive Vice President and Chief Financial Officer of NU, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated March 12, 2004
(b) The Connecticut Light and Power Company
Certification of John H. Forsgren, Executive Vice President and Chief Financial Officer of CL&P, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated March 12, 2004
(c) Public Service Company of New Hampshire
Certification of John H. Forsgren, Executive Vice President and Chief Financial Officer of PSNH, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated March 12, 2004
(d) Western Massachusetts Electric Company
Certification of John H. Forsgren, Executive Vice President and Chief Financial Officer of WMECO, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated March 12, 2004
*32
(a) Northeast Utilities
Certification of Charles W. Shivery, President of NU and John H. Forsgren, Vice Chairman, Executive Vice President and Chief Financial Officer of NU, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated March 12, 2004
(b) The Connecticut Light and Power Company
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 12, 2004
(c) Public Service Company of New Hampshire
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 12, 2004
(d) Western Massachusetts Electric Company
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 12, 2004