UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from ________ to ________
Commission Registrant; State of Incorporation; I.R.S. Employer
File Number Address; and Telephone Number Identification No.
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1-5324 NORTHEAST UTILITIES 04-2147929
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(a Massachusetts voluntary association)
174 Brush Hill Avenue
West Springfield, Massachusetts 01090-2010
Telephone: (413) 785-5871
0-11419 THE CONNECTICUT LIGHT AND POWER COMPANY 06-0303850
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(a Connecticut corporation)
107 Selden Street
Berlin, Connecticut 06037-1616
Telephone: (860) 665-5000
1-6392 PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE 02-0181050
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(a New Hampshire corporation)
Energy Park
780 North Commercial Street
Manchester, New Hampshire 03101-1134
Telephone: (603) 669-4000
0-7624 WESTERN MASSACHUSETTS ELECTRIC COMPANY 04-1961130
--------------------------------------
(a Massachusetts corporation)
174 Brush Hill Avenue
West Springfield, Massachusetts 01090-2010
Telephone: (413) 785-5871
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Securities registered pursuant to Section 12(b) of the Act:
Name of Each Exchange
Registrant Title of Each Class on Which Registered
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Northeast Utilities Common Shares, $5.00 par value New York Stock Exchange,Inc.
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Securities registered pursuant to Section 12(g) of the Act:
Registrant Title of Each Class ---------- ------------------- The Connecticut Light and Preferred Stock, par value $50.00 per share, Power Company issuable in series, of which the following |
series are outstanding:
$1.90 Series of 1947 4.96% Series of 1958 $2.00 Series of 1947 4.50% Series of 1963 $2.04 Series of 1949 5.28% Series of 1967 $2.20 Series of 1949 $3.24 Series G of 1968 3.90% Series of 1949 6.56% Series of 1968 $2.06 Series E of 1954 $2.09 Series F of 1955 4.50% Series of 1956 |
Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.
Yes X No ___
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrants' knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X]
Indicate by check mark whether the registrants are accelerated filers (as defined in Rule 12b-2 of the Act).
Yes X No ___
The aggregate market value of Northeast Utilities' Common Shares, $5.00 Par Value, held by nonaffiliates, computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of Northeast Utilities' most recently completed second fiscal quarter (June 30, 2003) was $2,124,888 based on a closing sales price of $16.74 per share for the 126,934,753 common shares outstanding on June 30, 2003. Northeast Utilities holds all of the 6,035,205 shares, 301 shares, and 434,653 shares of the outstanding common stock of The Connecticut Light and Power Company, Public Service Company of New Hampshire and Western Massachusetts Electric Company, respectively.
Documents Incorporated by Reference:
Part of Form 10-K
into Which Document
Description is Incorporated
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Portions of Annual Reports of the following
companies for the year ended December 31, 2003:
Northeast Utilities Part II
The Connecticut Light and Power Company Part II
Public Service Company of New Hampshire Part II
Western Massachusetts Electric Company Part II
Portions of the Northeast Utilities Proxy
Statement dated April 2, 2004 Part III
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GLOSSARY OF TERMS
The following is a glossary of frequently used abbreviations or acronyms that are found in this report:
COMPANIES
Acumentrics............................... Acumentrics Corporation
Baycorp................................... Baycorp Holdings, Ltd.
Bechtel................................... Bechtel Power Corporation
BMC....................................... BMC Energy LLC
Boulos.................................... E.S. Boulos Company
CL&P...................................... The Connecticut Light and Power Company
Con Edison................................ Consolidated Edison, Inc.
CRC....................................... CL&P Receivables Corporation
CVEC...................................... Connecticut Valley Electric Company, Inc.
CVPS...................................... Central Vermont Public Service Corporation
CYAPC..................................... Connecticut Yankee Atomic Power Company
DNCI...................................... Dominion Nuclear Connecticut, Inc.
Entergy................................... Entergy Corporation
FPL....................................... FPL Group, Inc.
Funding Companies......................... CL&P Funding LLC, PSNH Funding LLC,
PSNH Funding LLC 2, and WMECO Funding LLC
HEC/CJTS.................................. HEC/CJTS Energy Center LLC
HEC/Tobyhanna............................. HEC/Tobyhanna Energy Project, LLC
HP&E...................................... Holyoke Power and Electric Company
HWP....................................... Holyoke Water Power Company
MGT....................................... Meriden Gas Turbines, LLC
Mode 1.................................... Mode 1 Communications, Inc.
MYAPC..................................... Maine Yankee Atomic Power Company
NAEC...................................... North Atlantic Energy Corporation
NAESCO.................................... North Atlantic Energy Service Corporation
NEON...................................... NEON Communications, Inc.
NGC....................................... Northeast Generation Company
NGS....................................... Northeast Generation Services Company
NNECO..................................... Northeast Nuclear Energy Company
NRG....................................... NRG Energy, Inc.
NRG-PMI................................... NRG Power Marketing, Inc.
NU or the company......................... Northeast Utilities
NU system................................. Northeast Utilities System
NUEI...................................... NU Enterprises, Inc.
NUSCO..................................... Northeast Utilities Service Company
PSNH...................................... Public Service Company of New Hampshire
RMS....................................... R.M. Services, Inc.
RRR....................................... The Rocky River Realty Company
Select Energy............................. Select Energy, Inc.
SESI...................................... Select Energy Services, Inc.
VYNPC..................................... Vermont Yankee Nuclear Power Corporation
WMECO..................................... Western Massachusetts Electric Company
Woods Electrical.......................... Woods Electrical Co., Inc.
Woods Network............................. Woods Network Services, Inc.
YAEC...................................... Yankee Atomic Electric Company
Yankee.................................... Yankee Energy System, Inc.
Yankee Companies.......................... CYAPC, MYAPC, VYNPC, and YAEC
Yankee Gas................................ Yankee Gas Services Company
GENERATING UNITS
Millstone 1............................... Millstone Unit No. 1, a 660 megawatt
nuclear unit completed in 1970; Millstone 1
is currently in decommissioning status and
was sold to a subsidiary of Dominion in
March 2001.
Millstone 2............................... Millstone Unit No. 2, an 870 megawatt
nuclear electric generating unit completed
in 1975; Millstone 2 was sold to a
subsidiary of Dominion in March 2001.
Millstone 3............................... Millstone Unit No. 3, a 1,154 megawatt
nuclear electric generating unit completed
in 1986; Millstone 3 was sold to a
subsidiary of Dominion in March 2001.
Seabrook.................................. Seabrook Unit No. 1, a 1,148 megawatt
nuclear electric generating unit completed
in 1986. Seabrook 1 went into service in
1990. Seabrook 1 was sold to a subsidiary
of FPL in November 2002.
REGULATORS
CSC....................................... Connecticut Siting Council
CDEP...................................... Connecticut Department of
Environmental Protection
DOE....................................... United States Department of Energy
DPUC...................................... Connecticut Department of
Public Utility Control
DTE....................................... Massachusetts Department of
Telecommunications and Energy
EPA....................................... United States Environmental
Protection Agency
FERC...................................... Federal Energy Regulatory Commission
NHPUC..................................... New Hampshire Public Utilities
Commission
NRC....................................... Nuclear Regulatory Commission
SEC....................................... Securities and Exchange Commission
OTHER
1935 Act.................................. Public Utility Holding Company
Act of 1935
ABO....................................... Accumulated Benefit Obligation
AFUDC..................................... Allowance for Funds Used During
Construction
ARO....................................... Asset Retirement Obligation
BFA....................................... Business Finance Authority
CAAA...................................... Clean Air Act Amendments of 1990
CTA....................................... Competitive Transition Assessment
District Court............................ United States District Court for the
Southern District of New York
EDIT...................................... Excess Deferred Income Taxes
EITF...................................... Emerging Issues Task Force
EMF....................................... Electric and Magnetic Fields
Energy Act................................ Energy Policy Act of 1992
EPS....................................... Earnings Per Share
ESOP...................................... Employee Stock Ownership Plan
ESPP...................................... Employee Stock Purchase Plan
IERM...................................... Infrastructure Expansion Rate
Mechanism
FASB...................................... Financial Accounting Standards Board
FPPAC..................................... Fuel and Purchased-Power
Adjustment Clause
FSP....................................... FASB Staff Position
FTR....................................... Financial Transmission Rights
GSC....................................... Generation Service Charge
Incentive Plan............................ Northeast Utilities Incentive Plan
IPP....................................... Independent Power Producer
ISO-NE.................................... New England Independent System
Operator
ITC....................................... Investment Tax Credits
kWh....................................... Kilowatt-hour
LMP....................................... Locational Marginal Pricing
LNS....................................... Local Network Service
LOC....................................... Letter of Credit
Merger Agreement.......................... Agreement and Plan of Merger, as
amended and restated as of January 11,
2000, between NU and Con Edison
MGP....................................... Manufactured Gas Plant
MW........................................ Megawatts
NEIL...................................... Nuclear Electric Insurance Limited
NEPOOL.................................... New England Power Pool
NPDES..................................... National Pollutant Discharge
Elimination System
NYMEX..................................... New York Mercantile Exchange
O&M....................................... Operation and Maintenance
PBO....................................... Projected Benefit Obligation
PBOP...................................... Postretirement Benefits Other
Than Pensions
PCRBs..................................... Pollution Control Revenue Bonds
Pool...................................... Northeast Utilities System Money Pool
Restructuring Settlement.................. "Agreement to Settle PSNH Restructuring"
RMR....................................... Reliability Must Run
RNS....................................... Regional Network Service
ROC....................................... Risk Oversight Council
ROE....................................... Return on Equity
RRBs...................................... Rate Reduction Bonds
RRCs...................................... Rate Reduction Certificates
RTO....................................... Regional Transmission Organization
SBC....................................... System Benefits Charge
SCRC...................................... Stranded Cost Recovery Charge
SERP...................................... Supplemental Executive Retirement Plan
SFAS...................................... Statement of Financial Accounting
Standards
SMD....................................... Standard Market Design
SPE....................................... Special Purpose Entity
TCC....................................... Transmission Congestion Contracts
TS........................................ Transition Energy Service
TSO....................................... Transitional Standard Offer
VIE....................................... Variable Interest Entity
VRP....................................... Voluntary Retirement Program
VSP....................................... Voluntary Separation Program
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NORTHEAST UTILITIES
THE CONNECTICUT LIGHT AND POWER COMPANY
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
WESTERN MASSACHUSETTS ELECTRIC COMPANY
2003 Form 10-K Annual Report
Table of Contents
PART I
Page
Item 1. Business................................................. 1
The Northeast Utilities System................................ 1
Safe Harbor Statement......................................... 2
Rates and Electric Industry Restructuring..................... 3
General.................................................. 3
Connecticut Rates and Restructuring...................... 4
Massachusetts Rates and Restructuring.................... 9
New Hampshire Rates and Restructuring.................... 10
Competitive System Businesses................................. 10
Retail and Wholesale Marketing........................... 11
Electric Generation...................................... 14
Competitive Energy Subsidiaries' Market
and Other Risks........................................ 14
Energy Management Services............................... 16
Telecommunications....................................... 17
Financing Program............................................. 17
2003 Financings.......................................... 17
2004 Financing Requirements.............................. 19
2004 Financing Plans..................................... 20
Financing Limitations.................................... 20
Construction and Capital Improvement Program.................. 26
Regulated Electric Operations................................. 26
Distribution and Sales................................... 26
Regional and System Coordination......................... 27
Transmission Access and FERC Regulatory Changes.......... 28
Regulated Gas Operations...................................... 29
Nuclear Generation............................................ 30
General.................................................. 30
Nuclear Fuel............................................. 31
Decommissioning.......................................... 32
Other Regulatory and Environmental Matters.................... 34
Environmental Regulation................................. 34
Electric and Magnetic Fields............................. 37
FERC Hydroelectric Project Licensing..................... 38
Employees..................................................... 39
Internet Information.......................................... 39
Item 2. Properties............................................... 39
Item 3. Legal Proceedings........................................ 43
Item 4. Submission of Matters to a Vote of Security Holders...... 48
PART II
Item 5. Market for Registrants' Common Equity, Related
Stockholder Matters and Issuer Purchases of
Equity Securities........................................ 49
Item 6. Selected Financial Data.................................. 51
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations...................... 51
Item 7A. Quantitative and Qualitative Disclosures About
Market Risk.............................................. 51
Item 8. Financial Statements and Supplementary Data.............. 51
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure...................... 52
Item 9A. Controls and Procedures.................................. 52
PART III
Item 10. Directors and Executive Officers of the Registrants...... 53
Item 11. Executive Compensation................................... 56
Item 12. Security Ownership of Certain Beneficial Owners and
Management and Related Stockholder Matters............... 64
Item 13. Certain Relationships and Related Transactions........... 66
Item 14. Principal Accountant Fees and Services................... 66
PART IV
Item 15. Exhibits, Financial Statement Schedules and
Reports on Form 8-K...................................... 69
Signatures......................................................... 71
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NORTHEAST UTILITIES
THE CONNECTICUT LIGHT AND POWER COMPANY
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
WESTERN MASSACHUSETTS ELECTRIC COMPANY
PART I
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
==== ==== === === ==== ====
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* 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
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(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%
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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%
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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%
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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
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* 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
===== ===== ===== ======
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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. 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
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Total PSNH Generating Plant (31 units) 1,157,287
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HWP Total - Fossil-Steam Plants (1 unit) 1960 147,000
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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
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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
========= =========
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*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. 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. 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. 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
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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.
Total Number of Maximum Number of
Shares Purchased Shares That May Yet
Total Number Average as Part of Publicly Be Purchased Under
of Shares Price Paid Announced Plans the Plans or
Period Purchased (1) Per Share or Programs Programs
------ ------------- ---------- ------------------- -------------------
Month #1
(October 1, 2003 to
October 31, 2003) 333 $18.03 0 N/A
Month #2
(November 1, 2003
to November 30, 2003) 0 N/A 0 N/A
Month #3
(December 1, 2003 to
December 31, 2003) 0 N/A 0 N/A
--- ------ --- ---
Total 333 $18.03 0 N/A
--- ------ --- ---
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(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. 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. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS;
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. 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. 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. 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. 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
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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
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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
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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
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* 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 |
Name Age Business Experience During Past 5 Years
------------------------ --- ---------------------------------------
David H. Boguslawski 49 Vice President - Transmission Business of
CL&P, PSNH and WMECO since May 1, 2001 and a
Director of CL&P, PSNH and WMECO since June 30,
1999; previously Vice President - Energy Delivery
of CL&P, PSNH and WMECO from September 1996 to
May 2001.
Gregory B. Butler 46 Senior Vice President, Secretary and
General Counsel of NU since August 31, 2003 and a
Director of Northeast Utilities Foundation, Inc.
since December 1, 2002; previously Vice
President, Secretary and General Counsel of NU
from May 1, 2001 through August 30, 2003; Vice
President - Governmental Affairs of NUSCO from
January 1997 to May 2001.
John H. Forsgren (1) 57 Vice Chairman of NU since May 1, 2001;
Executive Vice President and Chief Financial
Officer of NU since February 1, 1996; Executive
Vice President and Chief Financial Officer of
CL&P, PSNH, and WMECO since February 27, 2003 and
from February 1996 to June 1999; Director of
WMECO since June 10, 1996 and of PSNH since
August 5, 1996 and a Director of Northeast
Utilities Foundation, Inc. since September 23,
1998; Director of CL&P from June 1996 to June
1999.
Cheryl W. Grise (2) 51 President - Utility Group of NU since May
2001, Chief Executive Officer of CL&P, PSNH and
WMECO since September 10, 2002 a Director of CL&P
since May 1, 2001, PSNH since May 14, 2001 and
WMECO since June 2001, and a Director of
Northeast Utilities Foundation, Inc. since
September 23, 1998; previously President of CL&P
from May 2001 to September 2001, Senior Vice
President, Secretary and General Counsel of NU
from July 1998 to May 2001, Senior Vice
President, Secretary and General Counsel of CL&P,
and PSNH and Senior Vice President, Secretary,
Assistant Clerk and General Counsel of WMECO from
July 1998 to June 1999 and Senior Vice President,
Secretary and General Counsel of NGC from January
1999 to June 1999; previously Director of CL&P
and WMECO (January 1994 through November 1997)
and PSNH (February 1995 through November 1997);
Senior Vice President and Chief Administrative
Officer of CL&P and PSNH, and Senior Vice
President of WMECO from 1995 to 1998.
Kerry J. Kuhlman 53 President and Chief Operating Officer
and a Director of WMECO since April 1999;
previously Vice President-Customer Operations of
WMECO from October 1998 to April 1999; Vice
President - Central Region of CL&P from August
1997 to October 1998; and Vice President-Eastern
Region of CL&P from July 1994 to August 1997.
Gary A. Long 52 President and Chief Operating Officer
and a Director of PSNH since July 1, 2000;
previously Senior Vice President - PSNH of PSNH
from February 2000 through June 2000 and Vice
President - Customer Service and Economic
Development of PSNH from January 1994 to February
2000.
Michael G. Morris (3) 57 Chairman of the Board, President and Chief
Executive Officer and a Trustee of NU and
Chairman and a Director of PSNH and WMECO from
August 19, 1997 through December 31, 2003 and a
Director of Northeast Utilities Foundation, Inc.
from September 23, 1998 through December 31,
2003; Chief Executive Officer of PSNH from
August 19, 1997 through March 1, 2000 and from
July 1, 2000 through September 10, 2002; Chief
Executive Officer of WMECO from June 30, 1999 to
September 10, 2002; Chairman and a Director of CL&P
from August 1997 to June 1999.
Leon J. Olivier 55 President and Chief Operating Officer
and a Director of CL&P since September 2001;
previously Senior Vice President of Entergy
Nuclear Corp. from April 2001 to September 2001;
Senior Vice President and Chief Nuclear Officer
of Northeast Nuclear Energy Company from October
1998 to May 2001.
Charles W. Shivery 58 President (interim) of NU since January 1,
2004 and a Director of Northeast Utilities
Foundation since March 3, 2004; previously
President - Competitive Group of NU from June 2002
through December 31, 2003 and President and
Chief Executive Officer of NU Enterprises, Inc.,
from June 2002 through December 18, 2003;
Co-President of Constellation Energy Group, Inc.
from October 2000 to February 2002; President and
Chief Executive Officer of Constellation Power
Source Holdings, Inc., from 1997 to December 2001;
Chief Executive Officer and President of
Constellation Enterprises, Inc. from 1998 to
February 2002; and Chairman of the Board,
President and Chief Executive Officer of
Constellation Power Source, Inc., from 1997 to
December 2001.
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(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. 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:
---------------------------------------------------------------------------------------------------------------
Annual Compensation Long-Term Compensation
------------------- -----------------------------------------------
Awards Payouts
------------------------- ---------------------
Restricted Securities Long-Term All
Stock Underlying Incentive Other
Other Annual Award(s) Options/Stock Program Compen-
Name and Salary Bonus ($) Compensation ($) Appreciation Payouts sation ($)
Principal Position Year ($) (Note 1) (Note 2) (Note 3) Rights (#) ($) (Note 4)
---------------------------------------------------------------------------------------------------------------
Michael G. Morris 2003 957,692 2,600,000 227,914 1,060,500 - - 28,731
Chairman of the
Board, President 2002 915,385 558,000 209,883 - 630,600 - 27,462
and Chief Executive
Officer of NU and 2001 900,000 869,805 238,924 - 220,000 - 27,000
Chairman of
PSNH and WMECO
(retired end of
2003)
John H. Forsgren 2003 574,615 1,086,175 17,384 427,495 - - 187,574
Executive Vice
President and 2002 556,154 165,000 - - 54,400 - 179,674
Chief Financial
Officer and Vice 2001 524,423 200,000 - - 98,000 - 5,100
Chairman of NU
Cheryl W. Grise 2003 451,538 581,513 13,216 324,994 - - 184,587
President -
Utility Group of NU 2002 409,231 280,000 - - 39,600 - 180,523
and Chief Executive
Officer of CL&P, 2001 338,654 180,000 - - 76,000 - 10,119
PSNH and WMECO
Gregory B. Butler 2003 244,615 232,200 4,473 109,995 - - 6,000
Senior Vice Presi-
dent, Secretary 2002 206,154 70,000 - - 13,200 - 6,000
and General Counsel
of NU and NUSCO 2001 189,269 70,000 - - 7,600 - 5,100
Leon J. Olivier 2003 317,100 275,000 3,192 78,505 - - 18,343
President and Chief
Operating Officer 2002 303,908 138,000 - - 9,900 - 9,117
of CL&P
(CL&P Table Only) 2001 194,232 123,000 - 100,009 22,500 - -
Gary A. Long 2003 185,154 140,000 2,643 65,002 - - 5,555
President and Chief
Operating Officer 2002 178,154 70,000 - - 8,100 - 5,345
of PSNH
(PSNH Table Only) 2001 171,846 55,000 - - 6,750 - 5,100
Kerry J. Kuhlman 2003 180,015 125,000 2,542 62,499 - - 5,400
President and Chief
Operating Officer 2002 173,093 62,000 - - 7,900 - 5,193
of WMECO
(WMECO Table Only) 2001 166,846 45,000 - - 6,200 - 5,005
---------------------------------------------------------------------------------------------------------------
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AGGREGATED OPTIONS/SAR EXERCISES IN LAST
FISCAL YEAR AND FY-END OPTION/SAR VALUES
------------------------------------------------------------------------------------------------------------------
Shares With
Respect to Number of Securities Value of Unexercised
Which Underlying Unexercised In-the-Money
Options Were Value Options/SARs Options/SARs
Exercised Realized at Fiscal Year End (#) at Fiscal Year End ($)
Name (#) ($) Exercisable Unexercisable Exercisable Unexercisable
------------------------------------------------------------------------------------------------------------------
Michael G. Morris 150,000 994,650 863,124 660,402 4,812,597 1,952,103
John H. Forsgren 81,919 153,940 83,464 68,936 33,598 60,048
Cheryl W. Grise - - 119,492 51,736 217,469 43,809
Gregory B. Butler 15,716 55,726 18,466 11,334 22,589 13,992
Leon J. Olivier - - 9,967 9,933 6,847 11,294
Gary A. Long - - 20,399 7,651 46,669 8,586
Kerry J. Kuhlman - - 21,529 7,335 50,850 8,375
------------------------------------------------------------------------------------------------------------------
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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 $8,830 in non-qualified pension payments in accordance with his employment agreement.
LONG-TERM INCENTIVE PLANS - AWARDS IN LAST FISCAL YEAR
Grants of performance units were made during 2003 under the Northeast Utilities Incentive Plan to the Company's officers. Payments will be made in cash following the close of the performance period. Threshold, target, and maximum payouts will be determined based on net income over the performance period. Grants to the executive officers named in the Summary Compensation Table were as follows:
Estimated Future Payouts
Under Non-Stock Price-Based Plans
---------------------------------
(a) (b) (c) (d) (e) (f)
Number of Performance
Shares, or Other
Units or Period Until
Other Maturation
Rights Or Payout Threshold Target Maximum
Name (#) ($) ($) ($)
----- -------- ------------------- --------- ------ -------
Michael G. Morris 10,450 1/1/2003-12/31/2005 418,000 1,045,000 1,463,000
John H. Forsgren 4,275 1/1/2003-12/31/2005 171,000 427,500 598,500
Cheryl W. Grise 3,250 1/1/2003-12/31/2005 130,000 325,000 455,000
Gregory B. Butler 1,100 1/1/2003-12/31/2005 44,000 110,000 154,000
Leon J. Olivier 785 1/1/2003-12/31/2005 31,400 78,500 109,900
Gary A. Long 650 1/1/2003-12/31/2005 26,000 65,000 91,000
Kerry J. Kuhlman 625 1/1/2003-12/31/2005 25,000 62,500 87,500
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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
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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
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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. 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%
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(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:
--------------------------------------------------------------------------------------------------
Number of securities
Number of securities Weighted-average remaining available for
to be issued upon exercise price of future issuance under
exercise of outstanding equity compensation plans
outstanding options, options, warrants (excluding securities
Plan Category warrants and rights and rights reflected in column (a))
--------------------------------------------------------------------------------------------------
(a) (b) (c)
--------------------------------------------------------------------------------------------------
Equity 3,225,593 $17.033 See Note 1
compensation
plans approved by
security holders
Equity 350,000 $ 9.625 None
compensation
plans not
approved by
security holders
Total 3,575,593 $16.308 See Note 1
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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. 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. 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. 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.
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
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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.
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
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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.
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
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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.
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)
2003 2002
--------- ---------
ASSETS
------
Current Assets:
Cash $ - $ 625
Notes receivable from affiliated companies 259,600 289,100
Notes and accounts receivable 3,116 551
Receivables from affiliated companies 1,973 2,620
Taxes receivable 2,314 -
Prepayments 313 73
---------- ----------
267,316 292,969
Deferred Debits and Other Assets:
Investments in subsidiary companies, at equity 2,544,819 2,322,902
Other 14,565 18,159
---------- ----------
2,559,384 2,341,061
---------- ----------
Total Assets $2,826,700 $2,634,030
========== ==========
LIABILITIES AND CAPITALIZATION
------------------------------
Current Liabilities:
Notes payable to banks $ 65,000 $ 49,000
Long-term debt - current portion 24,000 23,000
Accounts payable 1,834 2,285
Accounts payable to affiliated companies 25 290
Accrued taxes - 2,460
Accrued interest 6,048 5,883
Derivative liabilities 3,576 -
Other 346 363
---------- ----------
100,829 83,281
---------- ----------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 4,261 6,087
Other 1,375 141
---------- ----------
5,636 6,228
---------- ----------
Capitalization:
Long-Term Debt 456,115 334,000
---------- ----------
Common Shareholders' Equity:
Common shares, $5 par value - authorized
225,000,000 shares; 150,398,403 shares issued and
127,695,999 shares outstanding in 2003 and
149,375,847 shares issued and
127,562,031 outstanding in 2002 751,992 746,879
Capital surplus, paid in 1,108,924 1,108,338
Deferred contribution plan - employee stock
stock ownership plan (73,694) (87,746)
Retained earnings 808,932 765,611
Accumulated other comprehensive income 25,991 14,927
Treasury stock (358,025) (337,488)
---------- ----------
Common Shareholders' Equity 2,264,120 2,210,521
---------- ----------
Total Capitalization 2,720,235 2,544,521
---------- ----------
Total Liabilities and Capitalization $2,826,700 $2,634,030
========== ==========
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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)
2003 2002 2001
------------- ------------- ------------
Operating Revenues $ - $ - $ -
------------- ------------- ------------
Operating Expenses:
Other 7,720 12,787 11,917
------------- ------------- ------------
Operating Loss (7,720) (12,787) (11,917)
------------- ------------- ------------
Interest Expense 22,186 30,630 32,696
------------- ------------- ------------
Other Income/(Loss):
Equity in earnings of subsidiaries 123,647 158,191 188,783
Gain related to sale of nuclear plants - 14,255 147,935
Loss on share repurchase contracts - - (35,394)
Other, net 11,041 13,002 10,863
------------- ------------- ------------
Other Income, Net 134,688 185,448 312,187
------------- ------------- ------------
Income Before Income Tax (Benefit)/Expense 104,782 142,031 267,574
Income Tax (Benefit)/Expense (11,629) (10,078) 24,064
------------- ------------- ------------
Earnings for Common Shares $ 116,411 $ 152,109 $ 243,510
============= ============= ============
Basic Earnings Per Common Share $ 0.91 $ 1.18 $ 1.80
============= ============= ============
Fully Diluted Earnings Per Common Share $ 0.91 $ 1.18 $ 1.79
============= ============= ============
Basic Common Shares Outstanding (average) 127,114,743 129,150,549 135,632,126
============= ============= ============
Fully Diluted Common Shares Outstanding (average) 127,240,724 129,341,360 135,917,423
============= ============= ============
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SCHEDULE I
NORTHEAST UTILITIES (PARENT)
FINANCIAL INFORMATION OF REGISTRANT
STATEMENTS OF CASH FLOWS
AT DECEMBER 31, 2003, 2002 AND 2001
(Thousands of Dollars)
2003 2002 2001
------------ ----------- ----------
Operating Activities:
Net income $ 116,411 $ 152,109 $ 243,510
Adjustments to reconcile to net cash flows
provided by operating activities:
Equity in earnings of subsidiary companies (123,647) (158,191) (188,783)
Deferred income taxes (411) (565) (233)
Other sources of cash 15,286 16,504 40,747
Other uses of cash (8,492) (5,011) (4,225)
Changes in current assets and liabilities:
Receivables, net (1,918) 19,097 (24,295)
Other current assets (excludes cash) (6,130) 1,020 2,651
Accounts payable (716) (24,197) 25,788
Accrued taxes (2,460) 2,211 (886)
Other current liabilities 17,340 51,132 (38,709)
------------ ---------- ----------
Net cash flows provided by operating activities 5,263 54,109 55,565
------------ ---------- ----------
Investing Activities:
NU system Money Pool borrowing/(lending) 29,500 (164,300) (30,400)
Investment in subsidiaries (213,191) 102,019 396,257
Payment for acquisitions, net of cash acquired - - (25,823)
Cash dividends received from subsidiary companies 114,921 126,154 120,072
Other investment activities 3,782 1,595 1,415
------------ ---------- ----------
Net cash flows (used in)/provided by investing activities (64,988) 65,468 461,521
------------ ---------- ----------
Financing Activities:
Issuance of common shares 13,654 7,458 1,751
Repurchase of common shares (20,537) (57,800) (291,789)
Increase/(decrease) in short-term debt 16,000 9,000 (396,000)
Issuance of long-term debt 150,000 263,000 263,000
Reacquisitions and retirements of long-term debt (23,000) (286,000) (21,000)
Cash dividends on common shares (73,090) (67,793) (60,923)
Other financing activities (3,927) - -
------------ ---------- ----------
Net cash flows provided by/(used in) financing activities 59,100 (132,135) (504,961)
------------ ---------- ----------
Net (decrease)/increase in cash (625) (12,558) 12,125
Cash - beginning of year 625 13,183 1,058
------------ ---------- ----------
Cash - end of year $ - $ 625 $ 13,183
============ ========== ==========
Supplemental Cash Flow Information:
Cash paid/(refunded) during the year for:
Interest, net of amounts capitalized $ 21,496 $ 25,213 $ 35,453
============ ========== ==========
Income taxes $ (16,818) $ (10,677) $ 32,126
============ ========== ==========
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NORTHEAST UTILITIES AND SUBSIDIARIES SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 2003
(Thousands of Dollars)
-------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
----------------------
(1) (2)
Charged to
Balance at Charged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
-------------------------------------------------------------------------------------------------
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $15,425 $23,229 $17,205 (a) $15,013 (b) $40,846
======= ======= ======= ======= =======
RESERVES NOT APPLIED AGAINST ASSETS:
Operating reserves $67,127 $17,688 $ - $16,157 (c) $68,658
======= ======= ======= ======= =======
(a) Amount relates to regulatory assets recorded in conjunction with the bankruptcy of NRG
and certain of its subsidiaries and to uncollectible amounts reserved for related to
capital projects and New Hampshire's low income assistance program.
(b) Amounts written off, net of recoveries.
(c) Principally payments for environmental remediation, various injuries and damages,
employee medical expenses, inventory reserves and expenses in connection therewith.
|
NORTHEAST UTILITIES AND SUBSIDIARIES SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 2002
(Thousands of Dollars)
-------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
----------------------
(1) (2)
Charged to
Balance at Charged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
-------------------------------------------------------------------------------------------------
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $16,353 $16,590 $ - $17,518 (a) $15,425
======= ======= ======= ======= =======
RESERVES NOT APPLIED AGAINST ASSETS:
Operating reserves $69,085 $18,959 $ - $20,917 (b) $67,127
======= ======= ======= ======= =======
(a) Amounts written off, net of recoveries.
(b) Principally payments for environmental remediation, various injuries and damages, employee
medical expenses, and expenses in connection therewith.
|
NORTHEAST UTILITIES AND SUBSIDIARIES SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 2001
(Thousands of Dollars)
-------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
----------------------
(1) (2)
Charged to
Balance at Charged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
-------------------------------------------------------------------------------------------------
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $12,500 $15,947 $ - $12,094 (a) $16,353
======= ======= ======= ======= =======
RESERVES NOT APPLIED AGAINST ASSETS:
Operating reserves $79,281 $25,936 $ - $36,132 (b) $69,085
======= ======= ======= ======= =======
(a) Amounts written off, net of recoveries.
(b) Principally payments for environmental remediation, various injuries and
damages, employee medical expenses, and expenses in connection therewith.
|
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 2003
(Thousands of Dollars)
-------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
----------------------
(1) (2)
Charged to
Balance at Charged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
-------------------------------------------------------------------------------------------------
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 525 $ 5,164 $16,924 (a) $ 823 (b) $21,790
======= ======= ======= ======= =======
RESERVES NOT APPLIED AGAINST ASSETS:
Operating reserves $18,241 $ 9,712 $ - $ 6,589 (c) $21,364
======= ======= ======= ======= =======
(a) Amount relates to regulatory assets recorded in conjunction with the bankruptcy of NRG
and certain of its subsidiaries and to uncollectible amounts reserved for related to
capital projects.
(b) Amounts written off, net of recoveries.
(c) Principally payments for environmental remediation, various injuries and damages, employee
medical expenses, inventory reserves and expenses in connection therewith.
|
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 2002
(Thousands of Dollars)
-------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
----------------------
(1) (2)
Charged to
Balance at Charged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
-------------------------------------------------------------------------------------------------
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 525 $ 398 $ - $ 398 (a) $ 525
======= ======= ======= ======= =======
RESERVES NOT APPLIED AGAINST ASSETS:
Operating reserves $11,387 $13,755 $ - $ 6,901 (b) $18,241
======= ======= ======= ======= =======
(a) Amounts written off, net of recoveries.
(b) Principally payments for environmental remediation, various injuries and damages,
employee medical expenses, and expenses in connection therewith.
|
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 2001
(Thousands of Dollars)
-------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
----------------------
(1) (2)
Charged to
Balance at Charged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
-------------------------------------------------------------------------------------------------
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 300 $ 551 $ - $ 326 (a) $ 525
======= ======= ======= ======= =======
RESERVES NOT APPLIED AGAINST ASSETS:
Operating reserves $13,660 $ 5,735 $ - $ 8,008 (b) $11,387
======= ======= ======= ======= =======
(a) Amounts written off, net of recoveries.
(b) Principally payments for environmental remediation, various injuries and damages,
employee medical expenses, and expenses in connection therewith.
|
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 2003
(Thousands of Dollars)
-------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
----------------------
(1) (2)
Charged to
Balance at Charged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
-------------------------------------------------------------------------------------------------
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 1,990 $ 1,379 $ 102 (a) $ 1,881 (b) $ 1,590
======= ======= ======= ======= =======
RESERVES NOT APPLIED AGAINST ASSETS:
Operating reserves $14,089 $ 2,585 $ - $ 3,106 (c) $13,568
======= ======= ======= ======= =======
(a) Amount relates to regulatory assets recorded in conjunction with uncollectible amounts
reserved for related to New Hampshire's low income assistance program.
(b) Amounts written off, net of recoveries.
(c) Principally payments for environmental remediation, various injuries and damages,
employee medical expenses, and expenses in connection therewith.
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PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 2002
(Thousands of Dollars)
-------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
----------------------
(1) (2)
Charged to
Balance at Charged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
-------------------------------------------------------------------------------------------------
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 1,736 $ 1,840 $ - $ 1,586 (a) $ 1,990
======= ======= ======= ======= =======
RESERVES NOT APPLIED AGAINST ASSETS:
Operating reserves $13,842 $ 3,088 $ - $ 2,841 (b) $14,089
======= ======= ======= ======= =======
(a) Amounts written off, net of recoveries.
(b) Principally payments for environmental remediation, various injuries and damages,
employee medical expenses, and expenses in connection therewith.
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PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 2001
(Thousands of Dollars)
-------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
----------------------
(1) (2)
Charged to
Balance at Charged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
-------------------------------------------------------------------------------------------------
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 1,869 $ 1,787 $ - $ 1,920 (a) $ 1,736
======= ======= ======= ======= =======
RESERVES NOT APPLIED AGAINST ASSETS:
Operating reserves $11,650 $ 7,393 $ - $ 5,201 (b) $13,842
======= ======= ======= ======= =======
(a) Amounts written off, net of recoveries.
(b) Principally payments for environmental remediation, various injuries and damages,
employee medical expenses, and expenses in connection therewith.
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WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 2003
(Thousands of Dollars)
-------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
----------------------
(1) (2)
Charged to
Balance at Charged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
-------------------------------------------------------------------------------------------------
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 1,958 $ 4,107 $ 179 (a) $ 3,693 (b) $ 2,551
======= ======= ======= ======= =======
RESERVES NOT APPLIED AGAINST ASSETS:
Operating reserves $ 2,855 $ 1,501 $ - $ 1,385 (c) $ 2,971
======= ======= ======= ======= =======
(a) Amounts relates to uncollectible amounts reserved for related to capital projects.
(b) Amounts written off, net of recoveries.
(c) Principally payments for environmental remediation, various injuries and damages,
employee medical expenses, and expenses in connection therewith.
|
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 2002
(Thousands of Dollars)
-------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
----------------------
(1) (2)
Charged to
Balance at Charged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
-------------------------------------------------------------------------------------------------
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 2,028 $ 2,755 $ - $ 2,825 (a) $ 1,958
======= ======= ======= ======= =======
RESERVES NOT APPLIED AGAINST ASSETS:
Operating reserves $ 7,506 $ 1,598 $ - $ 6,249 (b) $ 2,855
======= ======= ======= ======= =======
(a) Amounts written off, net of recoveries.
(b) Principally payments for environmental remediation, various injuries and damages,
employee medical expenses, and expenses in connection therewith.
|
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 2001
(Thousands of Dollars)
-------------------------------------------------------------------------------------------------
Column A Column B Column C Column D Column E
Additions
----------------------
(1) (2)
Charged to
Balance at Charged to other Balance
beginning costs and accounts- Deductions- at end
Description of period expenses describe describe of period
-------------------------------------------------------------------------------------------------
RESERVES DEDUCTED FROM ASSETS
TO WHICH THEY APPLY:
Reserves for uncollectible accounts $ 1,886 $ 2,887 $ - $ 2,745 (a) $ 2,028
======= ======= ======= ======= =======
RESERVES NOT APPLIED AGAINST ASSETS:
Operating reserves $ 6,760 $ 3,767 $ - $ 3,021 (b) $ 7,506
======= ======= ======= ======= =======
(a) Amounts written off, net of recoveries.
(b) Principally payments for environmental remediation, various injuries and damages,
employee medical expenses, and expenses in connection therewith.
|
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)
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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)
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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)
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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).
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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)
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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)
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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)
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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)
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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)
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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)
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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).
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(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)
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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
EXHIBIT 13.1
ANNUAL REPORT OF NORTHEAST UTILITIES
MANAGEMENT'S DISCUSSION AND ANALYSIS
OVERVIEW
Consolidated: Northeast Utilities and subsidiaries (NU or the company)
reported 2003 earnings of $116.4 million, or $0.91 per share, compared with
earnings of $152.1 million, or $1.18 per share, in 2002 and $243.5 million,
or $1.79 per share, in 2001. All earnings per share (EPS) amounts are
reported on a fully diluted basis.
The 2003 earnings of $116.4 million, or $0.91 per share include a charge of $36.9 million, or $0.29 per share, associated with a loss recorded for the settlement of a wholesale power contract dispute between The Connecticut Light and Power Company (CL&P) and its three 2003 standard offer power suppliers, including an NU subsidiary, Select Energy, Inc. For more information about this contract dispute and the settlement, see the "Impacts of Standard Market Design" section of this Management's Discussion and Analysis. Also included in 2003 earnings was a negative $4.7 million after- tax cumulative effect of an accounting change as a result of the adoption of Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 46, "Consolidation of Variable Interest Entities." Excluding the effects of these two items, net income would have been $158 million, or $1.24 per share.
NU's 2003 results benefited from improved performance at NU Enterprises and lower corporate-wide interest costs. The better performance at NU Enterprises reflected improved margins on Select Energy, Inc.'s (Select Energy) energy supply contracts, higher volumes, improved operation of NU Enterprises' generating facilities, and the absence of natural gas trading losses that occurred in the first half of 2002. Those factors were offset by lower pension income and the absence of earnings related to the Seabrook nuclear unit (Seabrook).
During 2003, pre-tax pension income for NU declined $41.6 million, from a credit of $73.4 million in 2002 to a credit of $31.8 million in 2003. Of the $31.8 million and $73.4 million of pension credits recorded during 2003 and 2002, $16.4 million and $47.2 million, respectively, were recognized in the consolidated statements of income as reductions to operating expenses. The remaining $15.4 million in 2003 and $26.2 million in 2002 relate to employees working on capital projects and were reflected as reductions to capital expenditures. The pre-tax $30.8 million decrease in pension income that reduces operating expenses was reflected evenly throughout 2003, resulting in a decline of $4.6 million in net income per quarter during 2003.
NU's EPS also benefited modestly from a share repurchase program. In the first quarter of 2003, NU repurchased approximately 1.5 million of its shares at an average price of $13.73. There were no share repurchases during the remainder of 2003. On May 13, 2003, the company's Board of Trustees authorized the repurchase of up to 10 million shares through July 1, 2005. NU had 127.7 million shares outstanding at December 31, 2003.
NU's revenues for 2003 increased to $6.1 billion from $5.2 billion in 2002, or an increase of $0.9 billion. Of the $0.9 billion increase in NU's revenues, $0.8 billion related to NU Enterprises. NU Enterprises' revenues in 2003 increased primarily due to higher wholesale and retail sales volumes of $0.4 billion and higher prices of $0.3 billion. The increase in revenues is also due to increases in electric sales at the Utility Group in 2003 as compared to 2002.
Earnings decreased $91.4 million for the year ended December 31, 2002 as compared to 2001. This decrease is primarily the result of several items recorded in 2001, including an after-tax gain of $115.6 million, or $0.85 per share associated with the sale of the Millstone nuclear units (Millstone), offset by an after-tax loss of $22.4 million, or $0.17 per share related to the adoption of Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended, and a charge of $35.4 million, or $0.26 per share related to an agreement with two financial institutions to repurchase NU common shares. This earnings decrease is also attributable to after-tax losses totaling $11 million, or $0.09 per share recorded in 2002, associated with the write-down of investments in NEON Communications, Inc. (NEON) and Acumentrics Corporation (Acumentrics), offset by after-tax gains totaling $24.5 million, or $0.19 per share, associated with the sale of Seabrook, which were also recorded in 2002.
Utility Group: Earnings at all of NU's Utility Group subsidiaries were lower in 2003 as compared with 2002. The Utility Group is comprised of CL&P, Public Service Company of New Hampshire (PSNH), Western Massachusetts Electric Company (WMECO), North Atlantic Energy Corporation (NAEC), and Yankee Gas Services Company (Yankee Gas). Utility Group net income was lower due to the absence of approximately $13 million of investment tax credits (ITC) that were reflected in the second quarter of 2002 at WMECO, as well as lower pension income and the loss of earnings related to Seabrook. Lower pension income and the lack of Seabrook earnings resulted in a net income decrease in 2003 as compared to 2002 of $18.4 million and $16.3 million, respectively. These decreases were partially offset by lower Utility Group controllable operation and maintenance costs.
As a result of an adjustment to estimated unbilled electric revenues resulting from a process to validate and update the assumptions used to estimate unbilled revenues, 2003 Utility Group retail electric sales increased 3.6 percent compared to 2002. Absent that adjustment, Utility Group retail electric sales increased 2.1 percent. Adjustments to estimated unbilled revenues had a negative impact on Yankee Gas. Yankee Gas firm gas sales decreased 0.6 percent in 2003 as compared to 2002. Absent those adjustments, Yankee Gas firm gas sales increased 7.8 percent. Combined, the adjustments to estimated unbilled revenues increased NU's net income by approximately $4.6 million for 2003. For further information regarding the estimate of unbilled revenues, see "Critical Accounting Policies and Estimates - Utility Group Unbilled Revenues," included in this Management's Discussion and Analysis.
CL&P earnings before preferred dividends totaled $68.9 million in 2003, compared with $85.6 million in 2002. The lower income was primarily attributable to lower pension income, after-tax write-offs of approximately $5 million related to a distribution rate case that was decided in December 2003, and a loss of approximately $1 million recorded for the settlement of the wholesale power contract dispute.
PSNH earned $45.6 million in 2003, compared with $62.9 million in 2002. The decline in earnings is due to a lower level of regulatory assets earning a return, the positive resolution of certain contingencies related to a regulatory proceeding decided in 2002, and higher pension costs. Also, as a result of the sale of Seabrook, earnings at NAEC were essentially eliminated in 2003, compared with earnings of $26.3 million for 2002. NAEC's 2002 earnings included $13.9 million related to the elimination of reserves associated with its ownership share of Seabrook assets.
WMECO earnings were $16.2 million in 2003 compared to $37.7 million in 2002. The decline in earnings related primarily to the recognition of $13 million of ITC in the second quarter of 2002 and to the positive financial impact of an approval of a regulatory settlement in the fourth quarter of 2002.
Yankee Gas earned $7.3 million in 2003, compared with $17.6 million in 2002. Yankee Gas earnings were reduced by $6.2 million in 2003 as a result of both the aforementioned downward adjustments in estimated unbilled revenues and certain gas cost adjustments.
NU Enterprises: NU Enterprises, Inc. is the parent company of Select Energy, Northeast Generation Company (NGC), Select Energy Services, Inc. (SESI), Northeast Generation Services Company (NGS), and their respective subsidiaries, and Woods Network Services, Inc. (Woods Network), all of which are collectively referred to as "NU Enterprises." The generation operations of Holyoke Water Power Company (HWP) are also included in the results of NU Enterprises. The companies included in the NU Enterprises segment are grouped into two business lines: the merchant energy business line and the energy services business line.
The financial performance of NU Enterprises improved in 2003, losing $3.5 million, or $0.03 per share, compared with losses of $53.2 million, or $0.41 per share in 2002 and earnings of $6.1 million, or $0.05 per share in 2001, prior to the negative cumulative effect of an accounting change associated with the adoption of SFAS No. 133. The 2003 loss of $3.5 million includes an after-tax loss of approximately $36 million, or $0.28 per share, related to Select Energy's share of the cost of settling the contract dispute between affiliate CL&P and its suppliers over the responsibility for costs related to the March 2003 implementation of Standard Market Design (SMD) in New England. The settlement was filed with the Federal Energy Regulatory Commission (FERC) on March 3, 2004 and is expected to be approved by the FERC in the first half of 2004. Excluding the settlement loss, NU Enterprises earned $32.2 million or $0.25 per share.
NU Enterprises' net income improved due to increased margins on wholesale and retail contracts, improved performance at NGC, which owns nearly 1,300 megawatts (MW) of primarily hydroelectric and pumped storage generating capacity in Massachusetts and Connecticut, and the absence of natural gas trading losses in 2003. Natural gas trading positions in the first half of 2002 resulted in $17.6 million of trading losses. Over the past year, Select Energy has significantly reduced its trading activities, which are now limited primarily to price discovery and transaction and risk management for the merchant energy business line.
FUTURE OUTLOOK
Consolidated: NU estimates that it will earn between $1.20 per share and
$1.40 per share in 2004, including approximately $0.10 per share of parent
company interest and other expenses.
In 2004, NU is projecting to record pre-tax pension expense of $2.9 million. Pension expense is annually adjusted during the second quarter based on updated actuarial valuations, and the 2004 estimate may change.
Utility Group: The NU consolidated earnings estimate of $1.20 per share to $1.40 per share includes Utility Group earnings of between $1.08 per share and $1.20 per share. The range reflects uncertainties over the outcome of a pending PSNH rate case before the New Hampshire Public Utilities Commission (NHPUC) and the outcome of the NU transmission rate case before the FERC. Management expects both cases to be decided in the second half of 2004. The earnings range also reflects a continued reduction in pension income.
NU Enterprises: NU projects that the financial performance of NU Enterprises will continue to improve in 2004. The NU consolidated earnings range of $1.20 per share to $1.40 per share for 2004 reflects projected earnings of between $0.22 per share and $0.30 per share at NU Enterprises.
LIQUIDITY
Consolidated: After four years of reducing its indebtedness, NU's total
debt, excluding rate reduction bonds, rose to $2.7 billion at the end of
2003, compared with $2.4 billion at the end of 2002. The higher debt levels
reflect the issuance of new debt by NU parent, WMECO and SESI during 2003, as
well as a $49 million increase in borrowings on NU's revolving credit lines.
NU parent sold $150 million of notes at a coupon rate of 3.3 percent during
2003. These notes mature in 2008. The proceeds from this issuance were
primarily used to refinance Select Energy's short-term debt.
At December 31, 2003, NU had $105 million in notes payable to banks, compared with $56 million of notes payable to banks at December 31, 2002. In addition, NU had $83.7 million of cash, including cash and cash equivalents and unrestricted cash from counterparties at December 31, 2003, compared with $67.2 million at December 31, 2002.
NU's net cash flows provided by operating activities totaled $573.6 million in 2003 as compared to $589.7 million in 2002 and $302.4 million in 2001. Cash flows provided by operating activities in 2003 decreased due to decreases in working capital items, primarily accounts payable and accrued taxes. Accrued taxes decreased as the taxes related to the 2002 sale of Seabrook were paid in March of 2003. Accounts payable decreased as a result of the timing of payments on amounts outstanding at NU Enterprises. The decreases in these working capital items were offset by an increase in regulatory overrecoveries in 2003 as compared to 2002, primarily associated with CL&P's Competitive Transition Assessment (CTA), Generation Service Charge (GSC) and System Benefits Charge (SBC), as well as PSNH's Stranded Cost Recovery Charge (SCRC). For a description of the costs recovered through these mechanisms, see Note 1H - "Summary of Significant Accounting Policies - Utility Group Regulatory Accounting," to the consolidated financial statements.
Cash flows provided by operating activities in 2002 increased due to increases in working capital items, primarily accrued taxes, offset by a reduction in net income, primarily due to the gain associated with the sale of Millstone in 2001. Accrued taxes increased due to the taxable gain on the sale of Seabrook. Those taxes were not paid until March of 2003. The increase in cash flows provided by operating activities in 2002 related primarily to more collections of receivables and unbilled revenues in 2002 compared to 2001 associated with the sales growth of NU Enterprises.
NU projects that cash flows provided by operating activities will decline significantly in 2004 from 2003, even if net income increases, as a result of expected refunds to CL&P's customers or applications of previous overcollections to current costs as a result of recent regulatory decisions.
There was a lower level of investing and financing activity in 2003 as compared to 2002, which was primarily due to the sale of Seabrook, the acquisition of Woods Electrical Co., Inc. (Woods Electrical) and Woods Network and the issuance of rate reduction bonds in 2002. Cash flows used for investments in plant increased to $550 million in 2003 from $485 million in 2002 and $451.4 million in 2001 as a result of increased levels of capital expenditures at the Utility Group. NU expects capital expenditures to reach $738 million in 2004.
There was a lower level of investing and financing activity in 2002 as
compared to 2001, primarily due to the following items that occurred in 2001:
the issuance of long-term debt, the issuance of rate reduction bonds, the
use of proceeds from the sale of Millstone, the buyout and buydown of
independent power producer (IPP) contracts, the retirement of preferred stock
and other preferred securities and the retirement of certain other capital
lease obligations.
The retirement of rate reduction bonds does not equal the amortization of rate reduction bonds because the retirement represents principal payments, while the amortization represents amounts recovered from customers for future principal payments. The timing of recovery does not exactly match the expected principal payments.
Aside from the rate reduction bonds outstanding, NU has a modest level of sinking fund payments and debt maturities due between 2004 and 2011, averaging $56.3 million annually and totaling $64.9 million in 2004. Most of the debt that must be repaid during that time was issued by NU parent, NGC, Yankee Gas, and SESI. No CL&P, PSNH or WMECO debt issues mature during that eight-year period.
The level of common dividends totaled $73.1 million in 2003, compared with $67.8 million in 2002 and $60.9 million in 2001. The 2003 increase resulted from NU paying a dividend of $0.1375 per share in the first two quarters of 2003 and $0.15 per share in the second two quarters of 2003. The level of dividends in 2002 was $0.125 per share in the first two quarters and $0.1375 per share in the second two quarters. Management expects to continue to increase the dividend level, subject to NU's ability to meet earnings targets and the judgment of its Board of Trustees at the time dividends are declared. In recent years, NU's Trustees have addressed dividend increases at the company's annual meeting, the next of which is on May 11, 2004. On January 12, 2004, the NU Board of Trustees approved the payment of a dividend of $0.15 per share on March 31, 2004, to shareholders of record at March 1, 2004.
Overall liquidity remained high at December 31, 2003, despite the increase in the common dividend and the repurchase of 1.5 million shares in 2003 at a cost of $20.5 million, due primarily to cash earnings from the Utility Group subsidiaries. NU's liquidity was also strengthened by the aforementioned issuance of $150 million in notes by NU parent.
Excluding rate reduction bonds as they are non-recourse to NU, NU's consolidated capitalization was comprised of 46 percent common shareholders' equity, and 54 percent preferred stock and long-term debt at December 31, 2003, as compared with 47 percent common shareholders' equity and 53 percent preferred stock and long-term debt at December 31, 2002. As a result of the Utility Group's proposed expansion plans, management expects capital requirements to increase over the next several years but will continue to target a 45 percent equity and 55 percent debt capitalization structure.
Utility Group: NU's higher debt levels reflect the sale of $55 million of 10- year senior unsecured notes by WMECO on September 30, 2003, at a coupon rate of 5.0 percent. WMECO used the proceeds from this debt issue to reduce its level of short-term borrowings from the NU Money Pool. On October 1, 2003, CL&P fixed the interest rate on $62 million of variable-rate, tax-exempt notes for five years at 3.35 percent. These notes mature in 2031. On January 30, 2004, Yankee Gas closed on the private placement of $75 million of 10-year first-mortgage bonds carrying an interest rate of 4.8 percent. The proceeds from these bonds were used to reduce short-term debt.
By the end of 2003, NU had completed the first stage of a comprehensive restructuring of its business profile. For CL&P that marked the sale of all electric generation in the period of 1999 through 2002 and the recovery of almost all of its unsecuritized stranded costs. The sale of assets and recovery of stranded costs have provided CL&P with extremely strong cash flows over the past five years. Those proceeds allowed CL&P to repay more than half of its debt and preferred securities and to return hundreds of millions of dollars of equity capital to NU. CL&P has not issued any new long-term debt since mid-1997. Aided by relatively low cost power supply contracts from 2000 through 2003, CL&P was able to maintain retail rates that were relatively low for New England and generally 10 percent below those charged by CL&P in 1996.
The year 2004, however, will show a significant change in CL&P's financial statements, even if net income remains relatively stable. The settlement of the dispute between CL&P and its standard offer service suppliers over a portion of the incremental costs incurred following the implementation of SMD on March 1, 2003, will have a significant negative impact on CL&P's cash flows in 2004 as compared to 2003. In 2003, CL&P was withholding payment of a portion of the incremental SMD costs from suppliers pending resolution but was recovering the costs from ratepayers at the same time. Through January 31, 2004, CL&P collected approximately $155 million from customers. Of this amount, $31.1 million was used in CL&P's operating cash flows and is secured by a surety bond. The remaining $124 million was deposited into an escrow account, and escrow account deposits through December 31, 2003 were $93.6 million and are included in restricted cash - LMP costs on the accompanying consolidated balance sheets. As a result of the settlement, CL&P will pay approximately $83 million to suppliers and return the remainder to its customers.
Another significant negative impact to CL&P's cash flows will be the refund of previously overcollected stranded costs to CL&P's customers. The Connecticut Department of Public Utility Control (DPUC) stated in CL&P's transitional standard offer (TSO) docket that CL&P should either refund $262 million of overcollections back to customers or use these overcollections to pay for cash expenses over the next four years, beginning in 2004.
These refunds or applications of past cash collections to future expenses, combined with CL&P's capital expansion program, will require CL&P to issue debt securities and receive equity infusions from NU parent over the next several years. CL&P is expected to issue up to $250 million of first mortgage bonds in 2004.
CL&P will continue to increase its distribution and transmission construction program to meet Connecticut's electric service reliability needs. CL&P projects capital spending of approximately $440 million in 2004, compared with $314.6 million in 2003 and $239.6 million in 2002. Over time, the capital program will add to CL&P's asset base and net income.
Under FERC policy, transmission owners cannot bill customers for new plant until it enters service. However, transmission owners may capitalize debt and equity costs during the construction period through an allowance for funds used during construction (AFUDC). Debt costs capitalized offset interest expense with no impact on net income, while equity costs capitalized increase net income. CL&P expects to fund its construction expenditures with approximately 45 percent equity and 55 percent debt. As a result of the size of the projects and the duration of the construction, a growing level of CL&P's earnings over the next four years is expected to be in the form of equity-related AFUDC. While the return on and recovery of the capitalized debt and equity AFUDC benefits earnings and cash flows after the projects enter service, AFUDC has no positive effect on cash flows until the projects are reflected in rates.
Capital spending at PSNH totaled $105.6 million in 2003, compared with $108.7 million in 2002. In 2003, PSNH spent over $20 million to buy down contracts with 14 small power producers and funded $30.1 million to acquire the assets of Connecticut Valley Electric Company (CVEC) and buy out a related wholesale power contract. The $30.1 million was placed in escrow at December 31, 2003 and is included in special deposits on the accompanying consolidated balance sheets. PSNH expects to increase its capital spending to approximately $160 million in 2004, assuming it receives satisfactory regulatory approval for a $70 million conversion of a 50 megawatt generating unit at its Schiller Station to burn wood chips. Such a level of spending is likely to require PSNH to issue in 2004 its first new debt since it exited bankruptcy in 1991.
Yankee Gas has also been investing heavily in its infrastructure since it was acquired by NU in March 2000. In November 2003, Yankee Gas received regulatory support to build a 1.2 billion cubic foot natural gas storage facility in Waterbury, Connecticut. As a result of that project and other initiatives, Yankee Gas projects $60 million of capital expenditures in 2004, compared with $55.2 million in 2003.
In November 2003, the Utility Group renewed its $300 million credit line under terms similar to the previous arrangement that expired in November 2003. There were $40 million in borrowings outstanding on this credit line at December 31, 2003.
In addition to its revolving credit line, CL&P has an arrangement with a financial institution under which CL&P can sell up to $100 million of accounts receivable. At December 31, 2003 and 2002, CL&P had sold accounts receivable of $80 million and $40 million, respectively, to that financial institution. For more information on the sale of receivables, see "Off- Balance Sheet Arrangements" in this Management's Discussion and Analysis and Note 1P, "Summary of Significant Accounting Policies - Sale of Customer Receivables" to the consolidated financial statements.
In November 2003, CL&P received approval from its preferred shareholders for an extension of a 10-year waiver that allows CL&P's unsecured debt to rise to 20 percent of total capitalization. CL&P preferred shareholders approved a similar waiver in 1993 that will expire in March 2004. The approval waives a requirement that unsecured debt represent no more than 10 percent of total capitalization.
Rate reduction bonds are included on the consolidated balance sheets of NU, CL&P, PSNH, and WMECO, even though the debt is non-recourse to these companies. At December 31, 2003, these companies had a total of $1.7 billion in rate reduction bonds outstanding, compared with $1.9 billion outstanding at December 31, 2002. All outstanding rate reduction bonds of CL&P are scheduled to amortize by December 30, 2010. PSNH's rate reduction bonds are scheduled to fully amortize by May 1, 2013, and those of WMECO are scheduled to fully amortize by June 1, 2013. Interest on the bonds totaled $108.4 million in 2003, compared with $115.8 million in 2002 and $87.6 million in 2001, the year of issuance. Cash flows from the amortization of rate reduction bonds totaled $153.2 million in 2003, compared with $148.6 million in 2002 and $98.4 million in 2001. Over the next several years, retirement of rate reduction bonds will increase, and interest payments will steadily decrease, resulting in no material changes to debt service costs on the existing issues. CL&P, PSNH and WMECO fully recover the amortization and interest payments from customers through stranded cost revenues each year, and the bonds have no impact on net income. Moreover, as the rate reduction bonds are non-recourse, the three rating agencies that rate the debt and preferred stock securities of these companies do not reflect the revenues, expenses, or outstanding securities related to the rate reduction bonds in establishing the credit ratings of these companies or of NU.
NU Enterprises: NU's higher debt levels reflect SESI borrowings of $63.4 million in 2003 to finance the implementation of energy saving improvements at customer facilities. Cash flows from SESI's share of customer energy savings will repay the debt. While NU parent guarantees SESI's performance under most of the contracts, NU parent does not guarantee repayment of the debt, nor is the debt recourse to NU parent.
Select Energy was one of CL&P's standard offer service suppliers that incurred incremental locational marginal pricing (LMP) costs during 2003. CL&P did not pay Select Energy for these costs, which negatively impacted the operating cash flows of NU Enterprises in 2003. If the FERC approves the settlement of the wholesale power contract dispute over the responsibility for LMP costs, then there will be a positive impact on NU Enterprises' cash flows in 2004.
In November 2003, NU parent renewed its $350 million credit line with terms similar to its previous arrangement that expired in November 2003. There were $65 million in borrowings outstanding on this credit line at December 31, 2003. In addition, Select Energy had $106.9 million in letters of credit outstanding under this credit line primarily to support its marketing activities.
NU Enterprises continues to have a minimal level of capital spending. In 2002, NU Enterprises acquired certain assets and assumed certain liabilities of Woods Electrical, an electrical services company, and Woods Network, a network design, products and service company. The acquisitions were for $16.3 million in cash. NU Enterprises made no other business acquisitions in 2002 or 2003.
IMPACTS OF STANDARD MARKET DESIGN
On March 1, 2003, the New England Independent System Operator (ISO-NE)
implemented SMD. As part of SMD, LMP is utilized to assign value and
causation to transmission congestion and line losses. Transmission congestion
costs represent the additional costs incurred due to the need to run uneconomic
generating units in certain areas that have transmission constraints, which
prevent these areas from obtaining alternative lower-cost generation. Line
losses represent losses of electricity as it is sent over transmission lines.
The costs associated with transmission congestion and line losses are now
assigned to the pricing zone in which they occur, and the calculation of line
losses is now based on an economic formula. Prior to March 1, 2003, those
costs were spread across virtually all New England electric customers based on
engineering data of actual line losses experienced. As part of the
implementation of SMD, ISO-NE established eight separate pricing zones in
New England: three in Massachusetts and one in each of the five other New
England states. The three components of the LMP for each zone are 1) an energy
cost, 2) congestion costs and 3) line loss charges assigned to the zone. LMP
is increasing costs in zones that have inadequate or less cost-efficient
generation and/or transmission constraints, such as Connecticut, and decreasing
costs in zones that have sufficient or excess generation, such as Maine.
CL&P was billed $186 million of incremental LMP costs by its standard offer service suppliers or by ISO-NE. CL&P recovered a portion of these costs through an additional charge on customer bills beginning on May 1, 2003. Billings were on a two-month lag and were recorded as operating revenues when billed. Amounts were recovered subject to refund.
CL&P and its suppliers, including affiliate Select Energy, disputed the responsibility for the $186 million of incremental LMP costs incurred. NU recorded a pre-tax loss in 2003 of approximately $60 million (approximately $37 million after-tax) related to the settlement of this dispute. A settlement agreement was reached among all the parties involved. This settlement agreement was filed with the FERC on March 3, 2004 and will not be final until the FERC approves it. Management expects to receive FERC approval in the first half of 2004.
The pre-tax loss of approximately $60 million was reflected in two line items on the consolidated statements of income. Approximately $58 million was recorded as a reduction to operating revenues, and approximately $2 million was recorded in operating expenses.
NRG ENERGY, INC. EXPOSURES
Certain subsidiaries of NU have entered into various transactions with
subsidiaries of NRG Energy, Inc. (NRG). On May 14, 2003, NRG and certain of
its subsidiaries filed voluntary bankruptcy petitions in the United States
Bankruptcy Court for the Southern District of New York. On December 5, 2003,
NRG emerged from bankruptcy. NRG-related exposures to certain subsidiaries
of NU as a result of these transactions are as follows:
Standard Offer Service Contract: NRG Power Marketing, Inc. (NRG-PMI) contracted with CL&P to supply 45 percent of CL&P's standard offer service load through December 31, 2003. In May 2003, NRG-PMI attempted to terminate the contract with CL&P, but the FERC ordered NRG-PMI to continue serving CL&P under its standard offer service contract. Subsequently, NRG-PMI received a temporary restraining order from the United States District Court for the Southern District of New York (District Court) and stopped serving CL&P with standard offer supply on June 12, 2003. NRG-PMI was ultimately ordered by the FERC and the District Court to resume serving CL&P's standard offer service load and did so on July 2, 2003. During the period NRG-PMI did not serve CL&P under its standard offer service contract, CL&P's net replacement power cost amounted to $8.5 million, which was collected by CL&P from its customers and withheld from standard offer service contract payments to NRG- PMI.
On November 4, 2003, CL&P, NRG, the NRG Creditors' Committee, the DPUC, the Office of Consumer Counsel, and the attorney general of Connecticut entered into a comprehensive settlement agreement. Under the settlement agreement, approved by the bankruptcy court and the FERC on November 21, 2003 and December 18, 2003, respectively, NRG was required to continue to deliver power to CL&P under the terms and conditions of the standard offer service contract through the end of its term, which was December 31, 2003, in exchange for a commitment by CL&P to make payments to NRG on a revised weekly schedule. The settlement agreement also allowed CL&P to retain the aforementioned $8.5 million withheld from NRG for replacement power purchased by CL&P during the period June 12, 2003 through July 2, 2003. CL&P will seek to refund this amount to its customers in 2004 pending DPUC approval. On January 19, 2004, CL&P paid NRG-PMI its last weekly payment.
Pre-March 1, 2003 Congestion Charges: In November 2001, CL&P filed suit against NRG in Connecticut Superior Court seeking judgment for unpaid pre- March 1, 2003 congestion charges under its standard offer supply contract. On August 5, 2002, CL&P withheld the then unpaid congestion charges from payments due to NRG for standard offer service and continued to withhold those amounts through December 31, 2003, the end of the contract term. The total amount of congestion costs withheld from NRG was $28.4 million. If it is ultimately concluded that CL&P is responsible for pre-March 1, 2003 congestion costs, then management believes that CL&P would be allowed to recover these costs from its customers. This litigation is ongoing.
Station Service: Since December 1999, CL&P has provided NRG's Connecticut generating plants with station service, which includes energy and/or delivery services provided when a generator is off-line or unable to satisfy its station service energy requirements. Pursuant to the parties' interconnection agreement dated July 1, 1999, CL&P provides this service at DPUC-approved retail rates. In October 2002, CL&P filed a complaint with 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 and delivery services. The FERC issued a decision on December 20, 2002 that agreed that station service from CL&P would be subject to CL&P's applicable retail rates and that states have jurisdiction over the delivery of power to end users even where, as with station service, power is not delivered by distribution facilities. NRG disputed its obligation and refused to pay CL&P.
In September 2003, the bankruptcy court approved a stipulation between CL&P and NRG to submit the station service dispute to arbitration, and arbitration proceedings have been initiated by the parties. No hearing dates have been scheduled. On December 17, 2003, the DPUC determined that CL&P had appropriately administered its station service rates in providing NRG station service. In unrelated proceedings, the FERC has issued decisions with conflicting policy direction. In January 2004, CL&P filed a request with the FERC for further clarification of this issue.
Management will continue to pursue recovery from NRG of the station service balance, including approximately $4 million NRG placed in an escrow account related to this matter. In 2003, as a result of NRG's bankruptcy, the amount due from NRG in excess of the escrow amount was reserved. Management believes that amounts not collected from NRG are ultimately recoverable from CL&P's customers. Therefore, a regulatory asset of $11.4 million was recorded. At December 31, 2003, NRG owed CL&P $16 million for station service. The $16 million owed to CL&P includes $0.6 million billed to NRG subsequent to its emergence from bankruptcy on December 5, 2003.
Legal Costs: Through December 31, 2003, legal costs incurred by CL&P related to NRG's bankruptcy and the SMD dispute amounted to $2.3 million. This amount has been recorded as a regulatory asset, and CL&P received approval to recover $1.6 million in its recent rate case. CL&P will continue to defer these legal costs as they are incurred, and management believes that amounts in excess of $1.6 million will also be recovered from customers.
Meriden Gas Turbines, LLC: Yankee Gas, E.S. Boulos Company (Boulos), which is a subsidiary of NGS, and CL&P are or have been involved in ongoing litigation with Meriden Gas Turbines, LLC (MGT), an NRG subsidiary that was not included in NRG's voluntary bankruptcy proceeding, related to the construction of a generating plant that MGT stated it was abandoning.
Yankee Gas has expended costs in excess of $16 million in the construction of a natural gas pipeline to the generating plant that MGT was constructing. Yankee Gas drew down on an MGT $16 million letter of credit (LOC) when MGT stated that it was abandoning construction of the generating plant. MGT has contested the draw down on the LOC in a lawsuit filed in Connecticut Superior Court. Yankee Gas has a counterclaim pending against MGT to recover additional monies in accordance with the contract that are in excess of the $16 million LOC. This litigation is ongoing.
Boulos has a 50 percent interest in a joint venture that was building switchyards for the MGT generating plant. In the fourth quarter of 2003, Boulos settled all outstanding claims against MGT with no material financial impact.
MGT also currently owes CL&P $0.5 million for work on the South Kensington switching station, which was to be the interconnection point for the MGT generating plant. CL&P has joined pending foreclosure proceedings in an effort to recover the outstanding balance.
Management does not expect that the resolution of the aforementioned NRG exposures will have a material adverse effect on the financial condition or results of operations of NU and its subsidiaries.
NU ENTERPRISES
Business Lines: NU Enterprises aligns its activities into two business
lines, the merchant energy business line and the energy services business
line. The merchant energy business line includes Select Energy's wholesale
and retail marketing activities. Also included are 1,440 MW of generation
capacity, consisting of 1,293 MW at NGC and 147 MW at HWP, which support the
merchant energy business line. The energy services business line includes
the operations of SESI, NGS, and Woods Network.
SESI performs energy management services for large commercial customers, institutional facilities and the United States government. SESI engages in energy-related construction services. NGS operates and maintains NGC's and HWP's generation assets and provides third-party electrical services. In 2003, NGS also performed engineering contracting services.
Results and Outlook: Financial performance at NU Enterprises improved in 2003, losing $3.5 million, compared with losses of $53.2 million in 2002. The 2003 loss includes the after-tax loss of approximately $36 million associated with the aforementioned settlement of the wholesale power contract dispute with CL&P. Excluding that loss, NU Enterprises earned $32.2 million in 2003. During 2004, NU expects that NU Enterprises will continue to be successful and 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 line and between $4 million and $7 million from the energy services business line. Those ranges are heavily dependent on NU Enterprises' ability to achieve targeted wholesale and retail origination margins, successfully manage its contract portfolios and achieve targeted growth in the energy services business line.
Select Energy's merchant energy business line includes wholesale marketing and retail marketing activities. Wholesale marketing activities include wholesale origination, portfolio management and the operation of more than 1,400 MW of pumped storage, hydroelectric and coal-fired generation assets. Wholesale marketing activities earned $31.8 million in 2003, excluding the after-tax loss associated with the settlement of the aforementioned wholesale power contract dispute, compared to losses of $24.7 million in 2002. NGC earned $38.5 million in 2003, compared with $30.4 million in 2002. HWP lost $0.5 million in 2003 compared with a loss of $0.9 million in 2002. NGC's results benefit from an above-market contract with Select Energy. The above- market price continues through 2005, but the contract has been extended through 2006, though at a lower cost to Select Energy. NU parent will continue to guarantee the performance of Select Energy in that contract through 2006. Wholesale marketing activities benefited from above-average precipitation in western New England during 2003, which increased conventional hydroelectric output, as compared with near drought conditions during 2002. This increase in output resulted in $5 million of additional net income in 2003, as compared to 2002. Wholesale marketing activities also benefited from the absence of natural gas trading losses in 2003.
Select Energy signed a number of wholesale marketing contracts in 2003 for delivery to electric utilities in 2004. All contracts were won in competitive bidding processes. Total wholesale sales in 2004 are expected to exceed 40 million megawatt-hours, based on the contracts in effect as of January 1, 2004. The most significant contracts are with CL&P, NSTAR, National Grid USA, WMECO, Jersey Central Power & Light, and Atlantic City Electric Co. Most of the contracts noted above will expire in 2004. Select Energy will bid on additional contracts in 2004 that will take effect in 2004 and beyond. Select Energy's ability to secure a significant amount of wholesale load is a critical factor in NU Enterprises' overall profitability. Select Energy must realize enough gross margin from its sales to cover its overhead and taxes and produce a reasonable profit for NU. Overhead includes personnel and facility costs, credit requirements and carrying costs on NGC and HWP generation. The Northfield Mountain pumped storage facility, a 1,080 megawatt unit in Northfield, Massachusetts, plays a critical role in the success of Select Energy. Northfield's ability to generate large amounts of on-peak energy using water that was pumped uphill during off-peak hours and its ability to react rapidly to changing demand allow Select Energy to economically hedge much of the 2004 earnings risk that results from entering into full requirements supply obligations. As a result of a new competitively bid contract, Select Energy will continue to be CL&P's largest wholesale supplier in 2004, but at a significantly higher rate. Management expects that the improved terms of Select Energy's new CL&P contract will have a positive impact on NU Enterprises' 2004 earnings.
The second activity included in NU Enterprises' merchant energy business line is retail marketing, which also improved its financial performance in 2003 compared to 2002. Select Energy's retail marketing activities had a $25.9 million improvement in financial performance during 2003 compared to 2002 with losses of $1.8 million and $27.7 million in 2003 and 2002, respectively. The 2003 improved retail results are primarily due to improved margins and growth in retail electric sales, along with improved management of retail gas contracts. Over time, management expects that Select Energy's retail sales and financial performance will improve as more commercial and industrial customers move from buying energy through their electric distribution company to purchasing energy directly from suppliers such as Select Energy. Select Energy does not sell electricity or natural gas to residential customers, but actively markets energy to commercial and industrial customers throughout the Northeast between Maine and Maryland with the exception of Vermont. Vermont does not allow retail customers to choose their electric suppliers.
NU Enterprises' energy services business line, including SESI, NGS, and Woods Network earned approximately $2.6 million in 2003 as compared to 2002 when this business line was essentially breakeven. Financial performance at SESI continues to benefit from an expanding level of business with the United States Department of Defense, with net income rising to $4.6 million in 2003 from $3 million in 2002. NGS, which continues to be negatively affected by the lower level of electrical contracting resulting from the slow economy in New England, lost $2.2 million in 2003, following a loss of $3.2 million in 2002. Woods Network earned $0.2 million in both 2003 and 2002.
NU Enterprises parent costs totaled $0.4 million in 2003, compared to $0.8 million in 2002.
In 2002, NU Enterprises concluded a study of the depreciable lives of certain generation assets. The impact of this study was to lengthen the useful lives of those generation assets by 32 years to an average of 70 years. In addition, the useful lives of certain software was revised and shortened to reflect a remaining life of 1.5 years. As a result of these studies, NU Enterprises' operating expenses decreased by $8.6 million in 2003 and $5.1 million in 2002 as compared to 2001.
Intercompany Transactions: CL&P's standard offer purchases from Select Energy represented approximately $558 million of revenues in 2003, compared with $501 million in 2002. CL&P's TSO purchases from Select Energy in 2004 are expected to total approximately $500 million. Other transactions between CL&P and Select Energy totaled $130 million in 2003 and 2002. Additionally, WMECO's purchases from Select Energy represented approximately $143 million in 2003, compared with $14 million in 2002. All of these amounts are eliminated in consolidation. The CL&P standard offer amounts have been reduced by the loss related to the wholesale power contract settlement.
NU ENTERPRISES' MARKET AND OTHER RISKS
Overview: NU Enterprises is exposed to certain market risks inherent in its
business activities. The merchant energy business line enters into 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 the merchant energy business line, including wholesale marketing activities (which include limited energy trading for market and price discovery purposes) and retail marketing activities. 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 risk management policies and procedures. As a means to monitor and control compliance with these policies and procedures, NU's Risk Oversight Council (ROC) monitors NU Enterprises' risk management processes independently from the business lines that create or manage 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. The ROC also confirms methodologies employed to estimate portfolio values.
Wholesale and Retail Marketing Activities: A significant portion of Select Energy's wholesale marketing activities is providing energy to full requirements customers, primarily regulated distribution companies. Under full requirements contract terms, Select Energy is required to provide for the customers' load at all times. Wholesale and retail marketing transactions, including the full requirements contracts, are intended to be part of Select Energy's normal purchases and sales and are recognized on the accrual basis of accounting.
An important component of Select Energy's risk management strategy focuses on managing the volume and price risks of full requirements contracts. These risks include significant fluctuations in both supply and demand due to numerous factors such as weather, plant availability, transmission congestion, and potentially volatile price fluctuations. Select Energy uses energy contracts to mitigate these risks. These contracts, which are included in the wholesale and retail marketing portfolios and are subject to accrual accounting, are important to Select Energy's risk management.
Select Energy manages its portfolio of wholesale and retail marketing contracts and assets to maximize value while maintaining an acceptable level of risk. At forward market prices in effect at December 31, 2003, the wholesale marketing portfolio, which includes the CL&P TSO service contract that extends through December 31, 2004 and other contracts that extend to 2013, had a positive fair value. This positive fair value indicates a positive impact on Select Energy's gross margin in the future. However, there may be significant volatility in the energy commodities markets that may affect this position between now and when the contracts are settled. Accordingly, there can be no assurances that Select Energy will realize the gross margin corresponding to the present positive fair value on its wholesale marketing portfolio.
Hedging: Select Energy utilizes derivative financial and commodity instruments, including futures and forward contracts, to reduce market risk associated with fluctuations in the price of electricity and natural gas purchases for firm sales commitments to certain customers. Select Energy also utilizes derivatives, including financial swap agreements, call and put option contracts, and futures and forward contracts, to manage the market risk associated with a portion of its anticipated supply and delivery requirements. These derivatives have been designated as cash flow hedging instruments for accounting purposes and are used to reduce the market risk associated with fluctuations in the price of electricity, natural gas or oil. A derivative that effectively hedges exposure to the variable cash flows of a forecasted transaction (a cash flow hedge) is initially recorded at fair value with changes in fair value recorded in other comprehensive income, which is a component of equity. Hedges impact earnings when the forecasted transaction being hedged occurs, when hedge ineffectiveness is measured and recorded, when the forecasted transaction being hedged is no longer probable of occurring, or when there is accumulated other comprehensive loss and the hedge and the forecasted transaction being hedged are in a loss position on a combined basis. At December 31, 2003, Select Energy had hedging derivative assets of $55.8 million and hedging derivative liabilities of $12.7 million. At December 31, 2002, Select Energy had hedging derivative assets of $22.8 million and hedging derivative liabilities of $2 million.
The increase in hedging derivative assets and liabilities from December 31, 2002 to December 31, 2003 resulted primarily from new financial contracts entered into during 2003 to hedge gas-indexed power purchases in New England and new financial transmission rights (FTR) contracts to hedge congestion in both New England and the Pennsylvania, New Jersey, Maryland, and Delaware (PJM) regions.
Non-trading: Non-trading derivative contracts are used for delivery of energy related to wholesale and retail marketing activities. These contracts are not entered into for trading purposes, but are subject to fair value accounting because these contracts cannot be designated as normal purchases and sales, as defined in applicable accounting principles or because management has not elected hedge accounting or normal purchases and sales accounting. At December 31, 2003, Select Energy had non-trading derivative assets of $1.6 million and non-trading derivative liabilities of $0.8 million, compared to non-trading derivative assets of $2.9 million and no non- trading derivative liabilities at December 31, 2002. Changes to the non- trading derivatives portfolio, which are not significant, were recognized in revenues.
Wholesale Contracts Defined as "Energy Trading": Energy trading transactions at Select Energy include financial transactions and physical delivery transactions for electricity, natural gas and oil in which Select Energy is attempting to profit from changes in market prices. Energy trading contracts are recorded at fair value, and changes in fair value affect net income.
At December 31, 2003, Select Energy had trading derivative assets of $123.9 million and trading derivative liabilities of $91.4 million on a counterparty- by-counterparty basis, for a net positive position of $32.5 million for the entire trading portfolio. At December 31, 2002, trading derivative assets were $102.9 million and trading derivative liabilities were $61.9 million. The increase in both asset and liability amounts relates primarily to price increases, as trading activity has decreased. These amounts are combined with other derivatives and are included in derivative assets and derivative liabilities on the accompanying consolidated balance sheets.
There can be no assurances that Select Energy will realize cash corresponding to the present positive net fair value of its trading positions. Numerous factors either could positively or negatively affect the realization of the net fair value amount in cash. These include the volatility of commodity prices, changes in market design or settlement mechanisms, the outcome of future transactions, the performance of counterparties, and other factors.
Select Energy has policies and procedures requiring all trading positions to be marked-to-market at the end of each business day and segregating responsibilities between the individuals actually trading (front office) and those confirming the trades (middle office). The determination of the portfolio's fair value is the responsibility of the middle office independent from the front office.
The methods used to determine the fair value of energy trading contracts are identified and segregated in the table of fair value of contracts at December 31, 2003. A description of each method is as follows: 1) prices actively quoted primarily represent New York Mercantile Exchange futures and options that are marked to closing exchange prices; 2) prices provided by external sources primarily include over-the-counter forwards and options, including bilateral contracts for the purchase or sale of electricity or natural gas, and are marked to the mid-point of bid and ask market prices; and 3) prices based on models or other valuation methods primarily include transactions for which specific quotes are not available. The option component of a forward electricity purchase contract had a fair value of $4.5 million at December 31, 2002, and was the only amount included in this method of determining fair value at December 31, 2002. The fair value of the option component of this contract was reduced to zero in 2003 with a credit reserve that was established in 2003, and at December 31, 2003, Select Energy has no other contracts for which fair value is determined based on a model or other valuation method. Broker quotes for electricity are available through the year 2005. Broker quotes for natural gas are available through 2013.
Generally, valuations of short-term contracts derived from quotes or other external sources are more reliable should there be a need to liquidate the contracts, while valuations for longer-term contracts are less certain. Accordingly, there is a risk that contracts will not be realized at the amounts recorded. However, Select Energy has obtained corresponding purchase or sale contracts for substantially all of the trading contracts that have maturities in excess of one year. Because these contracts are sourced, changes in the value of these contracts due to changes in commodity prices are not expected to affect Select Energy's earnings.
As of and for the years ended December 31, 2003 and 2002, the sources of the fair value of trading contracts and the changes in fair value of these trading contracts are included in the following tables. Intercompany transactions are eliminated and not reflected in the amounts below.
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(Millions of Dollars) Fair Value of Trading Contracts at December 31, 2003
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Maturity Less Than Maturity of One to Maturity in Excess
Sources of Fair Value One Year Four Years of Four Years Total Fair Value
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Prices actively quoted $0.2 $0.1 $ - $ 0.3
Prices provided by external sources 6.9 9.6 15.7 32.2
Prices based on models or other
valuation methods - - - -
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Totals $7.1 $9.7 $15.7 $32.5
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(Millions of Dollars) Fair Value of Trading Contracts at December 31, 2002
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Maturity Less Than Maturity of One to Maturity in Excess
Sources of Fair Value One Year Four Years of Four Years Total Fair Value
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Prices actively quoted $(1.2) $ 0.1 $ - $(1.1)
Prices provided by external sources 2.8 20.2 14.6 37.6
Prices based on models or other
valuation methods - 4.5 - 4.5
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Totals $ 1.6 $24.8 $14.6 $41.0
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As indicated in the tables above and below, the fair value of energy trading contracts decreased $8.5 million from $41 million at December 31, 2002 to $32.5 million at December 31, 2003. The change in the fair value of the trading portfolio is attributable to several items, including the termination and realization in 2003 of a contract with a positive fair value of $5.7 million and the establishment of a credit reserve on a long-term trading contract. The change in fair value attributable to changes in valuation techniques and assumptions of $2.3 million in 2003 resulted from a change in the discount rate management uses to determine the fair value of trading contracts. In the second quarter of 2003, the rate was changed from a fixed rate of 5 percent to a market-based LIBOR discount rate to better reflect current market conditions.
In 2002, in connection with management's review of the contracts in the trading portfolio, the significant changes in the energy trading market and the change in the focus of the energy trading activities, certain long-term derivative energy contracts that were included in the trading portfolio and valued at $33.9 million at November 30, 2002, were designated as normal purchases and sales. The impact of this designation is that the contracts were adjusted to fair value at November 30, 2002 and were not and will not be adjusted subsequently for changes in fair value. The $33.9 million carrying value of these contracts was reclassified from trading derivative assets to other long-term assets and is being amortized on a straight-line basis to fuel, purchased and net interchange power expense over the remaining terms of the contracts, some of which extend to 2011. This amount is included in changes in fair values attributable to changes in valuation techniques and assumptions.
The other negative $6 million reflected in changes in fair value attributable to changes in valuation techniques and assumptions relates to $12 million of contracts held by Select Energy New York, Inc. at acquisition that in 2002 were determined to be held for non-trading purposes by Select Energy. Accordingly, the $12 million of contracts were removed from the trading portfolio. Long-term trading contracts with maturities in excess of four years and transmission congestion contracts (TCC) were revalued during 2002 based on the availability of market information, which added $6 million to the value of the trading portfolio.
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Years Ended December 31,
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2003 2002
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(Millions of Dollars) Total Portfolio Fair Value
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Fair value of trading contracts outstanding
at the beginning of the year $41.0 $56.4
Contracts realized or otherwise settled
during the period (10.7) (4.0)
Fair value of new contracts when entered
into during the year - 13.7
Changes in fair values attributable to changes
in valuation techniques and assumptions 2.3 (39.9)
Changes in fair value of contracts (0.1) 14.8
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Fair value of trading contracts outstanding
at the end of the year $32.5 $41.0
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Changing Market: The breadth and depth of the market for energy trading and marketing products in Select Energy's markets continue 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 in nature with less liquidity, market pricing information is becoming less readily available, and participants are more often unable to meet Select Energy's credit standards without providing cash or LOC support. Select Energy is being adversely affected by these factors, and there could be a continuing adverse impact on Select Energy's business lines. The decrease in the number of counterparties participating in the market for long-term energy contracts also continues to affect Select Energy's ability to estimate the fair value of its long-term wholesale energy contracts.
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. For information regarding the effects of SMD on Select Energy, see "Impacts of Standard Market Design" in this Management's Discussion and Analysis. As the market continues to evolve, there could be additional adverse effects that management cannot determine at this time.
Counterparty Credit: Counterparty credit risk relates to the risk of loss that Select Energy would incur because of non-performance by counterparties pursuant to the terms of their contractual obligations. Select Energy has established written credit policies with regard to its counterparties to minimize overall credit risk. These policies require an evaluation of potential counterparties' financial conditions (including credit ratings), collateral requirements under certain circumstances (including cash advances, letters of credit, and parent guarantees), and the use of standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. This evaluation results in establishing credit limits prior to Select Energy entering into contracts. The appropriateness of these limits is subject to continuing review. Concentrations among these counterparties may affect Select Energy's overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes to economic, regulatory or other conditions. At December 31, 2003, approximately 89 percent of Select Energy's counterparty credit exposure to wholesale and trading counterparties was cash collateralized or rated BBB- or better. Another one percent of the counterparty credit exposure was to unrated municipalities. Select Energy held $46.5 million and $16.9 million of counterparty cash advances at December 31, 2003 and 2002, respectively.
Asset Concentrations: At December 31, 2003, positions with four counterparties collectively represented approximately $89 million, or 72 percent, of the $123.9 million trading derivative assets. The largest counterparty's position is secured with letters of credit and cash collateral. Select Energy holds parent company guarantees at investment grade ratings supporting the remaining positions of the counterparties. None of the other counterparties represented more than 10 percent of trading derivative assets at December 31, 2003.
Select Energy's Credit: 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 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.
NU has applied to the Securities and Exchange Commission (SEC) for authority to expand its financial support of NU Enterprises. NU primarily seeks to 1) increase its allowable investments in certain of its unregulated businesses, presently 15 percent of its consolidated capitalization as permitted by SEC regulation, by an additional $500 million, 2) increase the limit for its guarantees of all of its competitive affiliates from $500 million to $750 million, and 3) increase its allowable investments in exempt wholesale generators (EWGs) from $481 million to $1 billion.
If granted, the SEC's order would permit NU's future investment in Select Energy above the amount now allowed. NU has no present plans to significantly expand its EWG portfolio at this time. However, if an investment opportunity becomes available, NU would be able to pursue it within the new allowable EWG investment level. NU expects SEC approval in early 2004.
If the application is not granted in early 2004 as management expects, then there could be a negative impact on the merchant energy business line's ability to achieve its 2004 earnings estimate. This business line depends on NU parent guarantees to support the energy contracts that make up both its revenues and expenses. At December 31, 2003, NU parent could guarantee an additional $211.5 million of merchant energy business line contracts, but guarantee levels constantly fluctuate with the market value of the contracts that are guaranteed, and NU's ability to issue new guarantees may be constrained due to the aforementioned SEC limitation.
For further information regarding Select Energy's activities and risks, see Note 3, "Derivative Instruments, Market Risk and Risk Management," and Note 10, "Accumulated Other Comprehensive Income/(Loss)," to the consolidated financial statements.
BUSINESS DEVELOPMENT AND CAPITAL EXPENDITURES
Utility Group: NU anticipates that it will continue to increase its level of
capital expenditures at the Utility Group to meet customers' increasing needs
for additional and more reliable energy supplies. Investments in Utility
Group plant totaled $505.8 million in 2003, compared with $447 million in
2002 and $411.9 million in 2001.
Connecticut - CL&P: Over the next several years, the majority of NU's capital spending will be at CL&P, where the company is seeking to upgrade and expand an aging and, in some locations, stressed distribution and transmission system. CL&P's capital expenditures totaled $314.6 million in 2003, compared with $239.6 million in 2002 and $236.2 million in 2001. CL&P expects capital expenditures to increase to $440 million in 2004. CL&P spent $246 million on distribution in 2003 and anticipates spending $228 million on distribution in 2004.
In its final 2003 CL&P rate decision, the DPUC authorized rate recovery of distribution capital expenditures totaling $236 million in 2004, $220 million in 2005, $216 million in 2006, and $225 million in 2007.
On July 14, 2003, the Connecticut Siting Council (CSC) approved a 345,000 volt transmission line project from Bethel, Connecticut to Norwalk, Connecticut, proposed in October 2001 by CL&P. The configuration of the new transmission line, enhancements to an existing 115,000 volt transmission line, and work in related substations are estimated to cost approximately $200 million. The line will alleviate identified reliability issues in southwest Connecticut and help reduce congestion costs for all of Connecticut. An appeal of the CSC decision by the City of Norwalk is pending, but management does not expect the appeal to be successful. CL&P anticipates placing the new transmission line in service by the end of 2005. This project is exempt from the State of Connecticut's moratorium on the approval of new electric and natural gas transmission projects. At December 31, 2003, CL&P has capitalized $12.4 million associated with this project.
On October 9, 2003, CL&P and United Illuminating (UI) filed for approval of a separate 345,000 volt transmission line from Norwalk, Connecticut to Middletown, Connecticut. Estimated construction costs of this project are approximately $620 million. CL&P will jointly site this project with UI, and CL&P will own 80 percent, or approximately $496 million, of the project. This project is also exempt from the State of Connecticut's moratorium on the approval of new electric and natural gas transmission projects. CL&P expects the CSC to rule on the application in 2004 and for construction to occur from 2005 through 2007. At December 31, 2003, CL&P has capitalized $9.2 million related to this project.
In September 2002, the CSC approved a plan to replace an undersea electric transmission line between Norwalk, Connecticut and Northport - Long Island, New York, at an estimated cost of $90 million. CL&P and the Long Island Power Authority each own approximately 50 percent of the line. The project still requires federal and New York state approvals. Given the approval process, changing pricing and operational rules in the New England and New York energy markets and pending business issues between the parties, the expected in-service date remains under evaluation. This project is also exempt from the State of Connecticut's moratorium on the approval of new electric and natural gas transmission projects. At December 31, 2003, CL&P has capitalized $5.2 million associated with this project.
Construction of these three projects would significantly enhance CL&P's ability to provide reliable electric service to the rapidly growing energy market in southwestern Connecticut. Despite the need for such facilities, significant opposition has been raised. As a result, management cannot be certain as to the expected in-service dates or the ultimate cost of these projects. Should the plans proceed, applicable law provides that CL&P will be able to recover its operating cost and carrying costs through federally- approved transmission tariffs.
Management believes that construction of the 345,000 volt projects is critical to maintaining service reliability in southwest Connecticut. The 345,000 volt projects, in addition to additional transmission spending planned between 2004 and 2007, also represent a significant source of potential earnings growth for NU. Management believes that if the projects now being considered are all built over the next four years, NU's net transmission plant investment would triple. Revenues and earnings for NU's transmission system are established by the FERC.
Connecticut - Yankee Gas: Yankee Gas has also proposed expansion of its natural gas distribution system in Connecticut. Yankee Gas' capital expenditures totaled $55.2 million in 2003, compared with $70.6 million in 2002 and $47.8 million in 2001. Yankee Gas expects capital expenditures to total $60 million in 2004 as it continues to expand its distribution system and begins work on two major projects; a liquefied natural gas storage facility in Waterbury, Connecticut and a new 9-mile pipeline in southeast Connecticut to connect the existing Yankee Gas delivery system with that of the New England Gas Company (NEGASCO), a Rhode Island natural gas delivery company. The NEGASCO project would cost approximately $5 million, provide Yankee Gas with additional revenue, improve service reliability in the Stonington, Connecticut area, and expand natural gas delivery into additional areas of southeastern Connecticut. Construction of this project is contingent upon receiving satisfactory regulatory approval.
Yankee Gas received a decision from the DPUC supporting the construction and operation of a 1.2 billion cubic foot liquefied natural gas storage and production facility in Waterbury, Connecticut. Construction of the facility, which is expected to take approximately three years, could begin in the second half of 2004. The decision allows for the deferral of prudently incurred costs related to the project and requires Yankee Gas to file a rate case to recover this investment when the facility is placed in service. This project is also exempt from the State of Connecticut's moratorium on the approval of new electric and natural gas transmission projects. At December 31, 2003, Yankee Gas has capitalized approximately $1.9 million related to this project.
New Hampshire: PSNH capital spending totaled $105.6 million in 2003 and is projected to total $160 million in 2004. The primary reason for the increase is PSNH's proposal to convert a 50 megawatt oil and coal burning unit at Schiller Station in Portsmouth, New Hampshire to burn wood chips. The $70 million project will commence if PSNH receives satisfactory approval from the NHPUC. PSNH believes that the conversion can be accomplished without impacting retail rates because of certain government incentives to promote renewable resource projects. Another reason for the projected increase in capital spending is PSNH's transmission projects.
Effective January 1, 2004, PSNH completed the purchase of the electric system and retail franchise of CVEC, a subsidiary of Central Vermont Public Service Corporation (CVPS), for $30.1 million. CVEC's 11,000 customers in western New Hampshire have been added to PSNH's customer base of more than 460,000 customers. The purchase price included the book value of CVEC's plant assets of approximately $9 million and an additional $21 million to terminate an above-market wholesale power purchase agreement CVEC had with CVPS. CVEC is expected to add approximately $1.1 million to PSNH's annual earnings.
Massachusetts: WMECO's capital expenditures totaled $30.4 million in 2003, compared with $23.1 million in 2002 and $30.7 million in 2001. WMECO's capital expenditures are expected to total $38 million in 2004.
NU Enterprises: Capital expenditures at NU Enterprises generation subsidiaries, NGC and HWP, are expected to be modest in 2004, with $13 million at NGC and $1 million at HWP. In 2003, NGC's and HWP's capital expenditures totaled $11.1 million and $1.8 million, respectively. NU continues to examine acquisitions in the energy services business. In 2002, NU acquired Woods Electrical and Woods Network for $16.3 million.
REGIONAL TRANSMISSION ORGANIZATION
The FERC has required all transmission owning utilities to voluntarily form
RTOs or to state why this process has not begun.
On October 31, 2003, ISO-NE, along with NU and six other New England transmission companies filed a proposal with the FERC to create a RTO for New England. The RTO is intended to strengthen the independent and efficient management of the region's power system while ensuring that customers in New England continue to have the most reliable system possible to realize the benefits of a competitive wholesale energy market.
ISO-NE, as a RTO, will have a new independent governance structure and will also become the transmission provider for New England by exercising operational control over New England's transmission facilities pursuant to a detailed contractual arrangement with the New England transmission owners. Under this contractual arrangement, the RTO will have clear authority to direct the transmission owners to operate their facilities in a manner that preserves system reliability, including requiring transmission owners to expand existing transmission lines or build new ones when needed for reliability. Transmission owners will retain their rights over revenue requirements, rates and rate designs. The filing requests that the FERC approve the RTO arrangements for an effective date of March 1, 2004.
In a separate filing made on November 4, 2003, NU along with six other New England transmission owners requested, consistent with the FERC's pricing policy for RTOs and Order-2000-compliant independent system operators, that the FERC approve a single return on equity (ROE) for regional and local rates that would consist of a base ROE as well as incentive adders of 50 basis points for joining a RTO and 100 basis points for constructing new transmission facilities approved by the RTO. If the FERC approves the request, then the transmission owners would receive a 13.3 percent ROE for existing transmission facilities and a 14.3 percent ROE for new transmission facilities. The outcome of this request and its impact on NU cannot be determined at this time.
RESTRUCTURING AND RATE MATTERS
Utility Group: On August 26, 2003, NU's electric operating companies filed
their first transmission rate case at the FERC since 1995. In the filing, NU
requested implementation of a formula rate that would allow recovery of
increasing transmission expenditures on a timelier basis and that the
changes, including a $23.7 million annual rate increase through 2004, take
effect on October 27, 2003. NU requested that the FERC maintain NU's
existing 11.75 percent ROE until a ROE for the New England RTO is
established by the FERC. On October 22, 2003, the FERC accepted this filing
implementing the proposed rates subject to refund effective on October 28,
2003. A final decision in the rate case is expected in 2004.
Increasing transmission rates are generally recovered from distribution companies through FERC-approved transmission rates. Electric distribution companies pass through higher transmission rates to retail customers as approved by the appropriate state regulatory commission. Distribution companies need to file for retail rate increases if transmission costs exceed what is currently allowed in rates. Currently, WMECO has a tracking mechanism to reset rates annually for transmission costs with overcollections refunded to customers and undercollections deferred and then collected from customers in later years. In its 2003 rate case, CL&P sought a tracking mechanism to allow it to recover changes in transmission expenses on a timely basis. While the DPUC approved a $28.4 million increase in transmission rates for CL&P's retail customers effective January 1, 2004, it did not grant a tracking mechanism in rates. As a result, CL&P will need to reapply to the DPUC to adjust transmission rates when its revenues are not adequate to recover transmission costs. PSNH requested a tracking mechanism from the NHPUC when it filed its rate case on December 29, 2003, which will allow it to recover changes in transmission expenses on a timely basis.
Connecticut - CL&P:
Public Act No. 03-135 and Rate Proceedings: On June 25, 2003, the Governor
of Connecticut signed into law Public Act No. 03-135 (Act) that amended
Connecticut's 1998 electric utility industry legislation. Among key
features, the Act created a TSO period from 2004 through 2006 that allowed
the base rate cap to return to 1996 levels, which represented a potential
increase of up to 11.1 percent. Additional costs related to Federally
Mandated Congestion Charges (FMCC) are not included in the cap.
Additionally, if energy supply costs were to exceed levels established in the
TSO rate, these costs could be recovered through an energy adjustment clause
or through the FMCC. The Act also allowed CL&P to collect a procurement fee
of at least 0.50 mills per kilowatt-hour (kWh) from customers who continue to
purchase TSO service. That fee can increase to 0.75 mills if CL&P beats
certain regional benchmarks. Management expects that the procurement fee
will be between $11 million and $12 million annually, which will add $6
million to $7 million to CL&P's net income. One mill is equal to one-tenth
of a cent.
ISO-NE and the New England Power Pool are currently debating the implementation of locational installed capacity (LICAP). LICAP is the requirement 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 its lack of sufficient generation and transmission, is expected to have high LICAP costs. LICAP rules are subject to the jurisdiction of the FERC. ISO-NE filed a proposal with the FERC on March 1, 2004 for implementation in June 2004. Until the exact proposal is approved by the FERC, the financial impact on CL&P's customers cannot be determined. CL&P expects to recover LICAP from its customers as a FMCC.
On July 1, 2003, CL&P filed with the DPUC to establish TSO service and to set the TSO rates equal to December 31, 1996 total rate levels. On December 19, 2003, the DPUC issued a final decision setting the average TSO rate at $0.1076 per kWh for 2004, which the DPUC found to be within the statutory cap. That rate incorporated nine key elements, which combined produced the average TSO rate. The most significant element was an average GSC of $0.05744 per kWh. That charge will allow CL&P to fully recover from customers the amounts to be paid in 2004 to its five TSO suppliers. These suppliers include Select Energy, which was awarded 37.5 percent of CL&P's TSO load through a request for proposal process overseen by the DPUC, and four other suppliers, all of which are investment grade rated by major rating agencies.
The Act also required CL&P to file a four-year transmission and distribution plan with the DPUC. Accordingly, on August 1, 2003, CL&P filed a rate case that amended rate schedules and proposed changes to increase distribution rates. On December 19, 2003, the DPUC issued its final decision in the rate case. In that decision, the DPUC chose to apply $120 million of overcollections from CL&P's customers in prior years against higher distribution rates in the form of credits of $30 million per year. Net of those overcollections, the DPUC ordered that distribution rates be lowered by $1.9 million in 2004 and be raised by $25.1 million in 2005, $11.9 million in 2006, and $7 million in 2007. The decision approved a transmission rate increase of $28.4 million in 2004, but did not allow the tracking mechanism and did not set transmission rates beyond 2004. The DPUC also approved rate recovery of approximately $900 million of CL&P's proposed $1 billion distribution capital budget over the four-year period. The decision set CL&P's authorized ROE at 9.85 percent. Earnings above 9.85 percent will be shared equally by shareholders and ratepayers. The sharing mechanism is not affected by earnings from the procurement fee.
CL&P filed a petition for reconsideration of certain items in the rate case on December 31, 2003. Other parties also filed petitions for reconsideration. On January 21, 2004, the DPUC agreed to reconsider CL&P's items; however, CL&P also filed an appeal with the Connecticut Superior Court on January 30, 2004, which was within the time frame required by law. The appeal was filed in the event that the DPUC's reconsideration is still not acceptable to CL&P.
Disposition of Seabrook Proceeds: CL&P sold its share of the Seabrook nuclear unit on November 1, 2002. The net proceeds in excess of the book value of Seabrook of $16 million were recorded as a regulatory liability and, after being offset by accelerated decommissioning funding and other adjustments, will be refunded to customers. On May 1, 2003, CL&P filed its application with the DPUC for approval of the disposition of the proceeds from the sale. This filing described CL&P's treatment of its share of the proceeds from the sale. Hearings in this docket were held in September 2003, and a draft decision was received on February 3, 2004. The final decision, which was received on March 3, 2004, did not have a material effect on CL&P's net income or financial position.
CTA and SBC Reconciliation Filing: On April 3, 2003, CL&P filed its annual CTA and SBC reconciliation with the DPUC. For the year ended December 31, 2002, total CTA revenues and excess GSC revenues exceeded the CTA revenue requirement by $93.5 million. This amount was recorded as a regulatory liability. For the same period, SBC revenues exceeded the SBC revenue requirement by $22.4 million. In compliance with a prior decision of the DPUC, a portion of the SBC overcollection reduced regulatory assets, and the remaining overcollection of $18.6 million was applied to the CTA. The DPUC's December 19, 2003 TSO decision addressed $41 million of SBC overcollections and $64 million of CTA overcollections that had been estimated as of December 31, 2003. In its decision, the DPUC ordered that $80 million of the overcollections be used to reduce CTA costs during the 2004 through 2006 TSO period. The DPUC also ordered that $25 million of the overcollections be used to offset SBC costs during the TSO period. The DPUC also ordered that $37 million of GSC overcollections be used to pay CL&P's 0.50 mill per kWh procurement fee during the TSO period.
Connecticut - Yankee Gas:
Infrastructure Expansion Rate Mechanism (IERM): On June 25, 2003, the DPUC issued a final decision in the 2002 IERM docket. The DPUC concluded that the basic concept of IERM is valid, appropriate and beneficial. The DPUC ordered Yankee Gas to provide a credit to customers for 2002 and 2003 overcollections. That credit was recorded as a regulatory liability and refunded to Yankee Gas customers from December 2003 through February 2004.
On October 1, 2003, Yankee Gas filed with the DPUC its IERM compliance filing. This filing is required annually on October 1 of each year to provide a reconciliation of the system expansion program and the earnings sharing mechanism projection.
Rate Case: In 2003, Yankee Gas earned a ROE below the DPUC-authorized level of 11 percent. As a result of higher pension costs and other factors, management expects that the financial performance will continue to underearn the DPUC-authorized ROE. Yankee Gas is evaluating the filing of a rate case before the end of 2004 for a rate increase to take effect in 2005.
New Hampshire:
Transition Energy Service: In accordance with the "Agreement to Settle PSNH Restructuring" (Restructuring Settlement) and state law, PSNH must file for updated transition energy service (TS) rates annually. The TS rate recovers PSNH's generation and purchased power costs, including a return on PSNH's generation investment. During the February 1, 2004 through January 31, 2005 time period when current rates will be effective, PSNH will defer any difference between its TS revenues and the actual costs incurred. On December 19, 2003, the NHPUC approved a $0.0536 per kWh TS rate effective February 1, 2004.
Delivery Rate Case: PSNH's delivery rates were fixed by the Restructuring Settlement until February 1, 2004. Consistent with the requirements of the Restructuring Settlement and state law, PSNH filed a delivery service rate case and tariffs with the NHPUC on December 29, 2003 to increase electricity delivery rates by approximately $21 million, or approximately 2.6 percent, effective February 1, 2004. In addition, PSNH is requesting that recovery of FERC-regulated transmission costs be adjusted annually through a tracking mechanism. The NHPUC suspended the proposed rate increase until the conclusion of the delivery rate case. Hearings are expected in August 2004, and a decision is expected in the third quarter of 2004 with rates retroactively applied to February 1, 2004.
SCRC Reconciliation Filings: On an annual basis, PSNH files with the NHPUC an SCRC reconciliation filing for the preceding calendar year. This filing includes the reconciliation of stranded cost revenues with stranded costs, and TS revenues with TS costs. The NHPUC reviews the filing, including a prudence review of PSNH's generation operations.
On May 1, 2003, PSNH filed with the NHPUC an SCRC reconciliation filing for the period January 1, 2002, through December 31, 2002. This filing included the reconciliation of stranded cost revenues with stranded costs and a net proceeds calculation related to the sale of NAEC's share of Seabrook and the subsequent transfer of those net proceeds to PSNH. Upon the completion of discovery and technical sessions with the NHPUC staff and the New Hampshire Office of the Consumer Advocate (OCA), PSNH, the NHPUC Staff and the OCA entered into a stipulation and settlement agreement that was filed with the NHPUC on August 15, 2003. An order from the NHPUC approving the settlement agreement on October 24, 2003 did not have a material impact on PSNH's net income or financial position.
The 2003 SCRC filing is expected to be filed on May 1, 2004. Management does not expect the review of the 2003 SCRC filing to have a material effect on PSNH's net income or financial position. The recovery of stranded costs is expected to be a significant source of cash flow for PSNH through 2007. On May 22, 2003, the NHPUC issued an order approving a settlement between PSNH, owners of 14 small hydroelectric power producers, the NHPUC staff and the OCA calling for the termination of PSNH's obligations to purchase power from the hydroelectric units at above market prices. On May 30, 2003, under the terms of this settlement, PSNH made lump sum payments to those owners amounting to $20.4 million. The buyout payments were recorded as regulatory assets and will be recovered, including a return, over the initial term of the obligations as Part 2 stranded costs. PSNH is entitled to retain 20 percent of the estimated savings from the buyouts. PSNH is expected to recover $21 million of the purchase price of CVEC over the next three to four years.
Massachusetts:
Transition Cost Reconciliations: On March 31, 2003, WMECO filed its 2002 transition cost reconciliation with the Massachusetts Department of Telecommunications and Energy (DTE). This filing reconciled the recovery of generation-related stranded costs for calendar year 2002 and included the renegotiated purchased power contract related to the Vermont Yankee nuclear unit.
On July 15, 2003, the DTE issued a final order on WMECO's 2001 transition cost reconciliation, which addressed WMECO's cost tracking mechanisms. As part of that order, the DTE directed WMECO to revise its 2002 annual transition cost reconciliation filing. The revised filing was submitted to the DTE on September 22, 2003. Hearings have been held, and the timing of a final decision from the DTE is uncertain. Management does not expect the outcome of this docket to have a material adverse impact on WMECO's net income or financial position.
Standard Offer and Default Service: In December 2003, the DTE approved WMECO's standard offer service rate of $0.05607 per kWh for the period of January 1, 2004 through February 28, 2005. The DTE also approved a default service rate of $0.05829 for the period of January 1, 2004 through June 30, 2004 for residential customers and a rate of $0.0616 for the period January 1, 2004 through March 31, 2004 for commercial and industrial customers.
For information regarding commitments and contingencies related to restructuring and rate matters, see Note 7A, "Commitments and Contingencies - Restructuring and Rate Matters," to the consolidated financial statements.
CONSOLIDATED EDISON, INC. MERGER LITIGATION
On March 5, 2001, Consolidated Edison, Inc. (Con Edison) advised NU that it
was unwilling to close its merger with NU on the terms set forth in the
parties' 1999 merger agreement. On March 12, 2001, NU filed suit against Con
Edison seeking damages in excess of $1 billion.
On May 11, 2001, Con Edison filed an amended complaint seeking damages for breach of contract, fraudulent inducement and negligent misrepresentation. Con Edison claimed that it is entitled to recover a portion of the merger synergy savings estimated to have a net present value in excess of $700 million. NU disputes both Con Edison's entitlement to any damages as well as its method of computing its alleged damages.
The companies completed discovery in the litigation and both submitted motions for summary judgment. The court denied Con Edison's motion in its entirety, leaving NU's claim for breach of the merger agreement and partially granted NU's motion for summary judgment by eliminating Con Edison's claims against NU for fraud and negligent misrepresentation.
Various other motions in the case are pending. 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.
NUCLEAR GENERATION ASSET DIVESTITURES
Millstone: On March 31, 2001, CL&P and WMECO consummated the sale of
Millstone 1 and 2 and CL&P, PSNH and WMECO sold their ownership interests in
Millstone 3.
Seabrook: On November 1, 2002, CL&P, NAEC, and certain other joint owners consummated the sale of their ownership interests in Seabrook.
Vermont Yankee: On July 31, 2002, Vermont Yankee Nuclear Power Corporation (VYNPC) consummated the sale of its nuclear generating unit. In November 2003, CL&P, PSNH and WMECO collectively sold back to VYNPC their shares of stock for approximately $1.5 million. CL&P, PSNH and WMECO continue to purchase their respective shares of approximately 16 percent of the plant's output under new contracts.
Nuclear Decommissioning and Plant Closure Costs: Although the purchasers of NU's ownership shares of the Millstone, Seabrook and Vermont Yankee plants assumed the obligation of decommissioning those plants, NU still has significant decommissioning and plant closure cost obligations to the companies that own the Yankee Atomic (YA), Connecticut Yankee (CY) and Maine Yankee (MY) plants (collectively Yankee Companies). Each plant has been shut down and is undergoing decommissioning. The Yankee Companies collect decommissioning and closure costs through wholesale FERC-approved rates charged under power purchase agreements to NU electric utility companies 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 the decommissioning and closure costs has already been collected, but a substantial portion related to the decommissioning of CY has not yet been filed at and approved for collection by the FERC. The cost estimate for CY that has not yet been approved for recovery by the FERC at December 31, 2003 is $258.3 million.
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 or the Bechtel Power Corporation litigation referred to in Note 7G, "Commitments and Contingencies - Nuclear Decommissioning and Plant Closure Costs," to the consolidated financial statements. 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 these costs in retail rates as well.
OFF-BALANCE SHEET ARRANGEMENTS
Utility Group: The CL&P Receivables Corporation (CRC) was incorporated on
September 5, 1997, and is a wholly owned subsidiary of CL&P. CRC has an
arrangement with a highly rated financial institution under which CRC can
sell up to $100 million of accounts receivable. At December 31, 2003 and
2002, CRC had sold accounts receivable of $80 million and $40 million,
respectively, to that financial institution with limited recourse.
CRC was established for the sole purpose of selling CL&P's accounts receivable and unbilled revenues and is included in the consolidation of NU's financial statements. On July 9, 2003, CRC renewed its Receivables Purchase and Sale Agreement with CL&P and the financial institution. The agreement expires on July 7, 2004. Management plans to renew this agreement prior to its expiration.
The transfer of receivables to the financial institution under this
arrangement qualifies for sale treatment under SFAS No. 140, "Accounting for
Transfers and Servicing of Financial Assets and Extinguishment of Liabilities
- A Replacement of SFAS No. 125." Accordingly, the $80 million and $40
million outstanding under this facility are not reflected as debt or included
in the consolidated financial statements at December 31, 2003 and 2002,
respectively.
This off-balance sheet arrangement is not significant to NU's liquidity or other benefits. There are no known events, demands, commitments, trends, or uncertainties that will, or are reasonably likely to, result in the termination, or material reduction in the amount available to the company under this off-balance sheet arrangement.
NU Enterprises: During 2001, SESI created HEC/CJTS Energy Center, LLC (HEC/CJTS) which is a special purpose entity (SPE). Management decided to create HEC/CJTS for the sole purpose of providing a bankruptcy-remote entity for the financing of a construction project. The construction project was the construction of an energy center to serve the Connecticut Juvenile Training School (CJTS). The owner of CJTS, the State of Connecticut, entered into a 30-year lease with HEC/CJTS for the energy center. Simultaneously, HEC/CJTS transferred its interest in the lease with the State of Connecticut to investors who are unaffiliated with NU in exchange for the issuance of $19.2 million of Certificates of Participation. The transfer of HEC/CJTS's interest in the lease was accounted for as a sale under SFAS No. 140. The debt of $19.2 million created in relation to the transfer of interest and issuance of the Certificates of Participation was derecognized and is not reflected as debt or included in the consolidated financial statements. No gain or loss was recorded. HEC/CJTS does not provide any guarantees or on- going services, and there are no contingencies related to this arrangement.
SESI has a separate contract with the State of Connecticut to operate and maintain the energy center. The transaction was structured in this manner to obtain tax-exempt rate financing and therefore to reduce the State of Connecticut's lease payments.
This off-balance sheet arrangement is not significant to NU's liquidity, capital resources or other benefits. There are no known events, demands, commitments, trends, or uncertainties that will, or are reasonably likely to, result in the termination of this off-balance sheet arrangement.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States of America requires
management to make estimates, assumptions and at times difficult, subjective
or complex judgments. Changes in these estimates, assumptions and judgments,
in and of themselves, could materially impact the financial statements of NU.
Management communicates to and discusses with NU's Audit Committee of the
Board of Trustees all critical accounting policies and estimates. The
following are the accounting policies and estimates that management believes
are the most critical in nature.
Presentation: In accordance with current accounting pronouncements, NU's consolidated financial statements include all subsidiaries upon which control is maintained and all variable interest entities (VIE) for which NU is the primary beneficiary, as defined. All intercompany transactions between these subsidiaries are eliminated as part of the consolidation process.
NU has less than 50 percent ownership interests in the Connecticut Yankee Atomic Power Company, Yankee Atomic Electric Company, Maine Yankee Atomic Power Company, and two companies that transmit electricity imported from the Hydro-Quebec system. NU does not control these companies and does not consolidate them in its financial statements. NU accounts for the investments in these companies using the equity method. Under the equity method, NU records its ownership share of the earnings or losses at these companies. Determining whether or not NU should apply the equity method of accounting for an investee company requires management judgment.
NU has investments in NEON and Acumentrics. These investments are carried at cost, and these companies are VIEs, as defined by FIN 46. NU adopted FIN 46 on July 1, 2003. FIN 46 requires that the party to a VIE that absorbs the majority of the VIE's losses, defined as the primary beneficiary, consolidate the VIE. NU is not the primary beneficiary of NEON or Acumentrics and is not required to consolidate them.
NU also has a preferred stock investment in R. M. Services, Inc. (RMS). Upon adoption of FIN 46, management determined that NU was the primary beneficiary of RMS and that NU would have to consolidate RMS into its financial statements. The consolidation of RMS resulted in a negative $4.7 million after-tax cumulative effect of an accounting change in the third quarter of 2003. For more information on RMS, see Note 1E, "Summary of Significant Accounting Policies - Accounting for R.M. Services, Inc. Variable Interest Entity," to the consolidated financial statements.
The required adoption date of FIN 46 was delayed from July 1, 2003 to December 31, 2003 for NU. However, NU elected to adopt FIN 46 at the original adoption date, which impacted both the amount of the cumulative effect of the accounting change and the classification of losses NU recorded after RMS became a consolidated entity.
Determining whether the company is the primary beneficiary of a VIE is subjective and requires management's judgment. There are certain variables taken into consideration to determine whether the company is considered the primary beneficiary to the VIE. A change in any one of these variables could require the company to reconsider whether or not it is the primary beneficiary of the VIE.
In December 2003, the FASB issued a revised version of FIN 46 (FIN 46R). FIN 46R could result in fewer NU investments meeting the definition of a VIE. FIN 46R is effective for NU for the first quarter of 2004, but is not expected to have an impact on NU's consolidated financial statements.
Revenue Recognition: Utility Group retail revenues are based on rates approved by the state regulatory commissions. These regulated rates are applied to customers' use of energy to calculate a bill. In general, rates can only be changed through formal proceedings with the state regulatory commissions.
Certain Utility Group companies utilize regulatory commission-approved tracking mechanisms to track the recovery of certain incurred costs. The tracking mechanisms allow for rates to be changed periodically, with overcollections refunded to customers or undercollections collected from customers in future periods.
The determination of the energy sales to individual customers is based on the reading of meters, which occurs on a systematic basis throughout the month. Billed revenues are based on these meter readings. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated, and an estimated amount of unbilled revenues is recorded.
Wholesale transmission revenues are based on rates and formulas that are approved by the FERC. Most of NU's wholesale transmission revenues are collected through a combination of the New England Regional Network Service (RNS) tariff and NU's Local Network Service (LNS) tariff. The RNS tariff, which is administered by ISO-NE, recovers the revenue requirements associated with transmission facilities that are deemed by the FERC to be Pool Transmission Facilities. The LNS tariff which was accepted by the FERC on October 22, 2003, provides for the recovery of NU's total transmission revenue requirements, net of revenue credits received from various rate components, including revenues received under the RNS rates.
NU Enterprises recognizes revenues at different times for its different business lines. Wholesale and retail marketing revenues are recognized when energy is delivered to customers. Trading revenues are recognized as the fair value of trading contracts changes. Service revenues are recognized as services are provided, often on a percentage of completion basis.
Revenues and expenses for derivative contracts that are entered into for trading purposes are recorded on a net basis in revenues when these transactions settle. The settlement of wholesale non-trading derivative contracts for the sale of energy or gas by both the Utility Group and NU Enterprises that are not related to customers' needs are recorded in operating expenses. Derivative contracts that hedge an underlying transaction and that qualify for hedge accounting affect earnings when the forecasted transaction being hedged occurs, when hedge ineffectiveness is measured and recorded, when the forecasted transaction being hedged is no longer probable of occurring, or when there is an accumulated other comprehensive loss and when the hedge and the forecasted transaction being hedged are in a loss position on a combined basis. The settlement of hedge derivative contracts is recorded in the same revenue or expense line as the transaction being hedged. For further information regarding the accounting for these contracts, see Note 1G, "Summary of Significant Accounting Policies - Accounting for Energy Contracts," to the consolidated financial statements.
Utility Group Unbilled Revenues: Unbilled revenues represent an estimate of electricity or gas delivered to customers that has not been billed. Unbilled revenues represent assets on the balance sheet that become accounts receivable in the following month as customers are billed.
The estimate of unbilled revenues is sensitive to numerous factors that can significantly impact the amount of revenues recorded. Estimating the impact of these factors is complex and requires management's judgment. The estimate of unbilled revenues is important to NU's consolidated financial statements as adjustments to that estimate could significantly impact operating revenues and earnings. Two potential methods for estimating unbilled revenues are the requirements and the cycle method.
The Utility Group estimates unbilled revenues monthly using the requirements method. The requirements method utilizes the total monthly volume of electricity or gas delivered to the system and applies a delivery efficiency (DE) factor to reduce the total monthly volume by an estimate of delivery losses in order to calculate total estimated monthly sales to customers. The total estimated monthly sales amount less total monthly billed sales amount results in a monthly estimate of unbilled sales. Unbilled revenues are estimated by applying an average rate to the estimate of unbilled sales.
Differences between the actual DE factor and the estimated DE factor can have a significant impact on estimated unbilled revenue amounts.
In 2003, the unbilled sales estimates for all Utility Group companies were tested using the cycle method. The cycle method uses the billed sales from each meter reading cycle and an estimate of unbilled days in each month based on the meter reading schedule. The cycle method is historically more accurate than the requirements method when used in a mostly weather-neutral month. The cycle method resulted in adjustments to the estimate of unbilled revenues that had a net positive after-tax earnings impact of approximately $4.6 million in 2003. The positive after-tax impacts on CL&P, PSNH, and WMECO were $7.2 million, $3.3 million, and $0.3 million, respectively. There was a negative after-tax impact on Yankee Gas of $6.2 million, including certain gas cost adjustments.
The testing of the requirements method with the cycle method will be done on at least an annual basis using a weather-neutral month.
Derivative Accounting: Effective January 1, 2001, NU adopted SFAS No. 133, as amended.
Select Energy uses derivative instruments in its wholesale and retail marketing activities, and many Utility Group contracts for the purchase or sale of energy or energy-related products are derivatives. The application of derivative accounting under SFAS No. 133, as amended, is complex and requires management judgment in the following respects: identification of derivatives and embedded derivatives, election and designation of the normal purchases and sales exception, identifying hedge relationships, assessing and measuring hedge ineffectiveness, and determining the fair value of derivatives. All of these judgments, depending upon their timing and effect, can have a significant impact on NU's consolidated net income.
In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities," which amended existing derivative accounting guidance. This new statement incorporates interpretations that were included in previous Derivative Implementation Group (DIG) guidance, clarifies certain conditions, and amends other existing pronouncements. It was effective for contracts entered into or modified after June 30, 2003. Management has determined that the adoption of SFAS No. 149 did not change NU's accounting for wholesale and retail marketing contracts or the ability of NU Enterprises to elect the normal purchases and sales exception. The adoption of SFAS No. 149 resulted in fair value accounting for certain Utility Group contracts that are subject to unplanned netting and do not meet the definition of capacity contracts. These non- trading derivative contracts are recorded at fair value at December 31, 2003 as derivative assets and liabilities with offsetting amounts recorded as regulatory liabilities and assets because the contracts are part of providing regulated electric or gas service. The fair values of these Utility Group contracts at December 31, 2003 were derivative assets of $1.6 million and derivative liabilities of $1.6 million.
Emerging Issues Task Force (EITF) Issue No. 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 EITF Issue No. 02-3," was derived from EITF Issue No. 02-3, which requires net reporting in the income statement of energy trading activities. Issue No. 03-11 addresses income statement classification of revenues related to derivatives that physically deliver and are not related to energy trading activities. Prior to Issue No. 03-11, there was no specific accounting guidance that addressed the classification in the income statement of Select Energy's retail marketing and wholesale contracts or the Utility Group's power supply contracts, many of which are non-trading derivatives.
On July 31, 2003, the EITF reached a consensus in Issue No. 03-11 that determining whether realized gains and losses on contracts that physically deliver and are not held for trading purposes should be reported on a net (sales and purchases both in expenses) or gross (sales in revenues and purchases in expenses) basis is a matter of judgment that depends on the relevant facts and circumstances. The EITF indicated that existing accounting guidance should be considered and provided no new guidance in Issue No. 03-11. In Issue No. 03-11, the EITF did not provide transition guidance, which management could have interpreted as becoming applicable on October 1, 2003 for revenues from that date forward. However, management applied its conclusion on net or gross reporting to all periods presented to enhance comparability.
Select Energy reports the settlement of long-term derivative contracts that physically deliver and are not held for trading purposes on a gross basis, generally with sales in revenues and purchases in expenses. Short-term sales and purchases represent power that is purchased to serve full requirements contracts but is ultimately not needed based on the actual load of the full requirements customers. This excess power is sold to the independent system operator or to other counterparties. As of December 31, 2003, settlements of short-term derivative contracts that are not held for trading purposes, though previously reported in revenues, are reported on a net basis in expenses. Select Energy applied the new classification to revenues for all years presented in order to enhance comparability. Short-term and non- requirements sales and other reclassifications that amounted to $595.7 million for the first nine months of 2003 were reflected as revenues in quarterly reporting but are now included in expenses.
Though previously reported on a gross basis, after reviewing the relevant facts and circumstances, the Utility Group also reported the settlement of all short-term sales contracts that are part of procurement activities on a net basis in expenses. The Utility Group applied this new classification to revenues for all years presented in order to enhance comparability. These sales that amounted to $50.2 million for the first nine months of 2003 were reflected as revenues in quarterly reporting but are now included in expenses.
The amounts reclassified from 2002 and 2001 revenues to operating expenses are included in Note 1C, "Summary of Significant Accounting Policies - New Accounting Standards," to the consolidated financial statements.
On June 25, 2003, the DIG cleared Issue No. C-20, which addressed the meaning of "not clearly and closely related regarding contracts with a price adjustment feature" as it relates to the election of the normal purchase and sales exception to derivative accounting. The implementation of this guidance was required for the fourth quarter of 2003 for NU. The implementation of Issue No. C-20 resulted in CL&P recording the fair value of two existing power purchase contracts as derivatives, one as a derivative asset, and one as a derivative liability. An offsetting regulatory liability and an offsetting regulatory asset were recorded, as these contracts are part of stranded costs, and management believes that these costs will continue to be recovered or refunded in rates. The fair values of these long-term power purchase contracts include a derivative asset with a fair value of $112.4 million and a derivative liability with a fair value of $54.6 million at December 31, 2003.
At December 31, 2003, Select Energy recorded approximately $4.3 million of TCCs at fair value. Market information for these TCCs is not available, and management believes the amounts paid for these contracts are equal to their fair value. Select Energy, as well as CL&P and PSNH, hold FTR contracts to mitigate the risk associated with the congestion price differences associated with LMP in New England. FTR contracts in New England held by NU subsidiaries were recorded at a fair value of $6.2 million. FTR contracts held by Select Energy in the PJM region were recorded at a fair value of $0.8 million. Management continues to believe the amount to be paid for both the TCC and the FTR contracts best represents their fair value. If new markets for these contracts develop, then there may be an impact on NU's consolidated financial statements in future periods.
Regulatory Accounting: The accounting policies of NU's regulated utility companies historically reflect the effects of the rate-making process in accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." The transmission and distribution businesses of CL&P, PSNH and WMECO, along with PSNH's generation business and Yankee Gas' distribution business, continue to be cost-of-service rate regulated, and management believes the application of SFAS No. 71 to that portion of those businesses continues to be appropriate. Management must reaffirm this conclusion at each balance sheet date. If, as a result of a change in circumstances, it is determined that any portion of these companies no longer meets the criteria of regulatory accounting under SFAS No. 71, that portion of the company will have to discontinue regulatory accounting and write-off the respective regulatory assets and liabilities. Such a write-off could have a material impact on NU's consolidated financial statements.
The application of SFAS No. 71 results in recording regulatory assets and liabilities. Regulatory assets represent the deferral of incurred costs that are probable of future recovery in customer rates. In some cases, NU records regulatory assets before approval for recovery has been received from the applicable regulatory commission. Management must use judgment to conclude that costs deferred as regulatory assets are probable of future recovery. Management bases its conclusion on certain factors, including changes in the regulatory environment, recent rate orders issued by the applicable regulatory agencies and the status of any potential new legislation. Regulatory liabilities represent revenues received from customers to fund expected costs that have not yet been incurred or probable future refunds to customers.
Management uses its best judgment when recording regulatory assets and liabilities; however, regulatory commissions can reach different conclusions about the recovery of costs, and those conclusions could have a material impact on NU's consolidated financial statements. Management believes it is probable that the Utility Group companies will recover the regulatory assets that have been recorded.
Goodwill and Other Intangible Assets: SFAS No. 142, "Goodwill and Other Intangible Assets," requires that goodwill balances be reviewed for impairment at least annually by applying a fair value-based test. NU selected October 1 as the annual goodwill impairment testing date. The goodwill impairment analysis impacts the Utility Group - Gas and NU Enterprises segments. Goodwill impairment is deemed to exist if the net book value of a reporting unit exceeds its estimated fair value and if the implied fair value of goodwill based on the estimated fair value of the reporting unit is less than the carrying amount of the goodwill. If goodwill is deemed to be impaired it will be written off, which could have a significant impact on NU's consolidated financial statements.
NU has completed its impairment analyses as of October 1, 2003, for all reporting units that maintain goodwill and has determined that no impairments exist.
In performing the impairment evaluation required by SFAS No. 142, NU estimates the fair value of each reporting unit and compares it to the carrying amount of the reporting unit, including goodwill. NU estimates the fair values of its reporting units using discounted cash flow methodologies and an analysis of comparable companies or transactions. The discounted cash flow analysis requires the input of several critical assumptions, including future growth rates, operating cost escalation rates, allowed ROE, a risk- adjusted discount rate, and long-term earnings multiples of comparable companies. These assumptions are critical to the estimate and are susceptible to change from period to period.
Modifications to the aforementioned assumptions in future periods, particularly changes in discount rates, could result in future impairments of goodwill. Actual financial performance and market conditions in upcoming periods could also impact future impairment analyses.
Pension and Postretirement Benefits Other Than Pensions (PBOP): NU's subsidiaries participate in a uniform noncontributory defined benefit retirement plan (Pension Plan) covering substantially all regular NU employees. NU also participates in a postretirement benefit plan (PBOP Plan) to provide certain health care benefits, primarily medical and dental, and life insurance benefits through a benefit plan to retired employees. For each of these plans, the development of the benefit obligation, fair value of plan assets, funded status and net periodic benefit credit or cost is based on several significant assumptions. If these assumptions were changed, the resulting change in benefit obligations, fair values of plan assets, funded status and net periodic benefit credits or costs could have a material impact on NU's consolidated financial statements.
Results: Pre-tax periodic pension income for the Pension Plan, excluding settlements, curtailments and special termination benefits, totaled $31.8 million, $73.4 million and $101 million for the years ended December 31, 2003, 2002 and 2001, respectively. The pension income amounts exclude one- time items recorded under SFAS No. 88, "Employers' Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits," associated with early termination programs and the sale of the Millstone and Seabrook nuclear units. Net SFAS No. 88 items totaled $22.2 million in income for the year ended December 31, 2002. This amount was recorded as a liability for refund to customers.
The pre-tax net PBOP Plan cost, excluding settlements, curtailments and special termination benefits, totaled $35.1 million, $34.5 million and $28.3 million for the years ended December 31, 2003, 2002 and 2001, respectively. The PBOP Plan cost excludes one-time items associated with the sale of the Seabrook nuclear units. These items totaled $1.2 million in income for the year ended December 31, 2002.
Long-Term Rate of Return Assumptions: In developing the expected long-term rate of return assumptions, NU evaluated input from actuaries, consultants and economists, as well as long-term inflation assumptions and NU's historical 20-year compounded return of approximately 11 percent. NU's expected long-term rate of return on assets is based on certain target asset allocation assumptions and expected long-term rates of return. The Pension Plan's and PBOP Plan's target asset allocation assumptions and expected long-term rates of return assumptions by asset category are as follows:
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At December 31,
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Pension Benefits Postretirement Benefits
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2003 2002 2003 2002
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Target Assumed Target Assumed Target Assumed Target Assumed
Asset Rate of Asset Rate of Asset Rate of Asset Rate of
Asset Category Allocation Return Allocation Return Allocation Return Allocation Return
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Equity securities:
United States 45.00% 9.25% 45.00% 9.75% 55.00% 9.25% 55.00% 9.75%
Non-United States 14.00% 9.25% 14.00% 9.75% 11.00% 9.25% - -
Emerging markets 3.00% 10.25% 3.00% 10.75% 2.00% 10.25% - -
Private 8.00% 14.25% 8.00% 14.75% - - - -
Debt Securities:
Fixed income 20.00% 5.50% 20.00% 6.25% 27.00% 5.50% 45.00% 6.25%
High yield fixed
income 5.00% 7.50% 5.00% 7.50% 5.00% 7.50% - -
Real estate 5.00% 7.50% 5.00% 7.50% - - - -
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The actual asset allocations at December 31, 2003 and 2002 approximated these target asset allocations. NU regularly reviews the actual asset allocations and periodically rebalances the investments to the targeted asset allocations when appropriate. For information regarding actual asset allocations, see Note 4A, "Employee Benefits - Pension Benefits and Postretirement Benefits Other Than Pensions," to the consolidated financial statements.
NU reduced the long-term rate of return assumption 50 basis points from 9.25 percent to 8.75 percent in 2003 for the Pension Plan and PBOP Plan due to lower expected market returns. NU believes that 8.75 percent is a reasonable long-term rate of return on Pension Plan and PBOP Plan assets for 2003, and NU expects to use 8.75 percent in 2004. NU will continue to evaluate the actuarial assumptions, including the expected rate of return, at least annually, and will adjust the appropriate assumptions as necessary.
Actuarial Determination of Income and Expense: NU bases the actuarial determination of Pension Plan and PBOP Plan income/expense on a market- related valuation of assets, which reduces year-to-year volatility. This market-related valuation calculation recognizes investment gains or losses over a four-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the fair value of assets. Since the market-related valuation calculation recognizes gains or losses over a four-year period, the future value of the market-related assets will be impacted as previously deferred gains or losses are recognized. There will be no impact on the fair value of Pension Plan and PBOP Plan assets.
At December 31, 2003, the Pension Plan had cumulative unrecognized investment losses of $106 million, which will increase pension expense over the next four years by reducing the expected return on Pension Plan assets. At December 31, 2003, the Pension Plan also had cumulative unrecognized actuarial losses of $189 million, which will increase pension expense over the expected future working lifetime of active Pension Plan participants, or approximately 13 years. The combined total of unrecognized investment and actuarial losses at December 31, 2003 is approximately $295 million. These losses impact the determination of pension expense and the actuarially determined prepaid pension amount recorded on the consolidated balance sheets but have no impact on expected Pension Plan funding.
At December 31, 2003, the PBOP Plan had cumulative unrecognized investment losses of $11 million, which will increase PBOP Plan cost over the next four years by reducing the expected return on plan assets. At December 31, 2003, the PBOP Plan also had cumulative unrecognized actuarial losses of $103 million, which will increase PBOP Plan expense over the expected future working lifetime of active PBOP Plan participants, or approximately 13 years. The combined total of unrecognized investment and actuarial losses at December 31, 2003 is approximately $114 million. These losses impact the determination of PBOP Plan cost and the actuarially determined accrued PBOP Plan cost recorded on the consolidated balance sheets.
Discount Rate: The discount rate that is utilized in determining future pension and PBOP obligations is based on a basket of long-term bonds that receive one of the two highest ratings given by a recognized rating agency. To compensate for the Pension Plan's longer duration, 25 basis points were added to the benchmark. The discount rate determined on this basis has decreased from 6.75 percent at December 31, 2002 to 6.25 percent at December 31, 2003.
Expected Pension Expense: Due to the effect of the unrecognized actuarial losses and based on an expected rate of return on Pension Plan assets of 8.75 percent, a discount rate of 6.25 percent and various other assumptions, NU estimates that expected contributions to and pension expense for the Pension Plan will be as follows (in millions):
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Expected
Year Contributions Pension Expense
----------------------------------------------------
2004 $ - $ 2.9
2005 $ - $21.2
2006 $ - $26.6
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Future actual pension income/expense will depend on future investment performance, changes in future discount rates and various other factors related to the populations participating in the Pension Plan.
Sensitivity Analysis: The following represents the increase/(decrease) to the Pension Plan's reported cost and to the PBOP Plan's reported cost as a result of the change in the following assumptions by 50 basis points (in millions):
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At December 31,
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Pension Plan Postretirement Plan
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Assumption Change 2003 2002 2003 2002
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Lower long-term
rate of return $10.7 $10.7 $0.9 $1.1
Lower discount rate $12.3 $11.0 $1.0 $1.1
Lower compensation
increase $(5.9) $(5.0) N/A N/A
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Plan Assets: The value of the Pension Plan assets has increased from $1.6 billion at December 31, 2002 to $1.9 billion at December 31, 2003. The investment performance returns, despite declining discount rates, have increased the funded status of the Pension Plan on a projected benefit obligation (PBO) basis from an underfunded position of $157.5 million at December 31, 2002 to an overfunded position of $3.8 million at December 31, 2003. The PBO includes expectations of future employee compensation increases. The accumulated benefit obligation (ABO) of the Pension Plan was approximately $240 million less than Pension Plan assets at December 31, 2003 and approximately $78 million less than Pension Plan assets at December 31, 2002. The ABO is the obligation for employee service and compensation provided through December 31, 2003. If the ABO exceeds Pension Plan assets at a future plan measurement date, NU will record an additional minimum liability. NU has not made employer contributions since 1991.
The value of PBOP Plan assets has increased from $147.7 million at December 31, 2002 to $178 million at December 31, 2003. The investment performance returns, despite declining discount rates, have decreased the underfunded status of the PBOP Plan on an accumulated projected benefit obligation basis from $250.1 million at December 31, 2002 to $227 million at December 31, 2003. NU has made a contribution each year equal to the PBOP Plan's postretirement benefit cost, excluding curtailments, settlements and special termination benefits.
Health Care Cost: The health care cost trend assumption used to project increases in medical costs is 9 percent for 2003, decreasing one percentage point per year to an ultimate rate of 5 percent in 2007. The effect of increasing the health care cost trend by one percentage point would have increased 2003 service and interest cost components of the PBOP Plan cost by $0.8 million in 2003 and $0.9 million in 2002.
Accounting for the Effect of Medicare Changes on PBOP: On December 8, 2003, the President signed into law a bill that expands Medicare, primarily by adding a prescription drug benefit and by adding a federal subsidy to qualifying plan sponsors of retiree health care benefit plans. Management believes that NU currently qualifies.
Specific authoritative accounting guidance on how to account for the effect the Medicare federal subsidy has on NU's PBOP Plan has not been issued by the FASB. FASB Staff Position (FSP) No. FAS 106-1, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003," required NU to make an election for 2003 financial reporting. The election was to either defer the impact of the subsidy until the FASB issues guidance or to reflect the impact of the subsidy on December 31, 2003 reported amounts. NU chose to reflect the impact on December 31, 2003 reported amounts.
Reflecting the impact of the Medicare change decreased the PBOP benefit obligation by $19.5 million and increased actuarial gains by $19.5 million with no impact on 2003 expenses, assets, or liabilities. The $19.5 million actuarial gain will be amortized as a reduction to PBOP expense over 13 years beginning in 2004. PBOP expense in 2004 will also reflect a lower interest cost due to the reduction in the December 31, 2003 benefit obligation. Management estimates that the reduction in PBOP expense in 2004 will be approximately $2 million.
When accounting guidance is issued by the FASB, it may require NU to change the accounting described above and change the information included in this annual report.
Income Taxes: Income tax expense is calculated each year in each of the jurisdictions in which NU operates. This process involves estimating NU's actual current tax exposures as well as assessing temporary differences resulting from differing treatment of items, such as timing of the deduction and expenses for tax and book accounting purposes. These differences result in deferred tax assets and liabilities, which are included in NU's consolidated balance sheets. The income tax estimation process impacts all of NU's segments. Adjustments made to income taxes could significantly affect NU's consolidated financial statements. Management must also assess the likelihood that deferred tax assets will be recovered from future taxable income, and to the extent that recovery is not likely, a valuation allowance must be established. Significant management judgment is required in determining income tax expense, deferred tax assets and liabilities and valuation allowances.
NU accounts for deferred taxes under SFAS No. 109, "Accounting for Income Taxes." For temporary differences recorded as deferred tax liabilities that will be recovered in rates in the future, NU has established a regulatory asset. The regulatory asset amounted to $253.8 million and $326.4 million at December 31, 2003 and 2002, respectively. Regulatory agencies in certain jurisdictions in which NU's Utility Group companies operate require the tax effect of specific temporary differences to be "flowed through" to utility customers. Flow through treatment means that deferred tax expense is not recorded on the consolidated statements of income. Instead, the tax effect of the temporary difference impacts both amounts for income tax expense currently included in customers' rates and the company's net income. Flow through treatment can result in effective income tax rates that are significantly different than expected income tax rates. Recording deferred taxes on flow through items is required by SFAS No. 109, and the offset to the deferred tax amounts is the regulatory asset referred to above. A reconciliation from expected tax expense at the statutory federal income tax rate to actual tax expense recorded is included on the accompanying consolidated statements of income taxes.
The estimates that are made by management in order to record income tax expense, accrued taxes and deferred taxes are compared each year to the actual tax amounts filed on NU's income tax returns. The income tax returns were filed in the fall of 2003 for the 2002 tax year. In the fourth quarter, NU recorded differences between income tax expense, accrued taxes and deferred taxes on its consolidated financial statements and the amounts that were on its income tax returns. Recording these differences in income tax expense resulted in a positive impact of approximately $6 million on NU's 2003 earnings.
Depreciation: Depreciation expense is calculated based on an asset's useful life, and judgment is involved when estimating the useful lives of certain assets. A change in the estimated useful lives of these assets could have a material impact on NU's consolidated financial statements absent timely rate relief for Utility Group assets.
Accounting for Environmental Reserves: Environmental reserves are accrued using a probabilistic model approach when assessments indicate that it is probable that a liability has been incurred and an amount can be reasonably estimated. The estimation of environmental liabilities impacts the Utility Group - Electric and the Utility Group - Gas segments. Adjustments made to environmental liabilities could have a significant effect on earnings. The probabilistic model approach estimates the liability based on the most likely action plan from a variety of available remediation options, ranging from no action to remedies ranging from establishing institutional controls to full site remediation and long-term monitoring. The probabilistic model approach estimates the liabilities associated with each possible action plan based on findings through various phases of site assessments. These estimates are based on currently available information from presently enacted state and federal environmental laws and regulations and several cost estimates from outside engineering and remediation contractors. These amounts also take into consideration prior experience in remediating contaminated sites and data released by the United States Environmental Protection Agency and other organizations.
These estimates are subjective in nature partly because there are usually several different remediation options from which to choose when working on a specific site. These estimates are subject to revisions in future periods based on actual costs or new information concerning either the level of contamination at the site or newly enacted laws and regulations. The amounts recorded as environmental liabilities on the consolidated balance sheets represent management's best estimate of the liability for environmental costs based on current site information from site assessments and remediation estimates. These liabilities are estimated on an undiscounted basis.
Under current rate-making policy, PSNH and Yankee Gas have regulatory recovery mechanisms in place for environmental costs. Accordingly, regulatory assets have been recorded for certain of PSNH's and Yankee Gas' environmental liabilities. As of December 31, 2003 and 2002, $26.3 million and $24.3 million, respectively, have been recorded as regulatory assets on the accompanying consolidated balance sheets. CL&P recovers a certain level of environmental costs currently in rates but does not have an environmental cost recovery tracking mechanism. Accordingly, changes in CL&P's environmental reserves impact CL&P's earnings. WMECO does not have a regulatory mechanism to recover environmental costs from its customers, and changes in WMECO's environmental reserves impact WMECO's earnings.
Asset Retirement Obligations: NU adopted SFAS No. 143, "Accounting for Asset Retirement Obligations," on January 1, 2003. SFAS No. 143 requires that legal obligations associated with the retirement of property, plant and equipment be recorded as a liability on the balance sheet at fair value when incurred and when a reasonable estimate of the fair value can be made. SFAS No. 143 defines an asset retirement obligation (ARO) as a legal obligation that is required to be settled due to an existing or enacted law, statute, ordinance, or a written or oral promise to remove an asset. AROs may stem from environmental laws, state laws and regulations, easement agreements, building codes, contracts, franchise grants and agreements, oral promises made upon which third parties have relied, or the dismantlement, restoration, or reclamation of properties.
Upon adoption of SFAS No. 143, certain removal obligations were identified that management believes are AROs but either have not been incurred or are not material. These removal obligations arise in the ordinary course of business or have a low probability of occurring. The types of obligations primarily relate to transmission and distribution lines and poles, telecommunication towers, transmission cables and certain FERC or state regulatory agency re-licensing issues. There was no impact to NU's earnings upon adoption of SFAS No. 143; however, if there are changes in certain laws and regulations, orders, interpretations or contracts entered into by NU, there may be future AROs that need to be recorded.
Under SFAS No. 71, regulated utilities, including NU's Utility Group companies, currently recover amounts in rates for future costs of removal of plant assets. Future removals of assets do not represent legal obligations and are not AROs. Historically, these amounts were included as a component of accumulated depreciation until spent. At December 31, 2003 and 2002, these amounts totaling $334 million and $321 million, respectively, were reclassified to regulatory liabilities on the accompanying consolidated balance sheets.
In June 2003, the FASB issued a proposed FSP, "Applicability of SFAS No. 143, 'Accounting for Asset Retirement Obligations', to Legislative Requirements on Property Owners to Remove and Dispose of Asbestos or Asbestos-Containing Materials." In the FSP, the FASB staff concludes that current legislation creates a legal obligation for the owner of a building to remove and dispose of asbestos-containing materials. In the FSP, the FASB staff also concludes that this legal obligation constitutes an ARO that should be recognized as a liability under SFAS No. 143. This FSP changes a FASB staff interpretation of SFAS No. 143 that an obligating event did not occur until a building containing asbestos was demolished. In November 2003, the FASB indicated that, based on the diverse views it received in comment letters on the proposed FSP, it was considering a proposal for a FASB agenda project to address this issue. If this FSP is adopted in its current form, then NU would be required to record an ARO. Management has not estimated this potential ARO at December 31, 2003.
Special Purpose Entities: In addition to SPEs that are described in the "Off- Balance Sheet Arrangements" section of this Management's Discussion and Analysis, during 2001 and 2002, to facilitate the issuance of rate reduction bonds and certificates intended to finance certain stranded costs, NU established four SPEs: CL&P Funding LLC, PSNH Funding LLC, PSNH Funding LLC 2 and WMECO Funding LLC (the funding companies). The funding companies were created as part of state-sponsored securitization programs. The funding companies are restricted from engaging in non-related activities and are required to operate in a manner intended to reduce the likelihood that they would be included in their respective parent company's bankruptcy estate if they ever became involved in a bankruptcy proceeding. The funding companies and the securitization amounts are consolidated in the accompanying consolidated financial statements.
During 1999, SESI established an SPE, HEC/Tobyhanna Energy Project, LLC (HEC/Tobyhanna), in connection with a federal energy savings performance project located at the United States Army Depot in Tobyhanna, Pennsylvania. HEC/Tobyhanna sold $26.5 million of Certificates related to the project and used the funds to repay SESI for the costs of the project. HEC/Tobyhanna's activities and Certificates are included in NU's consolidated financial statements.
For further information regarding the matters in this "Critical Accounting Policies and Estimates" section see Note 1, "Summary of Significant Accounting Policies," Note 3, "Derivative Instruments, Market Risk and Risk Management," Note 4, "Employee Benefits," Note 5, "Goodwill and Other Intangible Assets," and Note 7C, "Commitments and Contingencies - Environmental Matters," to the consolidated financial statements.
OTHER MATTERS
Commitments and Contingencies: For further information regarding other
commitments and contingencies, see Note 7, "Commitments and Contingencies,"
to the consolidated financial statements.
Contractual Obligations and Commercial Commitments: Information regarding NU's contractual obligations and commercial commitments at December 31, 2003 is summarized through 2008 and thereafter as follows:
------------------------------------------------------------------------------------------------------ (Millions of Dollars) 2004 2005 2006 2007 2008 Thereafter ------------------------------------------------------------------------------------------------------ Notes payable to banks (a) $ 105.0 $ - $ - $ - $ - $ - Long-term debt (a) 64.9 92.1 27.8 9.6 161.2 1,941.7 Capital leases (b)(c) 3.1 3.1 2.9 2.6 2.3 20.1 Operating leases (c)(d) 21.9 19.6 17.6 14.2 12.0 27.4 Long-term contractual arrangements (c)(d) 546.3 528.3 522.4 430.0 301.7 1,759.7 Select Energy purchase agreements (c)(d)(e) 4,471.0 761.5 142.9 84.3 84.7 275.4 ------------------------------------------------------------------------------------------------------ Totals $5,212.2 $1,404.6 $713.6 $540.7 $561.9 $4,024.3 ------------------------------------------------------------------------------------------------------ |
(a) Included in NU's debt agreements are usual and customary positive, negative and financial covenants. Non-compliance with certain covenants, for example the timely payment of principal and interest, may constitute an event of default, which could cause an acceleration of principal in the absence of receipt by the company of a waiver or amendment. Such acceleration would change the obligations outlined in the table of contractual obligations and commercial commitments.
(b) The capital lease obligations include imputed interest of $18.2 million.
(c) NU has no provisions in its capital or operating lease agreements or agreements related to its long-term contractual arrangements or Select Energy purchase commitments that could trigger a change in terms and conditions, such as acceleration of payment obligations.
(d) Amounts are not included on NU's consolidated balance sheets.
(e) Select Energy's purchase agreement amounts can exceed the amount expected to be reported in fuel, purchased and net interchange power because energy trading purchases are classified in revenues.
Rate reduction bond amounts are non-recourse to NU, have no required payments over the next five years and are not included in this table. The Utility Group's standard offer service contracts and default service contracts and NU's expected contribution to the PBOP Plan in 2004 of $41.3 million are also not included in this table. For further information regarding NU's contractual obligations and commercial commitments, see the Consolidated Statements of Capitalization and related footnotes, and Note 2, "Short-Term Debt," Note 9, "Leases," and Note 7F, "Commitments and Contingencies - Long- Term Contractual Arrangements," to the consolidated financial statements.
Forward Looking Statements: This discussion and analysis includes forward looking statements, which are statements of future expectations and not facts including, but not limited to, statements regarding future earnings, refinancings, regulatory proceedings, the use of proceeds from restructuring, and the recovery of operating costs. Words such as estimates, expects, anticipates, intends, plans, and similar expressions identify forward looking statements. Actual results or outcomes could differ materially as a result of further actions by state and federal regulatory bodies, competition and industry restructuring, changes in economic conditions, changes in weather patterns, changes in laws, developments in legal or public policy doctrines, technological developments, volatility in electric and natural gas commodity markets, and other presently unknown or unforeseen factors.
Website: Additional financial information is available through NU's website at www.nu.com.
RESULTS OF OPERATIONS
The following table provides the variances in income statement line items for the consolidated statements of income included in this annual report for the past two years.
<CAPTON> --------------------------------------------------------------------------------------------------- Income Statement Variances 2003 over/(under) 2002 2002 over/(under) 2001 (Millions of Dollars) Amount Percent Amount Percent --------------------------------------------------------------------------------------------------- Operating Revenues $832 16% $(524) (9)% Operating Expenses: Fuel, purchased and net interchange power 683 22 (382) (11) Other operation 148 20 (21) (3) Maintenance (31) (12) 5 2 Depreciation (1) (1) 5 2 Amortization (130) (42) (572) (65) Amortization of rate reduction bonds 4 3 50 51 Taxes other than income taxes 5 2 8 4 Gain on sale of utility plant 187 100 455 71 --------------------------------------------------------------------------------------------------- Total operating expenses 865 18 (452) (9) --------------------------------------------------------------------------------------------------- Operating Income (33) (7) (72) (13) --------------------------------------------------------------------------------------------------- Interest expense, net (24) (9) (9) (3) Other (loss)/income, net (44) (a) (144) (77) --------------------------------------------------------------------------------------------------- Income before tax expense (53) (22) (207) (46) Income tax expense (22) (27) (92) (53) Preferred dividends of subsidiaries - - (2) (23) --------------------------------------------------------------------------------------------------- Income before cumulative effect of accounting changes, net of tax benefits (31) (20) (113) (43) Cumulative effect of accounting changes, net of tax benefits (5) (100) 22 100 --------------------------------------------------------------------------------------------------- Net income $(36) (23)% $ (91) (38)% =================================================================================================== |
(a) Percent greater than 100.
OPERATING REVENUES
Total revenues increased $832 million in 2003, compared with 2002, due to
higher revenues from NU Enterprises ($775 million or $588 million after
intercompany eliminations), higher Utility Group electric revenues ($160
million or $165 million after intercompany eliminations) and higher Utility
Group gas revenues ($79 million).
The NU Enterprises' revenue increase is primarily due to higher wholesale and retail requirements sales volumes ($386 million) and higher prices ($339 million).
The Utility Group revenue increase is primarily due to higher retail electric revenue ($217 million), partially offset by lower wholesale revenue ($57 million). The regulated retail electric revenue increase is primarily due to higher CL&P recovery of incremental LMP costs net of amounts to be returned to customers ($72 million), higher sales volumes ($73 million), an adjustment to unbilled revenues ($46 million) and a higher average price resulting from the mix among customer classes for the regulated companies ($25 million). The higher Yankee Gas revenue is primarily due to higher recovery of gas costs ($77 million), higher gas sales volumes ($8 million) and price variances among customer classes ($7 million), partially offset by an adjustment to unbilled revenues ($13 million). Regulated retail electric kWh sales increased by 2.1 percent, and firm natural gas sales increased by 7.8 percent in 2003, before the adjustments to unbilled revenues. The regulated wholesale revenue decrease is primarily due to lower PSNH 2003 sales as a result of the sale of Seabrook.
Total revenues decreased by $524 million in 2002, compared with 2001, primarily due to lower competitive energy revenues ($245 million after intercompany eliminations) and lower regulated subsidiaries revenues due to lower wholesale and transmission revenues ($143 million after intercompany eliminations), and lower regulated retail revenues ($136 million).
The competitive energy companies' revenue decrease in 2002 is primarily due to lower wholesale marketing revenues from Select Energy full requirements contracts, primarily due to lower energy prices. The decrease in regulated wholesale revenues is primarily due to lower sales associated with purchased- power contracts ($91 million) and the 2001 revenue associated with the sale of Millstone output ($42 million). The regulated retail revenue decrease is primarily due to the May 2001 rate decrease for PSNH ($23 million), and the 2002 decrease in the WMECO standard offer energy rate ($77 million), lower Yankee Gas revenue due to lower purchased gas adjustment clause revenue ($59 million) and a combination of the April 2002 rate decrease and lower gas sales ($27 million), partially offset by an increase resulting from the collection of CL&P deferred fuel costs ($25 million) and higher retail electric sales ($25 million). Regulated retail electric kWh sales increased by 1.3 percent, and firm natural gas volume sales decreased by 4.3 percent in 2002.
FUEL, PURCHASED AND NET INTERCHANGE POWER
Fuel, purchased and net interchange power expense increased $683 million in
2003, primarily due to higher wholesale energy purchases at NU Enterprises
($629 million), and higher gas costs ($77 million), partially offset by lower
nuclear fuel ($20 million).
Fuel, purchased and net interchange power expense decreased by $382 million in 2002, primarily due to lower wholesale sales from the merchant energy business line ($168 million after intercompany eliminations), lower Yankee Gas expense primarily due to lower gas prices ($80 million), and lower purchased-power costs for the regulated subsidiaries ($131 million after intercompany eliminations).
OTHER OPERATION
Other operation expense increased $148 million in 2003, primarily due to
higher expenses for NU Enterprises resulting from service business growth
($57 million), higher regulated business administrative and general expenses,
primarily due to higher health care costs ($16 million), lower pension income
($31 million), higher reliability must run related transmission expense ($30
million), higher conservation and load management expenditures ($16 million),
higher distribution expense ($6 million), and higher load and dispatch
expenses ($6 million), partially offset by lower nuclear expense due to the
sale of Seabrook ($29 million).
Other operation expense decreased $21 million in 2002, primarily due to lower nuclear expenses as a result of the sale of the Millstone units at the end of the first quarter in 2001 ($26 million), partially offset by higher load and dispatch expenses ($7 million).
MAINTENANCE
Maintenance expense decreased $31 million in 2003, primarily due to lower
nuclear expense resulting from the sale of Seabrook ($26 million) and lower
competitive expenses associated with the services contracting business ($7
million), partially offset by higher gas distribution expenses ($2 million).
Maintenance expense increased $5 million in 2002, primarily due to higher competitive companies' expenses associated with the expansion of new services businesses ($23 million), higher fossil fuel expenses ($7 million) and higher distribution expenses ($3 million), partially offset by lower nuclear expenses as a result of the sale of the Millstone units at the end of the first quarter in 2001 ($29 million).
DEPRECIATION
Depreciation decreased $1 million in 2003 primarily due to lower
decommissioning and depreciation expenses resulting from 2002 depreciation of
Seabrook as compared to no 2003 Seabrook-related depreciation ($7 million)
and lower NU Enterprises depreciation due to a study which resulted in
lengthening the estimated lives of certain generation assets ($3 million),
partially offset by higher Utility Group depreciation resulting from higher
plant balances ($9 million).
Depreciation increased $5 million in 2002, primarily due to higher expense resulting from higher regulated plant balances ($11 million), partially offset by the higher Millstone-related decommissioning expenses recorded in 2001 ($8 million).
AMORTIZATION
Amortization decreased $130 million in 2003 primarily due to the 2002
amortization of stranded costs upon the sale of Seabrook ($183 million),
partially offset by higher amortization in 2003 related to the Utility
Group's recovery of stranded costs ($53 million), in part resulting from
higher wholesale revenue from the sale of IPP related energy.
Amortization decreased $572 million in 2002, primarily due to the amortization in 2001 related to the gain on sale of the Millstone units ($641 million) and Seabrook deferred returns ($39 million), and lower amortization related to recovery of the Millstone investment ($45 million), partially offset by the higher PSNH amortization in 2002 primarily related to the gain on the sale of Seabrook ($155 million).
AMORTIZATION OF RATE REDUCTION BONDS
Amortization of rate reduction bonds increased $4 million in 2003 due to the
repayment of principal.
Amortization of rate reduction bonds increased $50 million in 2002. All amortization was fully recovered by payments from customers in 2002 and 2003, and the bonds had no impact on net income.
TAXES OTHER THAN INCOME TAXES
Taxes other than income taxes increased $5 million in 2003, primarily due to
a credit recorded in 2002 recognizing a Connecticut sales and use tax audit
settlement ($8 million), partially offset by a lower 2003 payment to
compensate the Town of Waterford for lost property tax revenue as a result of
the sale of Millstone ($4 million) and lower New Hampshire property taxes due
to the sale of Seabrook ($2 million).
Taxes other than income taxes increased $8 million in 2002, primarily due to CL&P's payments to the Town of Waterford for its loss of property tax revenue resulting from electric utility restructuring ($15 million) and the favorable 2001 property tax settlement with the City of Meriden for CL&P and Yankee, which decreased 2001 taxes ($15 million). These increases were partially offset by the 2002 recognition of a Connecticut sales and use tax audit settlement for the years 1993 through 2001 ($8 million), lower gross earnings taxes ($6 million), lower New Hampshire franchise taxes ($3 million) and lower property taxes ($4 million).
GAIN ON SALE OF UTILITY PLANT
Gain on the sale of utility plant decreased $187 million in 2003 due to the
gain recognized in 2002 resulting from CL&P's and NAEC's sale of Seabrook
($187 million).
Gain on the sale of utility plant decreased $455 million in 2002 primarily due to the gain recognized in the 2001 sale of CL&P's and WMECO's ownership interests in the Millstone units ($642 million), partially offset by CL&P's and NAEC's 2002 sale of Seabrook ($187 million).
INTEREST EXPENSE, NET
Interest expense, net decreased $24 million in 2003 primarily due to lower
interest for the regulated subsidiaries resulting from lower rates ($12
million), lower interest at NU parent as a result of the interest rate swap
related to its $263 million fixed-rate senior notes ($8 million), capitalized
interest on prepayments for generator interconnections ($4 million) and lower
NAEC interest due to the retirement of debt ($3 million), partially offset by
higher competitive business interest as a result of higher debt levels ($6
million).
Interest expense, net decreased $9 million in 2002, primarily due to NAEC's reduction of debt.
OTHER (LOSS)/INCOME, NET
Other (loss)/income, net decreased $44 million primarily due to the 2002
elimination of certain reserves associated with NU's ownership share of
Seabrook ($25 million), 2002 Seabrook related gains ($15 million), lower
equity in earnings from the Yankee companies in 2003 ($7 million), a higher
level of donations in 2003 ($5 million), RMS losses recorded in 2003 ($4
million) and lower 2003 conservation and load management incentive income
($2 million), partially offset by 2002 investment write-downs ($18 million).
Other (loss)/income, net decreased $144 million in 2002 primarily due to the 2001 gain related to the Millstone sale ($202 million) and the 2002 investment write-downs ($18 million), partially offset by the 2002 Seabrook related gains ($39 million) and the 2001 loss on share repurchase contracts ($35 million).
INCOME TAX EXPENSE
The consolidated statement of income taxes provides a reconciliation of
actual and expected tax expense. The tax effect of temporary differences is
accounted for in accordance with the rate-making treatment of the applicable
regulatory commissions. In past years, this rate-making treatment has
required the company to provide the customers with a portion of the tax
benefits associated with accelerated tax depreciation in the year it is
generated (flow through depreciation). As these flow through differences
turn around, higher tax expense is recorded.
Income tax expense decreased by $22 million in 2003, primarily due to lower taxable income.
Income tax expense decreased by $92 million in 2002, primarily due to the recognition of WMECO ITC in the second quarter of 2002 and the tax impacts of the Millstone sale in 2001, partially offset by tax impacts of the sale of Seabrook in 2002.
PREFERRED DIVIDENDS OF SUBSIDIARIES
Preferred dividends decreased $2 million or 23 percent in 2002 primarily due
to a lower amount of preferred stock outstanding.
CUMULATIVE EFFECT OF ACCOUNTING CHANGES, NET OF TAX BENEFITS
A cumulative effect of an accounting change, net of tax benefit ($5 million)
was recorded in the third quarter of 2003 in connection with the adoption of
FIN 46, which required NU to consolidate RMS into NU's financial statements and
adjust its equity interest as a cumulative effect of an accounting change.
The cumulative effect of an accounting change, net of tax benefit, recorded in 2001, represents the effect of the adoption of SFAS No. 133, as amended ($22 million).
Management is responsible for the preparation, integrity, and fair presentation of the accompanying consolidated financial statements of Northeast Utilities and subsidiaries and other sections of this annual report. These financial statements, which were audited by Deloitte & Touche LLP, have been prepared in conformity with accounting principles generally accepted in the United States of America using estimates and judgments, where required, and giving consideration to materiality.
The company has endeavored to establish a control environment that encourages the maintenance of high standards of conduct in all of its business activities. Management is responsible for maintaining a system of internal control over financial reporting that is designed to provide reasonable assurance, at an appropriate cost-benefit relationship, to the company's management and Board of Trustees regarding the preparation of reliable, published financial statements. The system is supported by an organization of trained management personnel, policies and procedures, and a comprehensive program of internal audits. Through established programs, the company regularly communicates to its management employees their internal control responsibilities and obtains information regarding compliance with policies prohibiting conflicts of interest and policies segregating information between regulated and unregulated subsidiary companies. The company has standards of business conduct for all employees, as well as a code of ethics for senior financial officers.
The Audit Committee of the Board of Trustees is composed entirely of independent trustees and includes two members that the Board of Trustees considers "audit committee financial experts." The Audit Committee meets regularly with management, the internal auditors and the independent auditors to review the activities of each and to discuss audit matters, financial reporting matters, and the system of internal controls over financial reporting. The Audit Committee also meets periodically with the internal auditors and the independent auditors without management present.
Because of inherent limitations in any system of internal controls, errors or irregularities may occur and not be detected. The company believes, however, that its system of internal controls over financial reporting and control environment provide reasonable assurance that its assets are safeguarded from loss or unauthorized use and that its financial records, which are the basis for the preparation of all financial statements, are reliable. Additionally, management believes that its disclosure controls and procedures are in place and operating effectively. Disclosure controls and procedures are designed to ensure that information included in reports such as this annual report is recorded, processed, summarized, and reported within the time periods required and that the information disclosed is accumulated and reviewed by management for discussion and approval.
To the Board of Trustees and
Shareholders of Northeast Utilities:
We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Northeast Utilities and subsidiaries (a Massachusetts Trust) (the "Company") as of December 31, 2003 and 2002, and the related consolidated statements of income, comprehensive income, shareholders' equity, cash flows and income taxes for each of the three years in the period ended December 31, 2003. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Northeast Utilities and subsidiaries (a Massachusetts Trust) as of December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 1C to the consolidated financial statements, effective January 1, 2001, the Company adopted Statement of Financial Accounting Standards (SFAS) No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, and, in 2003, the Company adopted 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, and retroactively restated the 2002 and 2001 consolidated financial statements. As discussed in Notes 1E and 5, the Company adopted Financial Accounting Standards Board Interpretation No. 46, Consolidation of Variable Interest Entities, effective July 1, 2003, and SFAS No. 142, Goodwill and Other Intangible Assets, as of January 1, 2002, respectively.
/s/ DELOITTE & TOUCHE LLP
DELOITTE & TOUCHE LLP
Hartford, Connecticut
February 23, 2004
|
NORTHEAST UTILITIES AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
-------------------------------------------------------------------------------------------------------
At December 31, 2003 2002
-------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
ASSETS
------
Current Assets:
Cash and cash equivalents $ 37,196 $ 50,333
Unrestricted cash from counterparties 46,496 16,890
Restricted cash - LMP costs 93,630 -
Special deposits 79,120 30,716
Investments in securitizable assets 166,465 178,908
Receivables, less provision for uncollectible accounts
of $40,846 in 2003 and $15,425 in 2002 704,893 767,089
Unbilled revenues 125,881 126,236
Fuel, materials and supplies, at average cost 154,076 119,853
Derivative assets 301,194 130,929
Prepayments and other 63,780 110,261
------------- -------------
1,772,731 1,531,215
------------- -------------
Property, Plant and Equipment:
Electric utility 5,465,854 5,141,951
Gas utility 743,990 679,055
Competitive energy 885,953 866,294
Other 221,986 205,115
------------- -------------
7,317,783 6,892,415
Less: Accumulated depreciation 2,244,263 2,163,613
------------- -------------
5,073,520 4,728,802
Construction work in progress 356,396 320,567
------------- -------------
5,429,916 5,049,369
------------- -------------
Deferred Debits and Other Assets:
Regulatory assets 2,974,022 3,076,095
Goodwill 319,986 321,004
Purchased intangible assets, net 22,956 24,863
Prepaid pension 360,706 328,890
Other 428,567 433,444
------------- -------------
4,106,237 4,184,296
------------- -------------
Total Assets $ 11,308,884 $ 10,764,880
============= =============
|
The accompanying notes are an integral part of these consolidated financial statements.
NORTHEAST UTILITIES AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
------------------------------------------------------------------------------------------------------
At December 31, 2003 2002
------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
LIABILITIES AND CAPITALIZATION
------------------------------
Current Liabilities:
Notes payable to banks $ 105,000 $ 56,000
Long-term debt - current portion 64,936 56,906
Accounts payable 768,783 776,219
Accrued taxes 51,598 141,667
Accrued interest 41,653 40,597
Derivative liabilities 164,689 63,900
Other 249,576 208,680
--------------- ---------------
1,446,235 1,343,969
--------------- ---------------
Rate Reduction Bonds 1,729,960 1,899,312
--------------- ---------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 1,287,354 1,436,507
Accumulated deferred investment tax credits 102,652 106,471
Deferred contractual obligations 469,218 354,469
Regulatory liabilities 1,164,288 740,195
Other 247,526 270,092
--------------- ---------------
3,271,038 2,907,734
--------------- ---------------
Capitalization:
Long-Term Debt 2,481,331 2,287,144
--------------- ---------------
Preferred Stock of Subsidiaries - Non-redeemable 116,200 116,200
--------------- ---------------
Common Shareholders' Equity:
Common shares, $5 par value - authorized 225,000,000
shares; 150,398,403 shares issued and 127,695,999
shares outstanding in 2003 and 149,375,847 shares
issued and 127,562,031 shares outstanding in 2002 751,992 746,879
Capital surplus, paid in 1,108,924 1,108,338
Deferred contribution plan - employee stock
ownership plan (73,694) (87,746)
Retained earnings 808,932 765,611
Accumulated other comprehensive income 25,991 14,927
Treasury stock, 19,518,023 shares in 2003
and 18,022,415 in 2002 (358,025) (337,488)
--------------- ---------------
Common Shareholders' Equity 2,264,120 2,210,521
--------------- ---------------
Total Capitalization 4,861,651 4,613,865
--------------- ---------------
Commitments and Contingencies (Note 7)
Total Liabilities and Capitalization $ 11,308,884 $ 10,764,880
=============== ===============
|
The accompanying notes are an integral part of these consolidated financial statements.
NORTHEAST UTILITIES AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
--------------------------------------------------------------------------------------------------------------
For the Years Ended December 31, 2003 2002 2001
--------------------------------------------------------------------------------------------------------------
(Thousands of Dollars, except share information)
Operating Revenues $ 6,069,156 $ 5,237,000 $ 5,760,949
----------------- ----------------- -----------------
Operating Expenses:
Operation -
Fuel, purchased and net interchange power 3,730,416 3,046,781 3,428,465
Other 900,437 752,482 773,058
Maintenance 232,030 263,487 258,961
Depreciation 204,388 205,646 201,013
Amortization 182,675 312,955 884,624
Amortization of rate reduction bonds 153,172 148,589 98,413
Taxes other than income taxes 232,672 227,518 219,197
Gain on sale of utility plant - (187,113) (641,956)
----------------- ----------------- -----------------
Total operating expenses 5,635,790 4,770,345 5,221,775
----------------- ----------------- -----------------
Operating Income 433,366 466,655 539,174
Interest Expense:
Interest on long-term debt 126,259 134,471 140,497
Interest on rate reduction bonds 108,359 115,791 87,616
Other interest 11,740 20,249 51,545
----------------- ----------------- -----------------
Interest expense, net 246,358 270,511 279,658
----------------- ----------------- -----------------
Other(Loss)/Income, Net (435) 43,828 187,627
----------------- ----------------- -----------------
Income Before Income Tax Expense 186,573 239,972 447,143
Income Tax Expense 59,862 82,304 173,952
----------------- ----------------- -----------------
Income Before Preferred Dividends of Subsidiaries 126,711 157,668 273,191
Preferred Dividends of Subsidiaries 5,559 5,559 7,249
----------------- ----------------- -----------------
Income Before Cumulative Effect of
Accounting Changes, Net of Tax Benefits 121,152 152,109 265,942
Cumulative effect of accounting changes,
net of tax benefits of $2,553 in 2003 and
$14,908 in 2001 (4,741) - (22,432)
----------------- ----------------- -----------------
Net Income $ 116,411 $ 152,109 $ 243,510
================= ================= =================
Basic Earnings/(Loss) Per Common Share:
Income before cumulative effect of
accounting changes, net of tax benefits $ 0.95 $ 1.18 $ 1.97
Cumulative effect of accounting changes,
net of tax benefits (0.04) - (0.17)
----------------- ----------------- -----------------
Basic Earnings Per Common Share $ 0.91 $ 1.18 $ 1.80
================= ================= =================
Fully Diluted Earnings/(Loss) Per Common Share:
Income before cumulative effect of
accounting changes, net of tax benefits $ 0.95 $ 1.18 $ 1.96
Cumulative effect of accounting changes,
net of tax benefits (0.04) - (0.17)
----------------- ----------------- -----------------
Fully Diluted Earnings Per Common Share $ 0.91 $ 1.18 $ 1.79
================= ================= =================
Basic Common Shares Outstanding (average) 127,114,743 129,150,549 135,632,126
================= ================= =================
Fully Diluted Common Shares Outstanding (average) 127,240,724 129,341,360 135,917,423
================= ================= =================
|
The accompanying notes are an integral part of these consolidated financial statements.
NORTHEAST UTILITIES AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
---------------------------------------------------------------------------------------------------
For the Years Ended December 31, 2003 2002 2001
---------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Net Income $ 116,411 $ 152,109 $ 243,510
------------- ------------- -------------
Other comprehensive income/(loss), net of tax:
Qualified cash flow hedging instruments 9,274 52,360 (36,859)
Unrealized gains/(losses) on securities 2,093 (5,121) 2,620
Minimum supplemental executive retirement
pension liability adjustments (303) 158 -
------------- ------------- -------------
Other comprehensive income/(loss), net of tax 11,064 47,397 (34,239)
------------- ------------- -------------
Comprehensive Income $ 127,475 $ 199,506 $ 209,271
============= ============= =============
|
The accompanying notes are an integral part of these consolidated financial statements.
NORTHEAST UTILITIES AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
---------------------------------------------------------------------------------------------------------------------------
Deferred
Common Shares Capital Contribution Retained
-------------------------- Surplus, Plan- Earnings
Shares Amount Paid In ESOP (a)
---------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars, except share information)
Balance as of
January 1, 2001 143,820,405 $743,909 $1,106,580 $(114,463) $495,873
---------------------------------------------------------------------------------------------------------------------------
Net income for 2001 243,510
Cash dividends on common
shares - $0.45 per share (60,923)
Issuance of common shares, $5 par value 108,779 544 1,207
Allocation of benefits - ESOP 546,610 (2,296) 12,654
Repurchase of common shares (14,343,658)
Mark-to-market on forward
share purchase arrangement
Capital stock expenses, net 2,118
Other comprehensive loss
---------------------------------------------------------------------------------------------------------------------------
Balance as of
December 31, 2001 130,132,136 744,453 1,107,609 (101,809) 678,460
---------------------------------------------------------------------------------------------------------------------------
Net income for 2002 152,109
Cash dividends on common
shares - $0.525 per share (67,793)
Issuance of common shares, $5 par value 485,207 2,426 5,032
Allocation of benefits - ESOP and
restricted stock 607,475 (4,679) 14,063 2,835
Repurchase of common shares (3,662,787)
Capital stock expenses, net 376
Other comprehensive income
---------------------------------------------------------------------------------------------------------------------------
Balance as of
December 31, 2002 127,562,031 746,879 1,108,338 (87,746) 765,611
---------------------------------------------------------------------------------------------------------------------------
Net income for 2003 116,411
Cash dividends on common
shares - $0.575 per share (73,090)
Issuance of common shares, $5 par value 1,022,556 5,113 8,541
Allocation of benefits - ESOP 607,020 (4,030) 14,052
Issuance of restricted shares, net (c) (4,110)
Repurchase of common shares (1,495,608)
Capital stock expenses, net 185
Other comprehensive income
---------------------------------------------------------------------------------------------------------------------------
Balance as of
December 31, 2003 127,695,999 $751,992 $1,108,924 $(73,694) $808,932
---------------------------------------------------------------------------------------------------------------------------
|
NORTHEAST UTILITIES AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
---------------------------------------------------------------------------------------------------
Accumulated
Other
Comprehensive Treasury
Income/ Stock
(Loss) (b) Total
---------------------------------------------------------------------------------------------------
(Thousands of Dollars, except share information)
Balance as of
January 1, 2001 $ 1,769 $ (15,085) $2,218,583
---------------------------------------------------------------------------------------------------
Net income for 2001 243,510
Cash dividends on common
shares - $0.45 per share (60,923)
Issuance of common shares, $5 par value 1,751
Allocation of benefits - ESOP 10,358
Repurchase of common shares (293,452) (293,452)
Mark-to-market on forward
share purchase arrangement 29,934 29,934
Capital stock expenses, net 2,118
Other comprehensive loss (34,239) (34,239)
---------------------------------------------------------------------------------------------------
Balance as of
December 31, 2001 (32,470) (278,603) 2,117,640
---------------------------------------------------------------------------------------------------
Net income for 2002 152,109
Cash dividends on common
shares - $0.525 per share (67,793)
Issuance of common shares, $5 par value 7,458
Allocation of benefits - ESOP and
restricted stock 12,219
Repurchase of common shares (58,885) (58,885)
Capital stock expenses, net 376
Other comprehensive income 47,397 47,397
---------------------------------------------------------------------------------------------------
Balance as of
December 31, 2002 14,927 (337,488) 2,210,521
---------------------------------------------------------------------------------------------------
Net income for 2003 116,411
Cash dividends on common
shares - $0.575 per share (73,090)
Issuance of common shares, $5 par value 13,654
Allocation of benefits - ESOP 10,022
Issuance of restricted shares, net (c) (4,110)
Repurchase of common shares (20,537) (20,537)
Capital stock expenses, net 185
Other comprehensive income 11,064 11,064
---------------------------------------------------------------------------------------------------
Balance as of
December 31, 2003 $25,991 $(358,025) $2,264,120
---------------------------------------------------------------------------------------------------
|
(a) The Federal Power Act, the Public Utility Holding Act of 1935 (the 1935 Act), and certain state statutes limit the payment of dividends by CL&P, PSNH, WMECO and NAEC to their respective retained earnings balances. Yankee Gas is also subject to the restrictions under the 1935 Act.
Certain consolidated subsidiaries also have dividend restrictions imposed by their long-term debt agreements. These restrictions limit the amount of retained earnings available for NU common dividends. At December 31, 2003, retained earnings available for payment of dividends totaled $353.3 million.
NGC is subject to certain dividend payment restrictions under its bond covenants.
The Utility Group credit agreement also limits dividend payments subject to the requirements that each subsidiaries' total debt to total capitalization ratio does not exceed 65 percent.
(b) During 2003, 2002 and 2001, NU repurchased 1.5 million, 3.7 million and 14.3 million common shares, respectively. These repurchases are reflected herein as reductions in the amount of common shares outstanding.
(c) Issuances of restricted stock totaled $6.1 million, and amortization totaled $2.0 million.
The accompanying notes are an integral part of these consolidated financial statements.
NORTHEAST UTILITIES AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
-------------------------------------------------------------------------------------------------------------------------
For the Years Ended December 31, 2003 2002 2001
-------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Operating Activities:
Income before preferred dividends of subsidiaries $ 126,711 $ 157,668 $ 273,191
Adjustments to reconcile to net cash flows
provided by operating activities:
Depreciation 204,388 205,646 201,013
Deferred income taxes and investment tax credits, net (120,603) (149,325) (116,704)
Amortization 182,675 312,955 884,624
Amortization of rate reduction bonds 153,172 148,589 98,413
Amortization/(deferral) of recoverable energy costs 43,874 27,623 (2,005)
Gain on sale of utility plant - (187,113) (641,956)
Increase in prepaid pension (31,816) (96,492) (92,852)
Cumulative effect of accounting change (4,741) - (22,432)
Regulatory overrecoveries/(refunds) 273,715 27,061 (74,179)
Other sources of cash 20,002 94,664 110,562
Other uses of cash (169,011) (148,027) (127,958)
Changes in current assets and liabilities:
Restricted cash - LMP costs (93,630) - -
Unrestricted cash from counterparties (29,606) 2,757 (19,624)
Receivables and unbilled revenues, net 62,551 (102,181) (301,068)
Fuel, materials and supplies (34,223) (27,590) 55,195
Investments in securitizable assets 12,443 27,459 61,779
Other current assets (excludes cash) (24,863) 6,547 (183,944)
Accounts payable (7,436) 163,541 100,277
Accrued taxes (90,069) 114,296 (27,439)
Other current liabilities 100,039 11,671 127,538
---------- ---------- -----------
Net cash flows provided by operating activities 573,572 589,749 302,431
---------- ---------- -----------
Investing Activities:
Investments in plant:
Electric, gas and other utility plant (532,251) (463,498) (422,490)
Competitive energy assets (17,707) (21,010) (14,639)
Nuclear fuel - (465) (14,275)
---------- ---------- -----------
Cash flows used for investments in plant (549,958) (484,973) (451,404)
Investments in nuclear decommissioning trusts - (9,876) (105,076)
Net proceeds from the sale of utility plant - 366,786 1,045,284
Buyout/buydown of IPP contracts (20,437) (5,152) (1,157,172)
Payment for acquisitions, net of cash acquired - (16,351) (31,699)
CVEC acquisition special deposit (30,104) - -
Other investment activities 21,698 15,234 (51,677)
---------- ---------- -----------
Net cash flows used in investing activities (578,801) (134,332) (751,744)
---------- ---------- -----------
Financing Activities:
Issuance of common shares 13,654 7,458 1,751
Repurchase of common shares (20,537) (57,800) (291,789)
Issuance of long-term debt 268,368 310,648 703,000
Issuance of rate reduction bonds - 50,000 2,118,400
Retirement of rate reduction bonds (169,352) (169,039) (100,049)
Increase/(decrease) in short-term debt 49,000 (234,500) (1,019,477)
Reacquisitions and retirements of long-term debt (65,600) (314,773) (714,226)
Reacquisitions and retirements of preferred stock - - (60,768)
Retirement of monthly income preferred securities - - (100,000)
Retirement of capital lease obligation - - (180,000)
Cash dividends on preferred stock of subsidiaries (5,559) (5,559) (7,249)
Cash dividends on common shares (73,090) (67,793) (60,923)
Other financing activities (4,792) (736) 37,660
---------- ---------- -----------
Net cash flows (used in)/provided by financing activities (7,908) (482,094) 326,330
---------- ----------- -----------
Net decrease in cash and cash equivalents (13,137) (26,677) (122,983)
Cash and cash equivalents - beginning of year 50,333 77,010 199,993
---------- ---------- -----------
Cash and cash equivalents - end of year $ 37,196 $ 50,333 $ 77,010
========== ========== ===========
|
The accompanying notes are an integral part of these consolidated financial statements.
----------------------------------------------------------------------------------------------------------
Consolidated Statements of Capitalization
----------------------------------------------------------------------------------------------------------
At December 31,
----------------------------------------------------------------------------------------------------------
(Thousands of Dollars) 2003 2002
----------------------------------------------------------------------------------------------------------
Common Shareholders' Equity $2,264,120 $2,210,521
----------------------------------------------------------------------------------------------------------
Preferred Stock:
CL&P Preferred Stock Not Subject to Mandatory Redemption -
$50 par value - authorized 9,000,000 shares in 2003 and 2002;
2,324,000 shares outstanding in 2003 and 2002;
Dividend rates of $1.90 to $3.28;
Current redemption prices of $50.50 to $54.00 116,200 116,200
----------------------------------------------------------------------------------------------------------
Long-Term Debt: (a)
First Mortgage Bonds:
Final Maturity Interest Rates
----------------------------------------------------------------------------------------------------------
2005 5.00% to 6.75% 89,000 116,000
2009-2012 6.20% to 7.19% 80,000 80,000
2019-2024 7.88% to 10.07% 254,045 254,995
2026 8.81% 320,000 320,000
----------------------------------------------------------------------------------------------------------
Total First Mortgage Bonds 743,045 770,995
----------------------------------------------------------------------------------------------------------
Other Long-Term Debt: (b)
Pollution Control Notes:
2016-2018 5.90% 25,400 25,400
2021-2022 Adjustable Rate and 5.45% to 6.00% 428,285 428,285
2028 5.85% to 5.95% 369,300 369,300
2031 3.35% until 2008 (c) 62,000 62,000
Other: (d)
2003 6.24% - 1,400
2004-2007 6.11% to 8.81% 76,249 101,543
2008 3.30% 150,000 -
2010 5.95% to 8.23% 8,955 6,753
2012-2014 5.00% to 9.24% 320,627 263,876
2018-2019 6.00% to 6.23% 38,476 24,297
2021-2022 6.25% to 7.63% 39,461 40,712
2024 6.23% 9,368 -
2026 7.69% 26,164 -
----------------------------------------------------------------------------------------------------------
Total Pollution Control Notes and Other 1,554,285 1,323,566
----------------------------------------------------------------------------------------------------------
Total First Mortgage Bonds, Pollution Control Notes and Other 2,297,330 2,094,561
----------------------------------------------------------------------------------------------------------
Fees and interest due for spent nuclear fuel disposal costs (e) 256,438 253,638
Change in Fair Value (f) (3,577) -
Unamortized premium and discount, net (3,924) (4,149)
----------------------------------------------------------------------------------------------------------
Total Long-Term Debt 2,546,267 2,344,050
Less: Amounts due within one year 64,936 56,906
----------------------------------------------------------------------------------------------------------
Long-Term Debt, Net 2,481,331 2,287,144
----------------------------------------------------------------------------------------------------------
Total Capitalization $4,861,651 $4,613,865
----------------------------------------------------------------------------------------------------------
|
The accompanying notes are an integral part of these consolidated financial statements.
NOTES TO CONSOLIDATED STATEMENTS OF CAPITALIZATION
(a) Long-term debt maturities and cash sinking fund requirements on debt outstanding at December 31, 2003, for the years 2004 through 2008 and thereafter, are as follows:
-------------------------------------------- Year -------------------------------------------- 2004 $ 64.9 2005 92.1 2006 27.8 2007 9.6 2008 161.2 Thereafter 1,941.7 -------------------------------------------- Total $2,297.3 -------------------------------------------- |
Essentially all utility plant of CL&P, PSNH, NGC, and Yankee is subject to the liens of each company's respective first mortgage bond indenture.
CL&P has $315.5 million of pollution control notes secured by second mortgage liens on transmission assets, junior to the liens of its first mortgage bond indentures.
CL&P has $62 million of tax-exempt Pollution Control Revenue Bonds (PCRBs) with bond insurance and secured by the first mortgage bonds. For financial reporting purposes, this debt is not considered to be first mortgage bonds unless CL&P failed to meet its obligations under the PCRBs.
PSNH entered into financing arrangements with the Business Finance Authority (BFA) of the state of New Hampshire. Pursuant to which, the BFA issued five series of PCRBs and loaned the proceeds to PSNH. At December 31, 2003 and 2002, $407.3 million of the PCRBs were outstanding. PSNH's obligation to repay each series of PCRBs is secured by bond insurance and first mortgage bonds. Each such series of first mortgage bonds contains similar terms and provisions as the applicable series of PCRBs. For financial reporting purposes, these first mortgage bonds would not be considered outstanding unless PSNH failed to meet its obligations under the PCRBs.
NU's long-term debt agreements provide that certain of its subsidiaries must comply with certain financial and non-financial covenants as are customarily included in such agreements, including but not limited to, debt service coverage ratios and interest coverage ratios. The parties to these agreements currently are and expect to remain in compliance with these covenants.
(b) The weighted average effective interest rate on the variable-rate pollution control notes ranged from 0.99 percent to 1.08 percent for 2003 and 1.39 percent to 1.42 percent for 2002.
(c) The interest rate of 3.35 percent is effective through October 1, 2008 at which time the bonds will be remarketed, and the interest rate will be adjusted.
(d) Other long-term debt - other at December 31, 2003, includes the issuance of $150 million, $63.4 million and $55 million of long-term debt related to NU parent, SESI and WMECO in 2003.
(e) For information regarding fees and interest due for spent nuclear fuel disposal costs, see Note 7D, "Commitments and Contingencies - Spent Nuclear Fuel Disposal Costs," to the consolidated financial statements.
(f) The fair value of the NU parent 7.25 percent amortizing note due 2012 in the amount of $263 million is hedged with a fixed to floating interest rate swap. The change in fair value of the debt was recorded as an adjustment to long-term debt with an equal and offsetting adjustment to derivative assets for the change in fair value of the fixed to floating interest rate swap.
---------------------------------------------------------------------------------------------------
Consolidated Statements of Income Taxes
---------------------------------------------------------------------------------------------------
For the Years Ended December 31,
---------------------------------------------------------------------------------------------------
(Thousands of Dollars) 2003 2002 2001
---------------------------------------------------------------------------------------------------
The components of the federal and
state income tax provisions are:
Current income taxes:
Federal $ 143,349 $ 197,426 $ 244,501
State 37,116 34,204 46,155
---------------------------------------------------------------------------------------------------
Total current 180,465 231,630 290,656
---------------------------------------------------------------------------------------------------
Deferred income taxes, net:
Federal (82,518) (108,524) (80,968)
State (34,266) (14,210) (15,644)
---------------------------------------------------------------------------------------------------
Total deferred (116,784) (122,734) (96,612)
---------------------------------------------------------------------------------------------------
Investment tax credits, net (3,819) (26,592) (20,092)
---------------------------------------------------------------------------------------------------
Total income tax expense $ 59,862 $ 82,304 $ 173,952
---------------------------------------------------------------------------------------------------
Deferred income taxes are comprised of the tax effects of
temporary differences as follows:
Deferred tax asset associated with net operating losses $ - $ - $ 2,206
Depreciation 55,002 51,146 (8,956)
Net regulatory deferral (149,087) (141,567) (44,127)
Sale of generation assets - (20,500) (225,019)
Pension (3,467) (1,720) 24,183
Loss on bond redemptions (3,487) (1,084) 12,396
Contract termination costs, net of amortization (9,121) (9,500) 113,719
Change in fair value of energy contracts (12,310) 20,691 15,780
Other 5,686 (20,200) 13,206
---------------------------------------------------------------------------------------------------
Deferred income taxes, net $(116,784) $(122,734) $ (96,612)
---------------------------------------------------------------------------------------------------
A reconciliation between income tax expense and the expected
tax expense at the statutory rate is as follows:
Expected federal income tax $ 65,301 $ 83,990 $ 156,500
Tax effect of differences:
Depreciation 4,010 10,404 5,313
Amortization of regulatory assets 6,487 14,966 10,260
Investment tax credit amortization (3,819) (26,592) (20,092)
State income taxes, net of federal benefit 1,853 12,996 19,832
Dividends received deduction (1,370) (3,237) (3,382)
Tax asset valuation allowance/reserve adjustments (5,379) (111) (7,000)
Merger-related expenditures - - (4,589)
Nondeductible stock expenses - - 12,388
Other, net (7,221) (10,112) 4,722
---------------------------------------------------------------------------------------------------
Total income tax expense $ 59,862 $ 82,304 $ 173,952
---------------------------------------------------------------------------------------------------
|
NU and its subsidiaries file a consolidated federal income tax return. Likewise NU and its subsidiaries file state income tax returns, with some filing in more than one state. NU and its subsidiaries are parties to a tax allocation agreement under which each taxable subsidiary pays a quarterly estimate (or settlement) of no more than it would have otherwise paid had it filed a stand-alone tax return. Generally these quarterly estimated payments are settled to actual payments within three months after filing the associated return. Subsidiaries generating tax losses are similarly paid for their losses when utilized.
The accompanying notes are also an integral part of these consolidated financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A. ABOUT NORTHEAST UTILITIES Consolidated: Northeast Utilities (NU or the company) is the parent company of companies comprising the Utility Group and NU Enterprises. NU is registered with the Securities and Exchange Commission (SEC) as a holding company under the Public Utility Holding Company Act of 1935 (1935 Act) and is subject to the provisions of the 1935 Act. Arrangements among the Utility Group, NU Enterprises and other NU companies, outside agencies and other utilities covering interconnections, interchange of electric power and sales of utility property are subject to regulation by the Federal Energy Regulatory Commission (FERC) and/or the SEC. The Utility Group is subject to further regulation for rates, accounting and other matters by the FERC and/or applicable state regulatory commissions.
Several wholly owned subsidiaries of NU provide support services for NU's companies. Northeast Utilities Service Company provides centralized accounting, administrative, engineering, financial, information technology, legal, operational, planning, purchasing, and other services to NU's companies. Three other subsidiaries construct, acquire or lease some of the property and facilities used by NU's companies.
Utility Group: The Utility Group furnishes franchised retail electric service in Connecticut, New Hampshire and Massachusetts through three companies: The Connecticut Light and Power Company (CL&P), Public Service Company of New Hampshire (PSNH) and Western Massachusetts Electric Company (WMECO). Another company, North Atlantic Energy Corporation (NAEC), previously sold all of its entitlement to the capacity and output of the Seabrook nuclear unit (Seabrook) to PSNH under the terms of two life-of-unit, full cost recovery contracts (Seabrook Power Contracts). Seabrook was sold on November 1, 2002. Another Utility Group subsidiary is Yankee Gas Services Company (Yankee Gas), which is Connecticut's largest natural gas distribution system. The Utility Group includes two reportable segments: the regulated electric utility segment and the regulated gas utility segment.
Effective January 1, 2004, PSNH completed the purchase of the electric system and retail franchise of Connecticut Valley Electric Company (CVEC), a subsidiary of Central Vermont Public Service Corporation (CVPS), for $30.1 million. CVEC's 11,000 customers in western New Hampshire have been added to PSNH's customer base of more than 460,000 customers. The purchase price included the book value of CVEC's plant assets of approximately $9 million and an additional $21 million to terminate an above-market wholesale power purchase agreement CVEC had with CVPS. The $21 million payment will be recovered from PSNH's customers.
NU Enterprises: These companies include Select Energy, Inc. and subsidiary (Select Energy), a company engaged in wholesale and retail marketing activities; Northeast Generation Company (NGC) and Holyoke Water Power Company (HWP), companies that maintain 1,293 megawatts (MW) and 147 MW, respectively, of generation capacity that is used to support Select Energy's merchant energy business line; Select Energy Services, Inc. and subsidiaries (SESI), a company that performs energy management services for large commercial customers, institutional facilities, and the United States government and engages in energy-related construction services; Northeast Generation Services Company and subsidiaries (NGS), a company that operates and maintains NGC's and HWP's generation assets and provides third-party electrical services; and Woods Network Services, Inc. (Woods Network), a network design, products and service company. NU Enterprises is one reportable segment that includes two business lines: the merchant energy business line and the energy services business line.
B. PRESENTATION The consolidated financial statements of NU and of its subsidiaries, as applicable, include the accounts of all their respective subsidiaries. Intercompany transactions have been eliminated in consolidation.
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingencies at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Certain reclassifications of prior years' data have been made to conform with the current year's presentation. Reclassifications were made to cost of removal, regulatory asset and liability amounts and special deposits on the accompanying consolidated balance sheets and operating revenues and fuel, purchased and net interchange power on the accompanying consolidated statements of income. Reclassifications have also been made to the accompanying consolidated statements of cash flows and consolidated statements of income taxes.
C. NEW ACCOUNTING STANDARDS Derivative Accounting: Effective January 1, 2001, NU adopted Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended resulting in a negative cumulative effect of accounting change of $22.4 million. In April 2003, the Financial Accounting Standards Board (FASB) issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities," which amends SFAS No. 133. This new statement incorporates interpretations that were included in previous Derivative Implementation Group (DIG) guidance, clarifies certain conditions, and amends other existing pronouncements. It is effective for contracts entered into or modified after June 30, 2003. Management has determined that the adoption of SFAS No. 149 did not change NU's accounting for wholesale and retail marketing contracts, or the ability of NU Enterprises to elect the normal purchases and sales exception. The adoption of SFAS No. 149 resulted in fair value accounting for certain of Utility Group contracts that are subject to unplanned netting and do not meet the definition of capacity contracts. These non-trading derivative contracts are recorded at fair value at December 31, 2003, as derivative assets and liabilities with offsetting amounts recorded as regulatory liabilities and assets because the contracts are part of providing regulated electric or gas service.
In August of 2003, the FASB ratified the consensus reached by its Emerging Issues Task Force (EITF) in July 2003 on EITF Issue No. 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." Prior to Issue No. 03-11, no specific guidance existed to address the classification in the income statement of derivative contracts that are not held for trading purposes. The consensus states that determining whether realized gains and losses on contracts that physically deliver and are not held for trading purposes should be reported on a net or gross basis is a matter of judgment that depends on the relevant facts and circumstances. NU Enterprises and the Utility Group have derivative sales contracts, and though these contracts may result in physical delivery, management has determined, based on the relevant facts and circumstances, that because these transactions are part of the respective companies' procurement activities, inclusion in operating expenses better depicts these sales activities. At December 31, 2003, settlements of these derivative contracts that are not held for trading purposes, though previously reported on a gross basis, are reported on a net basis in expenses. Sales amounting to $645.9 million for the first nine months of 2003 were reflected as revenues in quarterly reporting but are now included in expenses.
In Issue No. 03-11, the EITF did not provide transition guidance, which management could have interpreted as becoming applicable on October 1, 2003 for revenues from that date forward. However, management applied its conclusion on net or gross reporting to all periods presented to enhance comparability. Operating revenues and fuel, purchased and net interchange power for the year ended December 31, 2003 reflect net reporting. The adoption of net reporting had no effect on net income.
The impact on previously reported 2002 and 2001 amounts is as follows:
-------------------------------------------------------------------------------
For the Years Ended December 31,
-------------------------------------------------------------------------------
Millions of Dollars 2002 2001
-------------------------------------------------------------------------------
Operating Revenues:
As previously reported $5,216.3 $5,968.2
Impact of reclassifications 20.7 (207.2)
-------------------------------------------------------------------------------
As currently reported $5,237.0 $5,761.0
-------------------------------------------------------------------------------
Fuel, Purchased and Net
Interchange Power:
As previously reported $3,026.1 $3,635.7
Impact of reclassifications 20.7 (207.2)
-------------------------------------------------------------------------------
As currently reported $3,046.8 $3,428.5
-------------------------------------------------------------------------------
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On June 25, 2003, the DIG cleared Issue No. C-20, which addressed the meaning of "not clearly and closely related regarding contracts with a price adjustment feature" as it relates to the election of the normal purchase and sales exception to derivative accounting. The implementation of this guidance was required to be adopted in the fourth quarter of 2003 for NU. Issue No. C-20 resulted in CL&P recording the fair value of two existing power purchase contracts as derivatives, one as a derivative asset and one as a derivative liability with offsetting regulatory liabilities and assets, as these contracts are part of stranded costs and as management believes that these costs will continue to be recovered or refunded in rates. The fair values of these long-term power purchase contracts include a derivative asset with a fair value of $112.4 million and a derivative liability with a fair value of $54.6 million at December 31, 2003.
Employers' Disclosures about Pensions and Other Postretirement Benefits: In December 2003, the FASB issued SFAS No. 132 (Revised 2003), "Employers' Disclosures about Pensions and Other Postretirement Benefits," (SFAS No. 132R). This statement revises employers' disclosures about pension plans and other postretirement benefit plans, requires additional disclosures about the assets, obligations, cash flows, and the net periodic benefit cost of defined benefit pension plans and other defined benefit postretirement plans and requires companies to disclose various elements of pension and postretirement benefit costs in interim period financial statements. The revisions in SFAS No. 132R are effective for 2003, and NU included the disclosures required by SFAS No. 132R in this annual report. For the required disclosures, see Note 4A, "Employee Benefits - Pension Benefits and Postretirement Benefits Other Than Pensions," to the consolidated financial statements.
Liabilities and Equity: In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity." SFAS No. 150 establishes standards on how to classify and measure certain financial instruments with characteristics of both liabilities and equity. SFAS No. 150 is effective for financial instruments entered into or modified after May 31, 2003, and was otherwise effective for NU for the third quarter of 2003. The adoption of SFAS No. 150 did not have an impact on NU's consolidated financial statements.
Consolidation of Variable Interest Entities: In December 2003, the FASB issued a revised version of FASB Interpretation No. (FIN) 46, "Consolidation of Variable Interest Entities," (FIN 46R). FIN 46R could result in fewer NU investments meeting the definition of a variable interest entity (VIE). FIN 46R is effective for NU for the first quarter of 2004 but is not expected to have an impact on NU's consolidated financial statements.
D. GUARANTEES NU provides credit assurance in the form of guarantees and letters of credit in the normal course of business, primarily for the financial performance obligations of NU Enterprises. NU would be required to perform under these guarantees in the event of non-performance by NU Enterprises, primarily Select Energy. At December 31, 2003, the maximum level of exposure under guarantees by NU, primarily on behalf of NU Enterprises, totaled $552.6 million. Additionally, NU had $106.9 million of letters of credit issued for the benefit of NU Enterprises outstanding at December 31, 2003. In conjunction with its investment in R. M. Services, Inc. (RMS), NU guarantees a $3 million line of credit through 2005, of which $1.3 million was outstanding at December 31, 2003, which is included in the $552.6 million of total guarantees outstanding. Effective July 1, 2003, NU now consolidates the financial statements of RMS and the line of credit balance with its financial statements.
CL&P has obtained surety bonds in the amount of $31.1 million related to the collection of March 2003 and April 2003 incremental locational marginal pricing (LMP) costs in compliance with a Connecticut Department of Public Utility Control (DPUC) order. At December 31, 2003, NU had outstanding guarantees to the Utility Group of $48 million, including the LMP-related surety bonds. This amount is included in the total outstanding NU guarantee amount of $552.6 million.
The NU guarantees and surety bonds contain credit ratings triggers that would require NU to post collateral in the event that NU's credit ratings are downgraded.
NU currently has authorization from the SEC to provide up to $500 million of guarantees for NU Enterprises through June 30, 2004, and has applied for authority to increase this amount to $750 million through September 30, 2007. The guarantees to the Utility Group are subject to a separate $50 million SEC limitation apart from the current $500 million guarantee limit. The amount of guarantees outstanding for compliance with the SEC limit for NU Enterprises is $288.5 million, which is calculated using different criteria than the maximum level of exposure required to be disclosed under FIN 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others."
E. ACCOUNTING FOR R.M. SERVICES, INC. VARIABLE INTEREST ENTITY On June 30, 2001, NU sold RMS, a provider of consumer collection services, for $10 million in the form of convertible cumulative 5 percent preferred stock and a warrant to buy 25 percent of the outstanding common stock of RMS for $1,000 that expires in 2021. NU also agreed to guarantee a $3 million line of credit for RMS through 2005. Beginning in the second quarter of 2003, RMS began drawing on this line of credit.
In January 2003, the FASB issued FIN 46, which was effective for NU on July 1, 2003. RMS is a VIE, as defined. FIN 46 requires that the party to a VIE that absorbs the majority of the VIE's losses, defined as the "primary beneficiary," consolidate the VIE. Upon adoption of FIN 46 on July 1, 2003, management determined that NU was the "primary beneficiary" of RMS under FIN 46 and that NU was now required to consolidate RMS into its financial statements. To consolidate RMS, NU eliminated the carrying value of its preferred stock investment in RMS and recorded the assets and liabilities of RMS. This adjustment resulted in a negative $4.7 million after-tax cumulative effect of an accounting change in the third quarter of 2003, and is summarized as follows (in millions):
-----------------------------------------------------------
Assets and Liabilities Recorded:
-----------------------------------------------------------
Current assets $ 0.6
Net property, plant and equipment 1.7
Other noncurrent assets 1.5
Current liabilities (0.6)
-----------------------------------------------------------
3.2
-----------------------------------------------------------
Elimination of investment at July 1, 2003 10.5
-----------------------------------------------------------
Pre-tax cumulative effect 7.3
Income tax effect (2.6)
-----------------------------------------------------------
Cumulative effect of an accounting change $ 4.7
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Prior to the consolidation of RMS on July 1, 2003, NU recorded $0.9 million of after-tax impairment losses on the investment balance. After RMS was consolidated, $1.9 million of after-tax operating losses were included in earnings.
NU has no other VIE's for which it is defined as the "primary beneficiary."
For further information regarding NU's investments in other VIEs, see Note 1K, "Summary of Significant Accounting Policies - Equity Investments and Jointly Owned Electric Utility Plant," to the consolidated financial statements.
F. REVENUES Utility Group: Utility Group retail revenues are based on rates approved by the state regulatory commissions. These regulated rates are applied to customers' use of energy to calculate a bill. In general, rates can only be changed through formal proceedings with the state regulatory commissions.
Certain Utility Group companies utilize regulatory commission-approved tracking mechanisms to track the recovery of certain incurred costs. The tracking mechanisms allow for rates to be changed periodically, with overcollections refunded to customers or undercollections collected from customers in future periods.
Unbilled revenues represent an estimate of electricity or gas delivered to customers that has not been billed. Unbilled revenues represent assets on the balance sheet that become accounts receivable in the following month as customers are billed. Billed revenues are based on meter readings.
Unbilled revenues are estimated monthly using the requirements method. The requirements method utilizes the total monthly volume of electricity or gas delivered to the system and applies a delivery efficiency factor to reduce the total monthly volume by an estimate of delivery losses in order to calculate total estimated monthly sales to customers. The total estimated monthly sales amount less total monthly billed sales amount results in a monthly estimate of unbilled sales. Unbilled revenues are estimated by applying an average rate to the estimate of unbilled sales.
In 2003, the unbilled sales estimates for all Utility Group companies were tested using the cycle method. The cycle method uses the billed sales from each meter reading cycle and an estimate of unbilled days in each month based on the meter reading schedule. The cycle method is historically more accurate than the requirements method when used in a mostly weather-neutral month. The cycle method resulted in adjustments to the estimate of unbilled revenues that had a net positive after-tax earnings impact of approximately $4.6 million in 2003. The positive after-tax impacts on CL&P, PSNH, and WMECO were $7.2 million, $3.3 million, and $0.3 million, respectively. There was a negative after-tax impact on Yankee Gas of $6.2 million including certain gas cost adjustments.
Wholesale transmission revenues are based on rates and formulas that are approved by the FERC. Most of NU's wholesale transmission revenues are collected through a combination of the New England Regional Network Service (RNS) tariff and NU's Local Network Service (LNS) tariff. The RNS tariff, which is administered by the New England Independent System Operator (ISO- NE), recovers the revenue requirements associated with transmission facilities that are deemed by the FERC to be Pool Transmission Facilities. The LNS tariff which was accepted by the FERC on October 22, 2003, provides for the recovery of NU's total transmission revenue requirements, net of revenue credits received from various rate components, including revenues received under the RNS rates.
NU Enterprises: NU Enterprises' revenues are recognized at different times for its different business lines. Wholesale and retail marketing revenues are recognized when energy is delivered. Trading revenues are recognized as the fair value of trading contracts changes. Service revenues are recognized as services are provided, often on a percentage of completion basis.
G. ACCOUNTING FOR ENERGY CONTRACTS The accounting treatment for energy contracts entered into varies between contracts and depends on the intended use of the particular contract and on whether or not the contracts are derivatives.
Non-derivative contracts that are entered into for the normal purchase or sale of energy to customers that will result in physical delivery are recorded at the point of delivery under accrual accounting.
Derivative contracts that are entered into for the normal purchase and sale of energy and meet the normal purchase and sale exception to derivative accounting, as defined in SFAS No. 133 and amended by SFAS No. 149 (normal), are also recorded at the point of delivery under accrual accounting.
Both long-term non-derivative contracts and long-term derivative contracts that are normal are recorded in revenues when these contracts represent sales, and recorded in fuel, purchased and net interchange power when these contracts represent purchases, except for sales contracts that relate to procurement activities. These contracts are recorded in fuel, purchased and net interchange power when settled.
Derivative contracts that are entered into for trading purposes are recorded on the consolidated balance sheets at fair value, and changes in fair value impact earnings. Revenues and expenses for these contracts are recorded on a net basis in revenues. Derivative contracts that are not held for trading purposes and that do not qualify as normal purchases and sales or hedges are non-trading derivative contracts. These contracts are recorded on the consolidated balance sheets at fair value, and changes in fair value impact earnings. Revenues and expenses for these contracts are recorded net in revenues.
Contracts that are hedging an underlying transaction and that qualify as cash flow hedges are recorded on the consolidated balance sheets at fair value with changes in fair value generally reflected in accumulated other comprehensive income. Hedges impact earnings when the forecasted transaction being hedged occurs, when hedge ineffectiveness is measured and recorded, when the forecasted transaction being hedged is no longer probable of occurring, or when there is an accumulated other comprehensive loss and when the hedge and the forecasted transaction being hedged are in a loss position on a combined basis.
For further information regarding these contracts and their accounting, see Note 3, "Derivative Instruments, Market Risk and Risk Management," to the consolidated financial statements.
H. UTILITY GROUP REGULATORY ACCOUNTING The accounting policies of NU's Utility Group conform to accounting principles generally accepted in the United States of America applicable to rate-regulated enterprises and historically reflect the effects of the rate- making process in accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation."
The transmission and distribution businesses of CL&P, PSNH and WMECO, along
with PSNH's generation business and Yankee Gas' distribution business,
continue to be cost-of-service rate regulated. The state's electric utility
industry restructuring laws have been modified to delay the sale of PSNH's
fossil and hydroelectric generation assets until at least April of 2006.
There has been no regulatory action to the contrary, and management currently
has no plans to divest these generation assets. As the New Hampshire Public
Utilities Commission (NHPUC) has allowed and is expected to continue to allow
rate recovery of a return on and recovery of these assets, as well as all
operating expenses, PSNH meets the criteria for the application of SFAS No.
71. Stranded costs related to generation assets, to the extent not currently
recovered in rates, are deferred as Part 3 stranded costs under the
"Agreement to Settle PSNH Restructuring" (Restructuring Settlement). Part 3
stranded costs are nonsecuritized regulatory assets which must be recovered
by a recovery end date determined in accordance with the Restructuring
Settlement or be written off.
Management believes the application of SFAS No. 71 to the portions of the aforementioned businesses continues to be appropriate. Management also believes it is probable that NU's operating companies will recover their investments in long-lived assets, including regulatory assets. In addition, all material net regulatory assets are earning an equity return, except for securitized regulatory assets, which are not supported by equity.
The components of regulatory assets are as follows:
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At December 31,
--------------------------------------------------------------------------
(Millions of Dollars) 2003 2002
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Recoverable nuclear costs $ 82.4 $ 85.4
Securitized assets 1,721.1 1,891.8
Income taxes, net 253.8 326.4
Unrecovered contractual obligations 378.6 239.3
Recoverable energy costs 255.7 299.6
Other 282.4 233.6
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Totals $2,974.0 $3,076.1
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Additionally, the Utility Group had $12.3 million and $6.1 million of regulatory assets at December 31, 2003 and 2002, respectively, that are included in deferred debits and other assets - other on the accompanying consolidated balance sheets. These amounts represent regulatory assets that have not yet been approved by the applicable regulatory agency. Management believes these assets are recoverable in future rates.
Recoverable Nuclear Costs: In March 2001, CL&P and WMECO sold their ownership interests in the Millstone nuclear units (Millstone). The gains on the sale in the amounts of $521.6 million and $119.8 million, respectively, for CL&P and WMECO were used to offset recoverable nuclear costs, resulting in unamortized balances of $22.5 million and $13.1 million at December 31, 2003 and 2002, respectively. Additionally, PSNH recorded a regulatory asset in conjunction with the sale of the Millstone units with an unamortized balance of $33.3 million and $36.8 million at December 31, 2003 and 2002, respectively, which is also included in recoverable nuclear costs. Also included in recoverable nuclear costs for 2003 and 2002 are $26.6 million and $35.5 million, respectively, primarily related to Millstone 1 recoverable nuclear costs associated with the undepreciated plant and related assets at the time Millstone 1 was shut down.
Securitized Assets: In March 2001, CL&P issued $1.4 billion in rate reduction certificates. CL&P used $1.1 billion of those proceeds to buy out or buy down certain contracts with independent power producers (IPP). The remaining balance is $960 million and $1.1 billion at December 31, 2003 and 2002, respectively. CL&P also securitized a portion of its SFAS No. 109, "Accounting for Income Taxes," regulatory asset which had a balance of $164.1 million and $180.7 million at December 31, 2003 and 2002, respectively.
In April 2001, PSNH issued rate reduction certificates in the amount of $525 million. PSNH used the majority of this amount to buy down its power contract with NAEC. The remaining balance is $427 million and $460 million at December 31, 2003 and 2002, respectively.
In May 2001, WMECO issued $155 million in rate reduction certificates and used $80 million of those proceeds to buy out an IPP contract. The remaining balance is $132 million and $142 million at December 31, 2003 and 2002, respectively.
In January 2002, PSNH issued an additional $50 million in rate reduction certificates and used the proceeds from this issuance to repay short-term debt that was incurred to buy out a purchased-power contract in December 2001. The remaining balance is $38 million and $46 million at December 31, 2003 and 2002, respectively.
Securitized assets are being recovered over the amortization period of their associated rate reduction bonds. All outstanding rate reduction bonds of CL&P are scheduled to amortize by December 30, 2010, while PSNH rate reduction bonds are scheduled to fully amortize by May 1, 2013, and those of WMECO are scheduled to fully amortize by June 1, 2013.
Income Taxes, Net: The tax effect of temporary differences (differences between the periods in which transactions affect income in the financial statements and the periods in which they affect the determination of taxable income) is accounted for in accordance with the rate-making treatment of the applicable regulatory commissions and SFAS No. 109. Differences in income taxes between SFAS No. 109 and the rate-making treatment of the applicable regulatory commissions are recorded as regulatory assets. For further information regarding income taxes, see Note 1I, "Summary of Significant Accounting Policies - Income Taxes," to the consolidated financial statements.
Unrecovered Contractual Obligations: CL&P, WMECO and PSNH, under the terms of contracts with the Yankee Companies, are responsible for their proportionate share of the remaining costs of the units, including decommissioning. These amounts are recorded as unrecovered contractual obligations. A portion of these obligations for CL&P and WMECO was securitized in 2001 and is included in securitized regulatory assets. The remaining amounts for PSNH are recovered as stranded costs. During 2002, NU was notified by the Yankee Companies that the estimated cost of decommissioning their units had increased by approximately $380 million over prior estimates due to higher anticipated costs for spent fuel storage, security and liability and property insurance. In December 2002, NU recorded an additional $171.6 million in deferred contractual obligations and a corresponding increase in the unrecovered contractual obligations regulatory asset as a result of these increased costs.
In November 2003, the Connecticut Yankee Atomic Power Company (CYAPC) prepared an updated estimate of the cost of decommissioning its nuclear unit. NU's aggregate share of the estimated increased cost is approximately $167.7 million. NU subsidiaries' respective shares of the estimated increased costs are as follows: CL&P, $118.1 million; PSNH, $17.1 million; and WMECO, $32.5 million. NU recorded an additional $167.7 million in deferred contractual obligations and a corresponding increase in the unrecovered contractual obligations regulatory asset as a result of these increased costs.
Recoverable Energy Costs: Under the Energy Policy Act of 1992 (Energy Act), CL&P, PSNH, WMECO, and NAEC were assessed for their proportionate shares of the costs of decontaminating and decommissioning uranium enrichment plants owned by the United States Department of Energy (DOE) (D&D Assessment). The Energy Act requires that regulators treat D&D Assessments as a reasonable and necessary current cost of fuel, to be fully recovered in rates like any other fuel cost. CL&P, PSNH and WMECO no longer own nuclear generation but continue to recover these costs through rates. At December 31, 2003 and 2002, NU's total D&D Assessment deferrals were $18 million and $21.9 million, respectively, and have been recorded as recoverable energy costs.
In conjunction with the implementation of restructuring under the Restructuring Settlement on May 1, 2001, PSNH's fuel and purchased-power adjustment clause (FPPAC) was discontinued. At December 31, 2003 and 2002, PSNH had $162.2 million and $179.6 million, respectively, of recoverable energy costs deferred under the FPPAC, including previous deferrals of purchases from IPPs. Under the Restructuring Settlement, the FPPAC deferrals are recovered as a Part 3 stranded cost through a stranded cost recovery charge. Also included in PSNH's recoverable energy costs are costs associated with certain contractual purchases from IPPs that had previously been included in the FPPAC. These costs are treated as Part 3 stranded costs and amounted to $56.1 million and $62.1 million at December 31, 2003 and 2002, respectively.
The regulated rates of Yankee Gas include a purchased gas adjustment clause under which gas costs above or below base rate levels are charged to or credited to customers. Differences between the actual purchased gas costs and the current rate recovery are deferred and recovered or refunded in future periods. These amounts are recorded as recoverable energy costs of $2.9 million and $3.3 million at December 31, 2003 and 2002, respectively.
Through December 31, 1999, CL&P had an energy adjustment clause under which fuel prices above or below base-rate levels were charged to or credited to customers. CL&P's energy costs deferred and not yet collected under the energy adjustment clause amounted to $31.7 million at December 31, 2002, which were recorded as recoverable energy costs. On July 26, 2001, the DPUC authorized CL&P to assess a charge of approximately $0.002 per kilowatt-hour (kWh) to collect these costs from August 2001 through December 31, 2003, at which time no unrecovered costs remained.
The majority of the recoverable energy costs are recovered in rates currently from the customers of CL&P, PSNH, WMECO, and Yankee Gas. PSNH's recoverable energy costs are Part 3 stranded costs which are nonsecuritized regulatory assets which must be recovered by a recovery end date to be determined in accordance with the Restructuring Settlement or which will be written off. Based on current projections, PSNH expects to fully recover all of its Part 3 stranded costs by the recovery end date.
Regulatory Liabilities: The Utility Group maintained $1.2 billion and $740.2 million of regulatory liabilities at December 31, 2003 and 2002, respectively. These amounts are comprised of the following:
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At December 31,
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(Millions of Dollars) 2003 2002
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Cost of removal $334.0 $321.0
CL&P CTA, GSC, and SBC overcollections 333.7 133.6
PSNH SCRC overcollections 160.4 166.2
Regulatory liabilities offsetting
Utility Group derivative assets 117.0 -
CL&P LMP overcollections 79.8 -
Yankee Gas IERM overcollections 5.3 2.9
Other regulatory liabilities 134.1 116.5
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Totals $1,164.3 $740.2
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Under SFAS No. 71, regulated utilities, including NU's Utility Group companies, currently recover amounts in rates for future costs of removal of plant assets. Historically, these amounts were included as a component of accumulated depreciation until spent. These amounts were reclassified to regulatory liabilities on the accompanying consolidated balance sheets.
The Competitive Transition Assessment (CTA) allows CL&P to recover stranded costs, such as securitization costs associated with the rate reduction bonds, amortization of regulatory assets, and IPP over market costs while the Generation Service Charge (GSC) allows CL&P to recover the costs of the procurement of energy for standard offer service. The System Benefits Charge (SBC) allows CL&P to recover certain regulatory and energy public policy costs, such as public education outreach costs, hardship protection costs, transition period property taxes, and displaced workers protection costs. The Stranded Cost Recovery Charge (SCRC) allows PSNH to recover its stranded costs. CL&P LMP overcollections represent amounts that are refundable to ratepayers related to the implementation of standard market design (SMD) on March 1, 2003. Yankee Gas' Infrastructure Expansion Rate Mechanism (IERM) tracks the revenues and expenses associated with its system expansion program.
The regulatory liabilities offsetting derivative assets relate to the fair value of CL&P IPP contracts and PSNH purchase and sales contracts used for market discovery of future procurement activities that will benefit ratepayers in the future. CL&P and PSNH also have financial transmission rights (FTR) contracts which are derivative assets offset by a regulatory liability.
I. INCOME TAXES The tax effect of temporary differences (differences between the periods in which transactions affect income in the financial statements and the periods in which they affect the determination of taxable income) is accounted for in accordance with the rate-making treatment of the applicable regulatory commissions and SFAS No. 109.
The tax effects of temporary differences that give rise to the net accumulated deferred tax obligation are as follows:
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At December 31,
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(Millions of Dollars) 2003 2002
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Deferred tax liabilities:
Accelerated depreciation and
other plant-related differences $ 904.4 $ 893.0
Regulatory amounts:
Securitized contract termination
costs and other 247.0 267.5
Income tax gross-up 178.6 220.2
Employee benefits 151.4 142.8
Other 332.2 306.6
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Total deferred tax liabilities 1,813.6 1,830.1
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Deferred tax assets:
Regulatory deferrals 341.6 238.3
Employee benefits 72.1 64.3
Income tax gross-up 20.8 25.6
Other 91.7 65.4
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Total deferred tax assets 526.2 393.6
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Totals $1,287.4 $1,436.5
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In 2000, NU requested from the Internal Revenue Service (IRS) a Private Letter Ruling (PLR) regarding the treatment of unamortized investment tax credits (ITC) and excess deferred income taxes (EDIT) related to generation assets that have been sold. EDIT are temporary differences between book and taxable income that were recorded when the federal statutory tax rate was higher than it is now or when those differences were expected to be resolved. The PLR addresses whether or not EDIT and ITC can be returned to customers, which without a PLR management believes would represent a violation of current tax law. The IRS declared a moratorium on issuing PLRs until final regulations on the return of EDIT and ITC to regulated customers are issued by the Treasury Department. Proposed regulations were issued in March 2003, and a hearing took place in June 2003. The proposed new regulations would allow the return of EDIT and ITC to regulated customers without violating the tax law. Also, under the proposed regulations, a company could elect to apply the regulation retroactively. The Treasury Department is currently deliberating the comments received at the hearing. If final regulations consistent with the proposed regulations are issued, then there could be an impact on NU's financial statements.
J. DEPRECIATION The provision for depreciation on utility assets is calculated using the straight-line method based on the estimated remaining useful lives of depreciable plant-in-service, which range primarily from 3 years to 75 years, adjusted for salvage value and removal costs, as approved by the appropriate regulatory agency where applicable. Depreciation rates are applied to plant- in-service from the time it is placed in service. When plant is retired from service, the original cost of the plant, including costs of removal less salvage, is charged to the accumulated provision for depreciation. Cost of removal is now classified as a regulatory liability. The depreciation rates for the several classes of electric utility plant-in-service are equivalent to a composite rate of 3.4 percent in 2003, 3.2 percent in 2002 and 3.1 percent in 2001.
NU also maintains other non-utility plant which is being depreciated using the straight-line method based on estimated remaining useful lives, which range primarily from 15 years to 120 years.
In 2002, NU Enterprises concluded a study of the depreciable lives of certain generation assets. The impact of this study was to lengthen the useful lives of those generation assets by 32 years to an average of 70 years. In addition, the useful lives of certain software was revised and shortened to reflect a remaining life of 1.5 years. As a result of these studies, NU Enterprises' operating expenses decreased by $8.6 million in 2003 and $5.1 million in 2002 as compared to 2001.
K. EQUITY INVESTMENTS AND JOINTLY OWNED ELECTRIC UTILITY PLANT Regional Nuclear Companies: At December 31, 2003, CL&P, PSNH and WMECO own common stock in three regional nuclear companies (Yankee Companies). NU's ownership interests in the Yankee Companies at December 31, 2003, which are accounted for on the equity method are 49 percent of the CYAPC, 38.5 percent of the Yankee Atomic Electric Company (YAEC) and 20 percent of the Maine Yankee Atomic Power Company (MYAPC). Effective November 7, 2003, CL&P, PSNH and WMECO sold their collective 17 percent ownership interest in Vermont Yankee Nuclear Power Corporation (VYNPC). NU's total equity investment in the Yankee Companies at December 31, 2003 and 2002, is $32.2 million and $48.9 million, respectively. Each of the remaining Yankee Companies owns a single nuclear generating plant which is being decommissioned.
Hydro-Quebec: NU has a 22.66 percent equity ownership interest in two companies that transmit electricity imported from the Hydro-Quebec system in Canada. NU's investment and exposure to loss is $10.1 million and $12 million at December 31, 2003 and 2002, respectively.
Other Investments: At December 31, 2003 and 2002, NU maintains certain cost method and other investments. The cost method investments are comprised of NEON Communications, Inc. (NEON), a provider of high-bandwidth fiber optic telecommunications services and Acumentrics Corporation (Acumentrics), a privately owned producer of advanced power generation and power protection technologies applicable to homes, telecommunications, commercial businesses, industrial facilities, and the automobile industry. These cost method investments have a combined total carrying value of $17.4 million and $12.5 million at December 31, 2003 and 2002, respectively.
Other investments also include a long-term note receivable from BMC Energy LLC, (BMC), an operator of renewable energy projects. NU's remaining note receivable from BMC totaled $4 million and $4.7 million at December 31, 2003 and 2002, respectively.
During 2002, after-tax impairment write-offs totaling $10.3 million were recorded to reduce the carrying values of NEON and Acumentrics to their net realizable values. Excluding BMC, these investments are VIEs under FIN 46 for which NU is not the primary beneficiary, and NU's exposure to loss as a result of these investments totaled $17.4 million and $12.5 million at December 31, 2003 and 2002, respectively.
L. ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION The allowance for funds used during construction (AFUDC) is a non-cash item that is included in the cost of Utility Group utility plant and represents the cost of borrowed and equity funds used to finance construction. The portion of AFUDC attributable to borrowed funds is recorded as a reduction of other interest expense, and the cost of equity funds is recorded as other income on the consolidated statements of income:
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For the Years Ended December 31,
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(Millions of Dollars,
except percentages) 2003 2002 2001
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Borrowed funds $ 5.0 $ 7.5 $ 6.6
Equity funds 6.5 5.8 3.8
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Totals $11.5 $13.3 $10.4
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Average AFUDC rates 4.0% 4.9% 7.2%
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M. EQUITY-BASED COMPENSATION In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based Compensation - Transition and Disclosure." This statement amended SFAS No. 123, "Accounting for Stock-Based Compensation," to provide alternative methods of transition for a voluntary change to the fair value-based method of accounting for equity-based employee compensation. This statement also requires prominent disclosures in both annual and interim financial statements about the method of accounting for equity-based employee compensation and the effect of the method used on reported results. At this time, NU has not elected to transition to the fair value-based method of accounting for equity-based employee compensation. At December 31, 2003, NU maintains an Employee Share Purchase Plan (ESPP) and other long-term incentive plans, which are described in Note 4D, "Employee Benefits - Equity-Based Compensation," to the consolidated financial statements. NU accounts for these plans under the recognition and measurement principles of Accounting Principles Board Opinion (APB) No. 25, "Accounting for Stock Issued to Employees," and related interpretations. No equity-based employee compensation cost for stock options is reflected in net income, as all options granted under those plans had an exercise price equal to the market value of the underlying common stock on the date of grant. No stock options were granted during 2003. The following table illustrates the effect on net income and earnings per share (EPS) if NU had applied the fair value recognition provisions of SFAS No. 123 to equity-based employee compensation.
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For the Years Ended December 31,
--------------------------------------------------------------------------
(Millions of Dollars, except per
share amounts) 2003 2002 2001
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Net income as reported $116.4 $152.1 $243.5
Total equity-based employee
compensation expense
determined under the
fair value-based method for
all awards, net of related tax
effects (1.9) (3.2) (2.6)
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Pro forma net income $114.5 $148.9 $240.9
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EPS:
Basic - as reported $0.91 $1.18 $1.80
Basic - pro forma $0.90 $1.15 $1.78
Diluted - as reported $0.91 $1.18 $1.79
Diluted - pro forma $0.90 $1.15 $1.77
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Net income as reported includes $2 million, $1 million and $1.2 million expensed for restricted stock in 2003, 2002 and 2001, respectively. NU accounts for restricted stock in accordance with APB No. 25 and amortizes the intrinsic value of the award over the service period.
NU assumes an income tax rate of 40 percent to estimate the tax effect on total equity-based employee compensation expense determined under the fair value-based method for all awards.
N. ASSET RETIREMENT OBLIGATIONS In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." This statement requires that legal obligations associated with the retirement of property, plant and equipment be recognized as a liability at fair value when incurred and when a reasonable estimate of the fair value of the liability can be made. SFAS No. 143 was effective on January 1, 2003 for NU. Management completed its review process for potential asset retirement obligations (ARO) and has not identified any material AROs that have been incurred. However, management has identified certain removal obligations that arise in the ordinary course of business or have a low probability of occurring. These types of obligations primarily relate to transmission and distribution lines and poles, telecommunication towers, transmission cables, and certain FERC or state regulatory agency re-licensing issues. These obligations are AROs that have not been incurred or are not material in nature.
A portion of NU's regulated utilities' rates is intended to recover the cost of removal of certain utility assets. The amounts recovered do not represent AROs. At December 31, 2003 and 2002, cost of removal was approximately $334 million and $321 million, respectively.
O. MATERIALS AND SUPPLIES Materials and supplies include materials purchased primarily for construction, operation and maintenance (O&M) purposes. Materials and supplies are valued at the lower of average cost or market.
P. SALE OF CUSTOMER RECEIVABLES CL&P has an arrangement with a financial institution under which CL&P can sell up to $100 million of accounts receivable and unbilled revenues. At December 31, 2003 and 2002, CL&P had sold accounts receivable of $80 million and $40 million, respectively, to the financial institution with limited recourse through CL&P Receivables Corporation (CRC), a wholly owned subsidiary of CL&P. At December 31, 2003 and 2002, the reserve requirements calculated in accordance with the Receivables Purchase and Sale Agreement were $29.3 million and $3.8 million, respectively. These reserve amounts are deducted from the amount of receivables eligible for sale at the time. Concentrations of credit risk to the purchaser under this agreement with respect to the receivables are limited due to CL&P's diverse customer base within its service territory. At December 31, 2003 and 2002, amounts sold to CRC by CL&P but not sold to the financial institution totaling $166.5 million and $178.9 million, respectively, are included in investments in securitizable assets on the accompanying consolidated balance sheets. These amounts would be excluded from CL&P's assets in the event of CL&P's bankruptcy. On July 9, 2003, CL&P renewed this arrangement.
The transfer of receivables to the financial institution under this arrangement qualifies for sale treatment under SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities - A Replacement of SFAS No. 125." This agreement expires on July 7, 2004. Management plans to renew this agreement prior to its expiration.
Q. CASH AND CASH EQUIVALENTS Cash and cash equivalents includes cash on hand and short-term cash investments that are highly liquid in nature and have original maturities of three months or less.
R. RESTRICTED CASH - LMP COSTS AND UNRESTRICTED CASH FROM COUNTERPARTIES Restricted cash - LMP costs represents incremental LMP cost amounts that have been collected by CL&P and deposited into an escrow account.
Unrestricted cash on deposit from counterparties represents balances collected from counterparties resulting from Select Energy's credit management activities. An offsetting liability has been recorded in other current liabilities for the amounts collected.
S. SPECIAL DEPOSITS Special deposits represents amounts Select Energy has on deposit with brokerage firms in the amount of $17 million, amounts included in escrow for SESI which have not been spent on its construction projects of $32 million, and $30.1 million in escrow that PSNH funded to acquire CVEC on January 1, 2004.
T. EXCISE TAXES Certain excise taxes levied by state or local governments are collected by NU from its customers. These excise taxes are accounted for on a gross basis with collections in revenues and payments in expenses. For the years ended December 31, 2003, 2002 and 2001, gross receipts taxes, franchise taxes and other excise taxes of $94.5 million, $86.7 million and $90.5 million, respectively, are included in operating revenues and taxes other than income taxes on the accompanying consolidated statements of income.
U. SUPPLEMENTAL CASH FLOW INFORMATION
---------------------------------------------------------------------
For the Years Ended December 31,
---------------------------------------------------------------------
(Millions of Dollars) 2003 2002 2001
---------------------------------------------------------------------
Cash paid during the
year for:
Interest, net of
amounts capitalized $241.3 $259.9 $275.3
Income taxes $248.3 $114.4 $321.0
---------------------------------------------------------------------
|
V. OTHER INCOME/(LOSS) The pre-tax components of NU's other income/(loss) items are as follows:
---------------------------------------------------------------------
For the Years Ended December 31,
---------------------------------------------------------------------
(Millions of Dollars) 2003 2002 2001
---------------------------------------------------------------------
Seabrook-related gains $ - $ 38.7 $ -
Investment write-downs (1.4) (18.4) -
Gain related to Millstone sale - - 201.9
Loss on share
repurchase contracts - - (35.4)
Investment income 17.1 25.4 19.3
Charitable donations (8.4) (3.7) (5.8)
Other (7.7) 1.8 7.6
---------------------------------------------------------------------
Totals $(0.4) $ 43.8 $187.6
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|
Limits: The amount of short-term borrowings that may be incurred by NU and its operating companies is subject to periodic approval by either the SEC under the 1935 Act or by the respective state regulators. On June 30, 2003, the SEC granted authorization allowing NU, CL&P, PSNH, WMECO, and Yankee Gas to incur total short-term borrowings up to a maximum of $400 million, $375 million, $100 million, $200 million, and $100 million, respectively, through June 30, 2006, with authorization for borrowings from the NU Money Pool (Pool) granted through June 30, 2004.
The charter of CL&P contains preferred stock provisions restricting the amount of unsecured debt that CL&P may incur. At meetings in November 2003, CL&P obtained authorization from its stockholders to issue unsecured indebtedness with a maturity of less than 10 years in excess of the 10 percent of total capitalization limitation in CL&P's charter, provided that all unsecured indebtedness would not exceed 20 percent of total capitalization for a ten-year period expiring March 2014. As of December 31, 2003, CL&P is permitted to incur $366 million of additional unsecured debt.
PSNH is authorized by the NHPUC to incur short-term borrowings up to a maximum of $100 million.
SEC authorization was also given on June 30, 2003, permitting NAEC to incur short-term borrowings from the Pool up to a maximum of $10 million through June 30, 2004. NAEC currently has a short-term debt limit set by the NHPUC equal to 10 percent of net fixed plant and has no plans at this time to incur any future short-term borrowings.
Utility Group Credit Agreement: On November 10, 2003, CL&P, PSNH, WMECO, and Yankee Gas entered into a 364-day unsecured revolving credit facility for $300 million. This facility replaces a similar credit facility that expired on November 11, 2003. CL&P may draw up to $150 million with PSNH, WMECO and Yankee Gas able to draw up to $100 million, subject to the $300 million maximum borrowing limit. Unless extended, the credit facility will expire on November 8, 2004. At December 31, 2003 and 2002, there were $40 million and $7 million, respectively, in borrowings under these credit facilities.
NU Parent Credit Agreement: On November 10, 2003, NU entered into a 364-day unsecured revolving credit and letter of credit (LOC) facility for $350 million. This facility replaces a similar facility that expired on November 11, 2003. This facility provides a total commitment of $350 million, subject to two overlapping sub-limits. First, subject to the notional amount of any outstanding LOCs, amounts up to $350 million are available for advances. Second, subject to the advances outstanding, LOCs may be issued in notional amounts up to $250 million for periods up to 364 days. The agreement provides for LOCs to be issued in the name of NU or any of its subsidiaries. Unless extended, the credit facility will expire on November 8, 2004. At December 31, 2003 and 2002, there were $65 million and $49 million, respectively, in borrowings under these credit facilities. In addition, there were $106.9 million and $6.7 million in LOCs outstanding at December 31, 2003 and 2002, respectively.
Under the Utility Group and NU parent credit agreements, NU and its subsidiaries may borrow at fixed or variable rates plus an applicable margin based upon certain debt ratings, as rated by the lower of Standard and Poor's or Moody's Investors Service. The weighted average interest rates on NU's notes payable to banks outstanding on December 31, 2003 and 2002 were 2.07 percent and 4.25 percent, respectively.
Under the Utility Group and NU parent credit agreements, NU and its subsidiaries must comply with certain financial and non-financial covenants as are customarily included in such agreements, including but not limited to, consolidated debt ratios and interest coverage ratios. The most restrictive financial covenant is the interest coverage ratio. The parties to the credit agreements currently are and expect to remain in compliance with these covenants.
Other Credit Facility: On December 29, 2003, E.S. Boulos Company (Boulos), a subsidiary of NGS, entered into a line of credit for $6 million. This facility replaces a similar credit facility that expired on December 31, 2003, and unless extended, this credit facility will expire on June 30, 2004. This credit facility limits Boulos' ability to pay dividends if borrowings are outstanding and limits access to the Pool for additional borrowings. At December 31, 2003 and 2002, there were no borrowings under this credit facility.
A. DERIVATIVE INSTRUMENTS Effective January 1, 2001, NU adopted SFAS No. 133, as amended. Derivatives that are utilized for trading purposes are recorded at fair value with changes in fair value included in earnings. Other contracts that are derivatives but do not meet the definition of a cash flow hedge and cannot be designated as being used for normal purchases or normal sales are also recorded at fair value with changes in fair value included in earnings. For those contracts that meet the definition of a derivative and meet the cash flow hedge requirements, the changes in the fair value of the effective portion of those contracts are generally recognized in accumulated other comprehensive income until the underlying transactions occur. For contracts that meet the definition of a derivative but do not meet the hedging requirements, and for the ineffective portion of contracts that meet the cash flow hedge requirements, the changes in fair value of those contracts are recognized currently in earnings. Derivative contracts designated as fair value hedges and the item they are hedging are both recorded at fair value on the consolidated balance sheets. Derivative contracts that are entered into as a normal purchase or sale and will result in physical delivery, and are documented as such, are recorded under accrual accounting. For information regarding accounting changes related to derivative instruments, see Note 1C, "Summary of Significant Accounting Policies - New Accounting Standards," to the consolidated financial statements.
During 2003, a negative $5.3 million, net of tax, was reclassified from other comprehensive income in connection with the consummation of the underlying hedged transactions and recognized in earnings. An additional $0.3 million, net of tax, was recognized in earnings for those derivatives that were determined to be ineffective and for the ineffective portion of cash flow hedges. Also during 2003, new cash flow hedge transactions were entered into that hedge cash flows through 2006. As a result of these new transactions and market value changes since January 1, 2003, accumulated other comprehensive income increased by $9.3 million, net of tax. Accumulated other comprehensive income at December 31, 2003 was a positive $24.8 million, net of tax (increase to equity), relating to hedged transactions, and it is estimated that $27.3 million of this net of tax balance will be reclassified as an increase to earnings within the next twelve months. Cash flows from hedge contracts are reported in the same category as cash flows from the underlying hedged transaction.
During 2002, a positive $17 million, net of tax, was reclassified from other comprehensive income in connection with the consummation of the underlying hedged transactions and recognized in earnings. An additional $0.9 million, net of tax, was recognized in earnings for those derivatives that were determined to be ineffective and for the ineffective portion of cash flow hedges. During 2002, new cash flow hedge transactions were entered into that hedge cash flows through 2005. As a result of these new transactions and market value changes during 2002, accumulated other comprehensive income increased by $52.4 million, net of tax. Accumulated other comprehensive income at December 31, 2002 was a positive $15.5 million, net of tax (increase to equity), relating to hedged transactions.
In 2003, there were changes to interpretations of as well as an amendment to SFAS No. 133, and the FASB continues to consider changes that could affect the way NU records and discloses derivative and hedging activities.
The tables below summarize the derivative assets and liabilities at December 31, 2003 and 2002. These amounts do not include option premiums paid, which are recorded as prepayments and amounted to $16.7 million and $26.6 million at December 31, 2003 and 2002, respectively. These amounts also do not include option premiums received, which are recorded as other current liabilities and amounted to $12.2 million and $33.9 million at December 31, 2003 and 2002, respectively. The premium amounts relate primarily to energy trading activities.
---------------------------------------------------------------------
At December 31, 2003
---------------------------------------------------------------------
(Millions of Dollars) Assets Liabilities Total
---------------------------------------------------------------------
NU Enterprises:
Trading $123.9 $ (91.4) $ 32.5
Non-trading 1.6 (0.8) 0.8
Hedging 55.8 (12.7) 43.1
Utility Group - Gas:
Non-trading 0.2 (0.2) -
Hedging 2.8 - 2.8
Utility Group - Electric:
Non-trading 116.9 (56.0) 60.9
NU Parent:
Hedging - (3.6) (3.6)
---------------------------------------------------------------------
Total $301.2 $(164.7) $136.5
---------------------------------------------------------------------
---------------------------------------------------------------------
At December 31, 2002
---------------------------------------------------------------------
(Millions of Dollars) Assets Liabilities Total
---------------------------------------------------------------------
NU Enterprises:
Trading $102.9 $(61.9) $41.0
Non-trading 2.9 - 2.9
Hedging 22.8 (2.0) 20.8
Utility Group - Gas:
Hedging 2.3 - 2.3
---------------------------------------------------------------------
Total $130.9 $(63.9) $67.0
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|
NU Enterprises - Trading: To gather market intelligence and utilize this information in risk management activities for the wholesale marketing activities, Select Energy conducts limited energy trading activities in electricity, natural gas and oil, and therefore experiences net open positions. Select Energy manages these open positions with strict policies that limit its exposure to market risk and require daily reporting to management of potential financial exposures. Derivatives used in trading activities are recorded at fair value and included in the consolidated balance sheets as derivative assets or liabilities. Changes in fair value are recognized in operating revenues in the consolidated statements of income in the period of change. The net fair value positions of the trading portfolio at December 31, 2003 and 2002 were assets of $32.5 million and $41 million, respectively.
Select Energy's trading portfolio includes New York Mercantile Exchange (NYMEX) futures and options, the fair value of which is based on closing exchange prices; over-the-counter forwards and options, the fair value of which is based on the mid-point of bid and ask market prices; and bilateral contracts for the purchase or sale of electricity or natural gas, the fair value of which is determined using available information from external sources. Select Energy's trading portfolio also includes transmission congestion contracts (TCC). The fair value of certain TCCs is based on published market data.
NU Enterprises - Non-trading: Non-trading derivative contracts are used for delivery of energy related to Select Energy's wholesale and retail marketing activities. These contracts are subject to fair value accounting because these contracts are derivatives that cannot be designated as normal purchases or sales, as defined. These contracts cannot be designated as normal purchases or sales either because they are included in the New York energy market that settles financially or because management did not elect the normal purchase and sale designation. Changes in fair value of a negative $2.1 million of non-trading derivative contracts were recorded in revenues in 2003. Market information for certain TCCs is not available, and those contracts cannot be reliably valued. Management believes the amounts paid for these contracts, which total $4.3 million and are included in premiums paid, are equal to their fair value.
NU Enterprises - Hedging: Select Energy utilizes derivative financial and commodity instruments, including futures and forward contracts, to reduce market risk associated with fluctuations in the price of electricity and natural gas purchased to meet firm sales commitments to certain customers. Select Energy also utilizes derivatives, including price swap agreements, call and put option contracts, and futures and forward contracts to manage the market risk associated with a portion of its anticipated supply and delivery requirements. These derivatives have been designated as cash flow hedging instruments and are used to reduce the market risk associated with fluctuations in the price of electricity, natural gas, or oil. A derivative that hedges exposure to the variable cash flows of a forecasted transaction (a cash flow hedge) is initially recorded at fair value with changes in fair value recorded in accumulated other comprehensive income. Hedges impact net income when the forecasted transaction being hedged occurs, when hedge ineffectiveness is measured and recorded, when the forecasted transaction being hedged is no longer probable of occurring, or when there is accumulated other comprehensive loss and the hedge and the forecasted transaction being hedged are in a loss position on a combined basis.
Select Energy maintains natural gas service agreements with certain customers to supply gas at fixed prices for terms extending through 2006. Select Energy has hedged its gas supply risk under these agreements through NYMEX futures contracts. Under these contracts, which also extend through 2006, the purchase price of a specified quantity of gas is effectively fixed over the term of the gas service agreements. At December 31, 2003 and 2002, the NYMEX futures contracts had notional values of $104.5 million and $30.9 million, respectively, and were recorded at fair value as derivative assets of $11.6 million and $12.2 million at December 31, 2003 and 2002, respectively.
Select Energy maintains power swaps to hedge purchases in New England as well as financial gas contracts and gas futures to hedge electricity purchase contracts that are indexed to gas prices. These hedging contracts, which are valued at the mid-point of bid and ask market prices, were recorded as derivative assets of $27.3 million and derivative liabilities of $5.1 million at December 31, 2003. To hedge the congestion price differences associated with LMP in the New England and the Pennsylvania, New Jersey, Maryland and Delaware (PJM) regions, Select Energy holds FTR contracts recorded as a derivative asset at a fair value of $3.8 million at December 31, 2003.
Other hedging derivative liabilities, which are valued at the mid-point of bid and ask market prices, include forwards, options and swaps to hedge Select Energy's basic generation service contracts in the PJM region and were recorded at fair value as derivative liabilities of $5.8 million at December 31, 2003 and derivative assets of $1.1 million at December 31, 2002.
Select Energy New York, Inc. maintains financial power swaps to hedge its retail sales portfolio through 2004, which were also valued at the mid-point of bid and ask market prices. These contracts were recorded at fair value as derivative assets of $6.9 million and $5.6 million at December 31, 2003 and 2002, respectively.
Utility Group - Gas - Non-trading: Yankee Gas' non-trading derivatives consist of peaking supply arrangements to serve winter load obligations and firm sales contracts with options to curtail delivery. These contracts are subject to fair value accounting because these contracts are derivatives that cannot be designated as normal purchases or sales, as defined, because of the optionality in their contract terms. The net fair values of non-trading derivatives at December 31, 2003 were liabilities of $24 thousand. Yankee Gas held no contracts accounted for as non-trading derivatives at December 31, 2002.
Utility Group - Gas - Hedging: Yankee Gas maintains a master swap agreement with a financial counterparty to purchase gas at fixed prices. Under this master swap agreement, the purchase price of a specified quantity of gas for an unaffiliated customer is effectively fixed over the term of the gas service agreements with those customers for a period not extending beyond 2005. At December 31, 2003 and 2002, the commodity swap agreement had notional values of $6.3 million and $10.7 million, respectively, and was recorded at fair value as derivative assets at December 31, 2003 and 2002 of $2.8 million and $2.3 million, respectively.
Utility Group - Electric - Non-trading: CL&P has two IPP contracts to purchase power that contain pricing provisions that are not clearly and closely related to the price of power. Because of a clarification in the definition of "clearly and closely related" in Issue No. C-20, these contracts no longer qualify for the normal purchases and sales exception to SFAS No. 133, as amended. The fair values of these IPP non-trading derivatives at December 31, 2003 include a derivative asset with a fair value of $112.4 million and a derivative liability with a fair value of $54.6 million. To mitigate the risk associated with certain supply contracts, CL&P purchased FTRs. FTRs are derivatives that cannot qualify for the normal purchases and sales exception. The fair value of these FTR non-trading derivatives at December 31, 2003 was an asset of $3 million. CL&P had no non- trading derivatives at December 31, 2002 that were required to be recorded at fair value.
NU Parent - Hedging: In March of 2003, NU parent entered into a fixed to floating interest rate swap on its $263 million, 7.25 percent fixed-rate note that matures on April 1, 2012. As a matched-terms fair value hedge, the changes in fair value of the swap and the hedged debt instrument are recorded on the consolidated balance sheets but are equal and offsetting in the consolidated statements of income. The cumulative change in the fair value of the hedged debt of $3.6 million is included as long-term debt on the consolidated balance sheets. The resulting changes in interest payments made are recorded as adjustments to interest expense.
B. MARKET RISK INFORMATION Select Energy utilizes the sensitivity analysis methodology to disclose quantitative information for its commodity price risks. Sensitivity analysis provides a presentation of the potential loss of future earnings, fair values or cash flows from market risk-sensitive instruments over a selected time period due to one or more hypothetical changes in commodity prices, or other similar price changes. Under sensitivity analysis, the fair value of the portfolio is a function of the underlying commodity, contract prices and market prices represented by each derivative commodity contract. For swaps, forward contracts and options, fair value reflects management's best estimates considering over-the-counter quotations, time value and volatility factors of the underlying commitments. Exchange-traded futures and options are recorded at fair value based on closing exchange prices.
NU Enterprises - Wholesale and Retail Marketing Portfolio: When conducting sensitivity analyses of the change in the fair value of Select Energy's electricity, natural gas and oil on the wholesale and retail marketing portfolio, which would result from a hypothetical change in the future market price of electricity, natural gas and oil, the fair values of the contracts are determined from models that take into consideration estimated future market prices of electricity, natural gas and oil, the volatility of the market prices in each period, as well as the time value factors of the underlying commitments. In most instances, market prices and volatility are determined from quoted prices on the futures exchange.
Select Energy has determined a hypothetical change in the fair value for its wholesale and retail marketing portfolio, which includes cash flow hedges and electricity, natural gas and oil contracts, assuming a 10 percent change in forward market prices. At December 31, 2003, a 10 percent change in market price would have resulted in an increase or decrease in fair value of $3.7 million.
The impact of a change in electricity, natural gas and oil prices on Select Energy's wholesale and retail marketing portfolio at December 31, 2003, is not necessarily representative of the results that will be realized when these contracts are physically delivered.
NU Enterprises - Trading Contracts: At December 31, 2003, Select Energy has calculated the market price resulting from a 10 percent change in forward market prices. That 10 percent change would result in a $0.4 million increase or decrease in the fair value of the Select Energy trading portfolio. In the normal course of business, Select Energy also faces risks that are either non-financial or non-quantifiable. These risks principally include credit risk, which is not reflected in this sensitivity analysis.
C. OTHER RISK MANAGEMENT ACTIVITIES Interest Rate Risk Management: NU manages its interest rate risk exposure in accordance with written policies and procedures by maintaining a mix of fixed and variable rate debt. At December 31, 2003, approximately 82 percent (72 percent including the debt subject to the fixed-to-floating interest rate swap in variable rate debt) of NU's long-term debt, including fees and interest due for spent nuclear fuel disposal costs, is at a fixed interest rate. The remaining long-term debt is variable-rate and is subject to interest rate risk that could result in earnings volatility. Assuming a one percentage point increase in NU's variable interest rates, including the rate on debt subject to the fixed-to-floating interest rate swap, annual interest expense would have increased by $4.3 million. At December 31, 2003, NU parent maintained a fixed to floating interest rate swap to manage the interest rate risk associated with its $263 million of fixed-rate debt.
Credit Risk Management: Credit risk relates to the risk of loss that NU would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. NU serves a wide variety of customers and suppliers that include IPPs, industrial companies, gas and electric utilities, oil and gas producers, financial institutions, and other energy marketers. Margin accounts exist within this diverse group, and NU realizes interest receipts and payments related to balances outstanding in these margin accounts. This wide customer and supplier mix generates a need for a variety of contractual structures, products and terms which, in turn, requires NU to manage the portfolio of market risk inherent in those transactions in a manner consistent with the parameters established by NU's risk management process.
The Utility Group has a lower level of credit risk related to providing electric and gas distribution service than NU Enterprises. However, Utility Group companies are subject to credit risk from certain long-term or high- volume supply contracts with energy marketing companies.
Credit risks and market risks at NU Enterprises are monitored regularly by a Risk Oversight Council operating outside of the business lines that create or actively manage these risk exposures to ensure compliance with NU's stated risk management policies.
NU tracks and re-balances the risk in its portfolio in accordance with fair value and other risk management methodologies that utilize forward price curves in the energy markets to estimate the size and probability of future potential exposure.
NYMEX traded futures and option contracts are guaranteed by the NYMEX and have a lower credit risk. Select Energy has established written credit policies with regard to its counterparties to minimize overall credit risk on all types of transactions. These policies require an evaluation of potential counterparties' financial condition (including credit ratings), collateral requirements under certain circumstances (including cash in advance, letters of credit, and parent guarantees), and the use of standardized agreements, which allow for the netting of positive and negative exposures associated with a single counterparty. This evaluation results in establishing credit limits prior to Select Energy entering into energy contracts. The appropriateness of these limits is subject to continuing review. Concentrations among these counterparties may impact Select Energy's overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes to economic, regulatory or other conditions.
At December 31, 2003 and 2002, Select Energy maintained collateral balances from counterparties of $46.5 million and $16.9 million, respectively. These amounts are included in both unrestricted cash from counterparties and other current liabilities on the accompanying consolidated balance sheets.
A. PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS Pension Benefits: NU's subsidiaries participate in a uniform noncontributory defined benefit retirement plan (Pension Plan) covering substantially all regular NU employees. Benefits are based on years of service and the employees' highest eligible compensation during 60 consecutive months of employment. Pre-tax pension income was $31.8 million in 2003, $73.4 million in 2002, and $101 million in 2001. These amounts exclude pension settlements, curtailments and net special termination income of $22.2 million in 2002 and expense of $2.6 million in 2001. NU uses a December 31 measurement date for the Pension Plan. Pension income attributable to earnings is as follows:
------------------------------------------------------------------------
For the Years Ended December 31,
------------------------------------------------------------------------
(Millions of Dollars) 2003 2002 2001
------------------------------------------------------------------------
Pension income before
settlements, curtailments
and special termination benefits $(31.8) $(73.4) $(101.0)
Net pension income
capitalized as utility plant 15.4 26.2 36.8
------------------------------------------------------------------------
Net pension income before
settlements, curtailments
and special termination
benefits (16.4) (47.2) (64.2)
Settlements, curtailments and
special termination benefits
reflected in earnings - - 7.5
------------------------------------------------------------------------
Total pension income
included in earnings $(16.4) $(47.2) $ (56.7)
------------------------------------------------------------------------
|
Pension Settlements, Curtailments and Special Termination Benefits: There were no settlements, curtailments or special termination benefits in 2003.
On November 1, 2002, CL&P, NAEC and certain other joint owners consummated the sale of their ownership interests in Seabrook to a subsidiary of FPL Group, Inc. (FPL), and North Atlantic Energy Service Corporation (NAESCO), a wholly owned subsidiary of NU, ceased having operational responsibility for Seabrook at that time. NAESCO employees were transferred to FPL, which significantly reduced the expected service lives of NAESCO employees who participated in the Pension Plan. As a result, NAESCO recorded pension curtailment income of $29.1 million in 2002. As the curtailment related to the operation of Seabrook, NAESCO credited the joint owners of Seabrook with this amount. CL&P recorded its $1.2 million share of this income as a reduction to stranded costs, and as such, there was no impact on 2002 CL&P earnings. PSNH was credited with its $10.5 million share of this income through the Seabrook Power Contracts with NAEC. PSNH also credited this income as a reduction to stranded costs, and as such, there was no impact on 2002 PSNH earnings.
Additionally, in conjunction with the divestiture of its generation assets, NU recorded $1.2 million in curtailment income in 2002, all of which was recorded as a regulatory liability and did not impact earnings.
Effective February 1, 2002, certain CL&P and Utility Group employees who were displaced were eligible for a Voluntary Retirement Program (VRP). The VRP supplements the Pension Plan and provides special provisions. Eligible employees include non-bargaining unit employees or employees belonging to a collective bargaining unit that agreed to accept the VRP who were active participants in the Pension Plan at January 1, 2002, and that were displaced as part of the reorganization between January 22, 2002 and March 2003. Eligible employees received a special retirement benefit under the VRP whose value was roughly equivalent to a multiple of base pay based on years of credited service. During 2002, NU recorded an expense of $8.1 million associated with special pension termination benefits related to the VRP. The cost of the VRP was recovered through regulated utility rates, and the $8.1 million was recorded as a regulatory asset with no impact on 2002 earnings.
In conjunction with the Voluntary Separation Program (VSP) that was announced in December 2000, NU recorded $26 million in settlement income and $64.7 million in curtailment income in 2001. The VSP was intended to reduce the generation-related support staff between March 1, 2001 and February 28, 2002, and was available to non-bargaining unit employees who, by February 1, 2002, were at least age 50, with a minimum of five years of credited service, and at December 15, 2000, were assigned to certain groups and in eligible job classifications.
One component of the VSP included special pension termination benefits equal to the greater of 5 years added to both age and credited service of eligible participants or two weeks of pay for each year of service subject to a minimum level of 12 weeks and a maximum of 52 weeks for eligible participants. The special pension termination benefits expense associated with the VSP totaled $93.3 million in 2001. The net total of the settlement and curtailment income and the special termination benefits expense was $2.6 million, of which $7.5 million of costs were included in operating expenses, $5.1 million was deferred as a regulatory liability and is expected to be returned to customers and $0.2 million was billed to the joint owners of Millstone and Seabrook.
Postretirement Benefits Other Than Pensions (PBOP): NU's subsidiaries also provide certain health care benefits, primarily medical and dental, and life insurance benefits through a benefit plan to retired employees (PBOP Plan). These benefits are available for employees retiring from NU who have met specified service requirements. For current employees and certain retirees, the total benefit is limited to two times the 1993 per retiree health care cost. These costs are charged to expense over the estimated work life of the employee. NU uses a December 31 measurement date for the PBOP Plan. NU annually funds postretirement costs through external trusts with amounts that have been rate-recovered and which also are tax deductible.
In 2002, the PBOP Plan was amended to change the claims experience basis, to increase minimum retiree contributions and to reduce the cap on the company's subsidy to the dental plan. These amendments resulted in a $34.2 million decrease in NU's benefit obligation under the PBOP Plan at December 31, 2002.
Impact of New Medicare Changes on PBOP: On December 8, 2003, the President signed into law a bill that expands Medicare, primarily by adding a prescription drug benefit starting in 2006 for Medicare-eligible retirees as well as a federal subsidy to plan sponsors of retiree health care benefit plans who provide a prescription drug benefit at least actuarially equivalent to the new Medicare benefit.
Based on the current PBOP Plan provisions, NU's actuaries believe that NU will qualify for this federal subsidy because the actuarial value of NU's PBOP Plan is estimated to be 60 percent greater than that of the standard Medicare benefit. NU will directly benefit from the federal subsidy for retirees of PSNH and NAESCO who retired before 1993, and other NU-company retirees who retired before 1991. For other retirees, management does not believe that NU will benefit from the subsidy because NU's cost support for these retirees is capped at a fixed dollar commitment.
The aggregate effect of recognizing the Medicare change is a decrease to the PBOP benefit obligation of $19.5 million. This amount includes the present value of the future government subsidy, which was estimated by discounting the expected payments using the actuarial assumptions used to determine the PBOP liability at December 31, 2003. Also included in the $19.5 million estimate is a decrease in the assumed participation in NU's retiree health plan from 95 percent to 85 percent for future retirees, which reflects the expectation that the Medicare prescription benefit will produce insurer- sponsored health plans that are more financially attractive to future retirees. The per capita claims cost estimate was not changed. Management reduced the PBOP benefit obligation as of December 31, 2003 by $19.5 million and recorded this amount as an actuarial gain within unrecognized net loss/(gain) in the tables that follow. The $19.5 million actuarial gain will be amortized beginning in 2004 as a reduction to PBOP expense over the future working lifetime of employees covered under the plan (approximately 13 years). PBOP expense in 2004 will also reflect a lower interest cost due to the reduction in the December 31, 2003 benefit obligation.
Specific authoritative guidance on accounting for the effect of the Medicare federal subsidy on PBOP plans and amounts is pending from the FASB. When issued, that guidance could require NU to change the accounting described above and change the information reported herein.
PBOP Settlements, Curtailments and Special Termination Benefits: There were no settlements, curtailments or special termination benefits in 2003. In 2002, NU recorded PBOP special termination benefits income of $1.2 million related to the sale of Seabrook. CL&P and PSNH recorded their shares of this curtailment as reductions to stranded costs. In 2001, NU recorded PBOP curtailment expense totaling $3.3 million and special termination benefits expense totaling $8.6 million in connection with the VSP. This amount was recorded as a regulatory asset and collected through regulated utility rates in 2002.
The following table represents information on the plans' benefit obligation, fair value of plan assets, and the respective plans' funded status:
----------------------------------------------------------------------------------------------------------
At December 31,
----------------------------------------------------------------------------------------------------------
Pension Benefits Postretirement Benefits
----------------------------------------------------------------------------------------------------------
(Millions of Dollars) 2003 2002 2003 2002
----------------------------------------------------------------------------------------------------------
Change in benefit obligation
Benefit obligation at beginning of year $(1,789.8) $(1,687.6) $(397.8) $(400.0)
Service cost (35.1) (37.2) (5.3) (6.2)
Interest cost (117.0) (119.8) (26.8) (29.2)
Medicare impact - - 19.5 -
Plan amendment - (11.4) - 34.2
Actuarial loss (102.9) (117.7) (34.8) (44.0)
Benefits paid - excluding lump sum payments 99.6 97.3 40.2 44.0
Benefits paid - lump sum payments 3.9 50.2 - -
Curtailments and settlements - 44.5 - 3.4
Special termination benefits - (8.1) - -
----------------------------------------------------------------------------------------------------------
Benefit obligation at end of year $(1,941.3) $(1,789.8) $(405.0) $(397.8)
----------------------------------------------------------------------------------------------------------
Change in plan assets
Fair value of plan assets at beginning of year $ 1,632.3 $ 1,990.4 $ 147.7 $ 171.0
Actual return on plan assets 416.3 (213.1) 35.4 (14.4)
Employer contribution - - 35.1 35.1
Plan asset transfer in - 2.5 - -
Benefits paid - excluding lump sum payments (99.6) (97.3) (40.2) (44.0)
Benefits paid - lump sum payments (3.9) (50.2) - -
----------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of year $ 1,945.1 $ 1,632.3 $ 178.0 $ 147.7
----------------------------------------------------------------------------------------------------------
Funded status at December 31 $ 3.8 $ (157.5) $(227.0) $(250.1)
Unrecognized transition (asset)/obligation (1.1) (2.6) 106.6 118.5
Unrecognized prior service cost 63.5 70.1 (5.5) (5.9)
Unrecognized net loss/(gain) 294.5 418.9 113.6 124.8
----------------------------------------------------------------------------------------------------------
Prepaid/(accrued) benefit cost $ 360.7 $ 328.9 $ (12.3) $ (12.7)
----------------------------------------------------------------------------------------------------------
|
The accumulated benefit obligation for the Plan was $1.7 billion and $1.6 billion at December 31, 2003 and 2002, respectively.
The following actuarial assumptions were used in calculating the plans' year end funded status:
-------------------------------------------------------------------------------
At December 31,
-------------------------------------------------------------------------------
Balance Sheets Pension Benefits Postretirement Benefits
-------------------------------------------------------------------------------
2003 2002 2003 2002
-------------------------------------------------------------------------------
Discount rate 6.25% 6.75% 6.25% 6.75%
Compensation/progression rate 3.75% 4.00% N/A N/A
Health care cost trend rate N/A N/A 9.00% 10.00%
-------------------------------------------------------------------------------
|
The components of net periodic (income)/expense are as follows:
----------------------------------------------------------------------------------------------------------
For the Years Ended December 31,
----------------------------------------------------------------------------------------------------------
Pension Benefits Postretirement Benefits
----------------------------------------------------------------------------------------------------------
(Millions of Dollars) 2003 2002 2001 2003 2002 2001
Service cost $ 35.1 $ 37.2 $ 35.7 $ 5.3 $ 6.2 $ 6.2
Interest cost 117.0 119.8 119.7 26.8 29.2 27.2
Expected return on plan assets (182.5) (204.9) (214.1) (14.9) (16.6) (17.0)
Amortization of unrecognized net
transition (asset)/obligation (1.5) (1.4) (1.5) 11.9 13.6 14.5
Amortization of prior service cost 7.2 7.7 6.9 (0.4) (0.1) -
Amortization of actuarial gain (7.1) (31.8) (47.7) - - -
Other amortization, net - - - 6.4 2.2 (2.6)
----------------------------------------------------------------------------------------------------------
Net periodic (income)/expense - before
settlements, curtailments and special
termination benefits (31.8) (73.4) (101.0) 35.1 34.5 28.3
----------------------------------------------------------------------------------------------------------
Settlement income - - (26.0) - - -
Curtailment (income)/expense - (30.3) (64.7) - - 3.3
Special termination benefits expense/(income) - 8.1 93.3 - (1.2) 8.6
----------------------------------------------------------------------------------------------------------
Total - settlements, curtailments and special
termination benefits - (22.2) 2.6 - (1.2) 11.9
----------------------------------------------------------------------------------------------------------
Total - net periodic (income)/expense $(31.8) $(95.6) $ (98.4) $ 35.1 $ 33.3 $ 40.2
----------------------------------------------------------------------------------------------------------
|
For calculating pension and postretirement benefit income and expense amounts, the following assumptions were used:
----------------------------------------------------------------------------------------------
For the Years Ended December 31,
----------------------------------------------------------------------------------------------
Statements of Income Pension Benefits Postretirement Benefits
----------------------------------------------------------------------------------------------
2003 2002 2001 2003 2002 2001
----------------------------------------------------------------------------------------------
Discount rate 6.75% 7.25% 7.50% 6.75% 7.25% 7.50%
Expected long-term rate of return 8.75% 9.25% 9.50% 8.75% 9.25% 9.50%
Compensation/progression rate 4.00% 4.25% 4.50% N/A N/A N/A
----------------------------------------------------------------------------------------------
|
The following table represents the PBOP assumed health care cost trend rate for the next year and the assumed ultimate trend rate:
---------------------------------------------------------------
Year Following December 31,
---------------------------------------------------------------
2003 2002
Health care cost trend rate
assumed for next year 8.00% 9.00%
Rate to which health care cost
trend rate is assumed to
decline (the ultimate trend rate) 5.00% 5.00%
Year that the rate reaches the
ultimate trend rate 2007 2007
----------------------------------------------------------------
|
The annual per capita cost of covered health care benefits was assumed to decrease by one percentage point each year through 2007. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. The effect of changing the assumed health care cost trend rate by one percentage point in each year would have the following effects:
----------------------------------------------------------------
One Percentage One Percentage
(Millions of Dollars) Point Increase Point Decrease
----------------------------------------------------------------
Effect on total service and
interest cost components $ 0.8 $ (0.7)
Effect on postretirement
benefit obligation $12.5 $(11.3)
----------------------------------------------------------------
|
NU's investment strategy for its Pension Plan and PBOP Plan is to maximize the long-term rate of return on those plans' assets within an acceptable level of risk. The investment strategy establishes target allocations, which are regularly reviewed and periodically rebalanced. NU's expected long-term rates of return on Pension Plan assets and PBOP Plan assets are based on these target asset allocation assumptions and related expected long-term rates of return. In developing its expected long-term rate of return assumptions for the Pension Plan and the PBOP Plan, NU also evaluated input from actuaries, consultants and economists as well as long-term inflation assumptions and NU's historical 20-year compounded return of approximately 11 percent. The Pension Plan's and PBOP Plan's target asset allocation assumptions and expected long-term rate of return assumptions by asset category are as follows:
-----------------------------------------------------------------------------------------------------------------
At December 31,
-----------------------------------------------------------------------------------------------------------------
Pension Benefits Postretirement Benefits
-----------------------------------------------------------------------------------------------------------------
2003 2002 2003 2002
-----------------------------------------------------------------------------------------------------------------
Target Assumed Target Assumed Target Assumed Target Assumed
Asset Rate of Asset Rate of Asset Rate of Asset Rate of
Asset Category Allocation Return Allocation Return Allocation Return Allocation Return
-----------------------------------------------------------------------------------------------------------------
Equity securities:
United States 45.00% 9.25% 45.00% 9.75% 55.00% 9.25% 55.00% 9.75%
Non-United States 14.00% 9.25% 14.00% 9.75% 11.00% 9.25% - -
Emerging markets 3.00% 10.25% 3.00% 10.75% 2.00% 10.25% - -
Private 8.00% 14.25% 8.00% 14.75% - - - -
Debt Securities:
Fixed income 20.00% 5.50% 20.00% 6.25% 27.00% 5.50% 45.00% 6.25%
High yield fixed
income 5.00% 7.50% 5.00% 7.50% 5.00% 7.50% - -
Real estate 5.00% 7.50% 5.00% 7.50% - - - -
-----------------------------------------------------------------------------------------------------------------
|
The actual asset allocations at December 31, 2003 and 2002, approximated these target asset allocations. The plans' actual weighted-average asset allocations by asset category are as follows:
---------------------------------------------------------------------
At December 31,
---------------------------------------------------------------------
Postretirement
Pension Benefits Benefits
---------------------------------------------------------------------
Asset Category 2003 2002 2003 2002
---------------------------------------------------------------------
Equity securities:
United States 47.00% 46.00% 59.00% 55.00%
Non-United States 18.00% 17.00% 12.00% -
Emerging markets 3.00% 3.00% 1.00% -
Private 3.00% 3.00% - -
Debt Securities:
Fixed income 19.00% 21.00% 25.00% 45.00%
High yield fixed
income 5.00% 5.00% 3.00% -
Real estate 5.00% 5.00% - -
---------------------------------------------------------------------
Total 100.00% 100.00% 100.00% 100.00%
---------------------------------------------------------------------
|
Currently, NU's policy is to annually fund an amount at least equal to that which will satisfy the requirements of the Employee Retirement Income Security Act and Internal Revenue Code.
NU does not expect to make any contributions to the Pension Plan in 2004 and expects to make $41.3 million in contributions to the PBOP Plan in 2004.
Postretirement health plan assets for non-union employees are subject to federal income taxes.
B. 401(K) SAVINGS PLAN NU maintains a 401(k) Savings Plan for substantially all NU employees. This savings plan provides for employee contributions up to specified limits. NU matches employee contributions up to a maximum of 3 percent of eligible compensation with cash and NU shares. The matching contributions made by NU were $9.9 million in 2003, $11.1 million in 2002 and $11.7 million in 2001.
C. EMPLOYEE STOCK OWNERSHIP PLAN NU maintains an Employee Stock Ownership Plan (ESOP) for purposes of allocating shares to employees participating in the NU's 401(k) Savings Plan. Under this arrangement, NU issued unsecured notes during 1991 and 1992 totaling $250 million, the proceeds of which were loaned to the ESOP trust for the purchase of 10.8 million newly issued NU common shares (ESOP shares). The ESOP trust is obligated to make principal and interest payments on the ESOP notes at the same rate that ESOP shares are allocated to employees. NU makes annual contributions to the ESOP equal to the ESOP's debt service, less dividends received by the ESOP. All dividends received by the ESOP on unallocated shares are used to pay debt service and are not considered dividends for financial reporting purposes. During the first and second quarters of 2002, NU declared a $0.125 per share quarterly dividend. During the third quarter of 2002 through the second quarter of 2003, NU declared a $0.1375 per share quarterly dividend. NU declared a $0.15 per share dividend during the third and fourth quarters of 2003.
In 2003 and 2002, the ESOP trust issued 607,020 and 607,475 of NU common shares, respectively, to satisfy 401(k) Savings Plan obligations to employees. At December 31, 2003 and 2002, total allocated ESOP shares were 7,615,804 and 7,008,784, respectively, and total unallocated ESOP shares were 3,184,381 and 3,791,401, respectively. The fair market value of the unallocated ESOP shares at December 31, 2003 and 2002, was $64.2 million and $57.5 million, respectively.
D. EQUITY-BASED COMPENSATION ESPP: Since July 1998, NU has maintained an ESPP for all eligible employees. Under the ESPP, NU common shares are purchased at six-month intervals at 85 percent of the lower of the price on the first or last day of each six-month period. Employees may purchase shares having a value not exceeding 25 percent of their compensation as of the beginning of the purchase period. During 2003 and 2002, employees purchased 225,985 and 188,774 shares, respectively, at discounted prices of $12.20 in 2003 and $14.15 and $15.39 in 2002. At December 31, 2003 and 2002, 1,585,241 shares and 1,811,226 shares remained registered for future issuance under the ESPP, respectively.
Incentive Plans: Under the Northeast Utilities Incentive Plan (Incentive Plan), NU is authorized to grant various types of awards, including restricted stock, performance units, restricted stock units, and stock options to eligible employees and board members. The number of shares that may be utilized for grants and awards during a given calendar year may not exceed the aggregate of one percent of the total number of shares of NU common shares outstanding as of the first day of that calendar year and the shares not utilized in previous years. At December 31, 2003 and 2002, NU had 1,649,268 and 2,440,339 shares of common stock, respectively, registered for issuance under the Incentive Plan.
Restricted Stock: During 2003, NU granted 417,222 shares of restricted stock under the Incentive Plan. The shares granted in 2003 had a fair value of $6.1 million when granted and were recorded as an offset to shareholders' equity. NU also made several grants of restricted stock during 2002 and 2001 under the Incentive Plan. During 2003, 2002 and 2001, $2 million, $1 million and $1.2 million, respectively, was expensed related to restricted stock.
Performance Units and Restricted Stock Units: Under the Incentive Plan, NU also granted 35,303 and 38,847 performance units during 2003 and 2002, respectively. There were no performance units granted in 2001. The performance units vest ratably over three years and will be paid in cash at the end of the vesting period. NU records a liability for the performance units based on the achievement of the performance unit goals. A liability of $1.5 million and $1.3 million was recorded at December 31, 2003 and 2002, respectively, for these performance units. During 2003 and 2002, $0.2 million and $1.3 million, respectively, was expensed related to these performance units.
During 2003, 75,000 restricted stock units were granted, all of which were forfeited effective January 1, 2004.
Stock Options: Prior to 2003, NU granted stock options to certain employees. The exercise price of stock options, as set at the time of grant, is equal to the fair market value per share at the date of grant, and therefore no equity- based compensation cost is reflected in net income. No stock options were granted during 2003, and stock option transactions for 2002 and 2001 are as follows:
-----------------------------------------------------------------------------------------------------
Exercise Price Per Share
-------------------------------------------
Options Range Weighted Average
-----------------------------------------------------------------------------------------------------
Outstanding - December 31, 2000 2,433,862 $ 9.3640 - $22.2500 $15.2569
Granted 817,300 $17.4000 - $21.0300 $20.2065
Exercised (108,779) $ 9.3640 - $19.5000 $16.0970
Forfeited and cancelled (132,467) $14.8750 - $21.0300 $18.2217
-----------------------------------------------------------------------------------------------------
Outstanding - December 31, 2001 3,009,916 $ 9.6250 - $22.2500 $16.4467
-----------------------------------------------------------------------------------------------------
Granted 1,337,345 $16.5500 - $19.8700 $17.8284
Exercised (262,800) $10.0134 - $19.5000 $15.4666
Forfeited and cancelled (247,152) $14.9375 - $22.2500 $18.3473
-----------------------------------------------------------------------------------------------------
Outstanding - December 31, 2002 3,837,309 $ 9.6250 - $22.2500 $16.8738
-----------------------------------------------------------------------------------------------------
Exercised (562,982) $ 9.6250 - $19.5000 $14.6223
Forfeited and cancelled (151,005) $14.9375 - $21.0300 $19.0227
-----------------------------------------------------------------------------------------------------
Outstanding - December 31, 2003 3,123,322 $ 9.6250 - $22.2500 $17.1270
-----------------------------------------------------------------------------------------------------
Exercisable - December 31, 2001 1,712,260 $ 9.6250 - $22.2500 $14.4650
-----------------------------------------------------------------------------------------------------
Exercisable - December 31, 2002 1,956,555 $ 9.6250 - $22.2500 $15.3758
-----------------------------------------------------------------------------------------------------
Exercisable - December 31, 2003 2,027,413 $ 9.6250 - $22.2500 $16.6969
-----------------------------------------------------------------------------------------------------
|
In 1997, 500,000 options with a weighted average exercise price of $9.625 were granted. These options, of which 350,000 are outstanding and exercisable at December 31, 2003, have a remaining contractual life of 3.63 years. Excluding these options from those outstanding at December 31, 2003, the resulting range of exercise prices is $14.9375 to $22.25.
For certain options that were granted in 2002, 2001 and 2000, the vesting schedule for these options is ratably over three years from the date of grant. Additionally, certain options granted in 2002, 2001 and 2000 vest 50 percent at the date of grant and 50 percent one year from the date of grant, while other options granted in 2002 vest 100 percent after five years.
The fair value of each stock option grant has been estimated on the date of grant using the Black-Scholes option pricing model with the following weighted average assumptions. No stock options were granted during 2003.
------------------------------------------------------
2002 2001
------------------------------------------------------
Risk-free interest rate 4.86% 5.34%
Expected life 10 years 10 years
Expected volatility 23.71% 25.47%
Expected dividend yield 2.11% 2.11%
------------------------------------------------------
|
The weighted average grant date fair values of options granted during 2002 and 2001 were $5.64 and $6.94, respectively. The weighted average remaining contractual lives for the options outstanding at December 31, 2003 is 6.79 years.
For further information regarding equity-based compensation, see Note 1M, "Summary of Significant Accounting Policies - Equity-Based Compensation."
E. SUPPLEMENTAL EXECUTIVE RETIREMENT AND OTHER PLANS NU has maintained a Supplemental Executive Retirement Plan (SERP) since 1987. The SERP provides its participants, who are executives of NU, with benefits that would have been provided to them under NU's retirement plan if certain Internal Revenue Code and other limitations were not imposed. The SERP liability of $22.1 million and $20.1 million at December 31, 2003 and 2002, respectively, represents NU's actuarially-determined obligation under the SERP. During 2003, 2002, and 2001, $3.9 million, $3.8 million, and $4 million, respectively, was expensed related to the SERP. The SERP is the only NU retirement plan for which a minimum pension liability has been recorded. Recording this minimum pension liability resulted in a reduction of $0.8 million to accumulated other comprehensive income at December 31, 2003. For information regarding the SERP investments, see Note 8, "Fair Value of Financial Instruments," to the consolidated financial statements.
NU maintains a plan for retirement and other benefits for certain current and past company officers. The actuarially-determined liability for this plan was $35.5 million and $32.2 million at December 31, 2003 and 2002, respectively. During 2003, 2002, and 2001, $6.3 million, $7.8 million, and $3.2 million, respectively, was expensed related to this plan.
Effective January 1, 2002, NU adopted SFAS No. 142, "Goodwill and Other Intangible Assets," which ended the amortization of goodwill and certain intangible assets with indefinite useful lives. SFAS No. 142 also requires that goodwill and intangible assets deemed to have indefinite useful lives be reviewed for impairment at least annually by applying a fair value-based test. NU selected October 1 as the annual goodwill impairment testing date. Goodwill impairment is deemed to exist if the net book value of a reporting unit exceeds its estimated fair value and if the implied fair value of goodwill based on the estimated fair value of the reporting unit is less than the carrying amount. Excluding adjustments to the purchase price allocation related to the acquisition of Woods Electrical Co., Inc. (Woods Electrical) and Woods Network, there were no impairments or adjustments to the goodwill balances during 2003. The adjustments primarily related to the reclassification between goodwill and intangible assets. In July 2002, NU Enterprises acquired certain assets and assumed certain liabilities of Woods Electrical, an electrical services company, and Woods Network, a network products and service company.
NU's reporting units that maintain goodwill are generally consistent with the operating segments underlying the reportable segments identified in Note 12, "Segment Information," to the consolidated financial statements. Consistent with the way management reviews the operating results of its reporting units, NU's reporting units under the NU Enterprises reportable segment include: 1) the merchant energy business line reporting unit, and 2) the energy services business line reporting unit. The merchant energy business line reporting unit is comprised of the operations of Select Energy, NGC and the generation operations of HWP, while the energy services business line reporting unit is comprised of the operations of SESI, NGS and Woods Network. As a result, NU's reporting units that maintain goodwill are as follows: Yankee Gas, which is classified under the Utility Group - gas reportable segment; the merchant energy business line reporting unit; and the energy services business line reporting unit, both of which are classified under the NU Enterprises reportable segment. The goodwill balances of these reporting units are included in the table herein.
NU has completed its impairment analyses as of October 1, 2003, for all reporting units that maintain goodwill and has determined that no impairment exists. In completing these analyses, the fair values of the reporting units were estimated using both discounted cash flow methodologies and an analysis of comparable companies or transactions.
At December 31, 2003, NU maintained $319.9 million of goodwill that is no longer being amortized, $14.4 million of identifiable intangible assets subject to amortization and $8.5 million of intangible assets not subject to amortization. At December 31, 2002, NU maintained $321 million of goodwill that is no longer being amortized, $18.1 million of identifiable intangible assets subject to amortization and $6.8 million of intangible assets not subject to amortization. A summary of NU's goodwill balances at December 31, 2003 and 2002, by reportable segment and reporting unit is as follows:
------------------------------------------------------
At December 31,
------------------------------------------------------
(Millions of Dollars) 2003 2002
------------------------------------------------------
Utility Group - Gas:
Yankee Gas $287.6 $287.6
NU Enterprises:
Energy Services Business Line 29.1 30.2
Merchant Energy Business Line 3.2 3.2
------------------------------------------------------
Totals $319.9 $321.0
------------------------------------------------------
|
The goodwill recorded related to the acquisition of Yankee Gas is not being recovered from the customers of Yankee Gas.
At December 31, 2003 and December 31, 2002, NU's intangible assets and related accumulated amortization consisted of the following:
--------------------------------------------------------------------------
At December 31, 2003
--------------------------------------------------------------------------
Gross Accumulated Net
(Millions of Dollars) Balance Amortization Balance
--------------------------------------------------------------------------
Intangible assets subject
to amortization:
Exclusivity agreement $17.7 $ 7.2 $10.5
Customer list 6.6 2.7 3.9
Customer backlog,
employment related
agreements and other 0.1 0.1 -
--------------------------------------------------------------------------
Totals $24.4 $10.0 $14.4
--------------------------------------------------------------------------
Intangible assets not
subject to amortization:
Customer relationships $ 5.2
Tradenames 3.3
---------------------------------------------------
Totals $ 8.5
---------------------------------------------------
--------------------------------------------------------------------------
At December 31, 2002
--------------------------------------------------------------------------
Gross Accumulated Net
(Millions of Dollars) Balance Amortization Balance
--------------------------------------------------------------------------
Intangible assets subject
to amortization:
Exclusivity agreement $17.7 $4.6 $13.1
Customer list 6.6 1.7 4.9
Customer backlog,
employment related
agreements and other 0.1 - 0.1
--------------------------------------------------------------------------
Totals $24.4 $6.3 $18.1
--------------------------------------------------------------------------
Intangible assets not
subject to amortization:
Customer relationships $ 3.8
Tradenames 3.0
---------------------------------------------------
Totals $ 6.8
---------------------------------------------------
|
NU recorded amortization expense of $3.7 million and $2.1 million for the years ended December 31, 2003 and 2002, respectively, related to these intangible assets. Substantially all of the intangible assets subject to amortization are being amortized over a period of 8.5 years. Based on the current amount of intangible assets subject to amortization, the estimated annual amortization expense for each of the succeeding 5 years is $3.6 million in 2004 through 2007 and no amortization expense in 2008. These amounts may vary as acquisitions and dispositions occur in the future.
The results for the year ended December 31, 2001, on a historical basis, do not reflect the provisions of SFAS No. 142. Had NU adopted SFAS No. 142 on January 1, 2001, historical income before the cumulative effect of an accounting change, net income and basic and fully diluted EPS amounts would have been adjusted as follows:
--------------------------------------------------------------------------
(Millions of Dollars, except Net Basic Fully
share information) Income EPS Diluted EPS
--------------------------------------------------------------------------
Year Ended December 31, 2003:
--------------------------------------------------------------------------
Reported income before cumulative
effect of accounting change $121.1 $0.95 $0.95
--------------------------------------------------------------------------
Reported net income $116.4 $0.91 $0.91
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Year Ended December 31, 2002:
--------------------------------------------------------------------------
Reported income before cumulative
effect of accounting change $152.1 $1.18 $1.18
--------------------------------------------------------------------------
Reported net income $152.1 $1.18 $1.18
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Year Ended December 31, 2001:
--------------------------------------------------------------------------
Reported income before cumulative
effect of accounting change $265.9 $1.97 $1.96
Add back: goodwill amortization 9.0 0.07 0.07
--------------------------------------------------------------------------
Adjusted income before cumulative
effect of accounting change $274.9 $2.04 $2.03
==========================================================================
Reported net income $243.5 $1.80 $1.79
Add back: goodwill amortization 9.0 0.07 0.07
--------------------------------------------------------------------------
Adjusted net income $252.5 $1.87 $1.86
==========================================================================
|
Seabrook: On November 1, 2002, CL&P and NAEC consummated the sale of their 40.04 percent combined ownership interest in Seabrook to a subsidiary of FPL. CL&P, NAEC and certain other of the joint owners collectively sold 88.2 percent of Seabrook to FPL. NU received approximately $367 million of total cash proceeds from the sale of Seabrook and another approximately $17 million from Baycorp Holdings, Ltd. (Baycorp), as a result of the sale of its interest in Seabrook. A portion of this cash was used to repay all $90 million of NAEC's outstanding debt and other short-term debt, to return a portion of NAEC's equity to NU and was used to pay approximately $93 million in taxes. The remaining proceeds received by NAEC were refunded to PSNH through the Seabrook Power Contracts. As part of the sale, FPL assumed responsibility for decommissioning Seabrook. NAEC and CL&P recorded a gain on the sale in the amount of approximately $187 million, which was primarily used to offset stranded costs.
In the third quarter of 2002, CL&P and NAEC received regulatory approvals for the sale of Seabrook from the DPUC and the NHPUC. As a result of these approvals, CL&P and NAEC eliminated $0.6 million and $13.9 million, respectively, on an after-tax basis, of reserves related to their respective ownership shares of certain Seabrook assets.
On October 10, 2000, NU reached an agreement with Baycorp, a 15 percent joint owner of Seabrook, under which NU guaranteed a minimum sale price, and NU and Baycorp would share the excess proceeds if the sale of Seabrook resulted in proceeds of more than $87.2 million for Baycorp's 15 percent ownership interest. The agreement also limited any accelerated decommissioning funding required to be funded by Baycorp as part of the sale process. NU received approximately $17 million in 2002 in connection with this agreement. This amount is included in the $38.7 million of pre-tax Seabrook-related gains included in other income/(loss), net.
VYNPC: On July 31, 2002, VYNPC consummated the sale of its nuclear generating plant to a subsidiary of Entergy Corporation (Entergy) for approximately $180 million. As part of the sale, Entergy assumed responsibility for decommissioning VYNPC's nuclear generating unit. On November 7, 2003, CL&P, PSNH and WMECO sold their collective 17 percent ownership interest in VYNPC. CL&P, PSNH and WMECO will continue to buy approximately 16 percent of the plant's output through March 2012 at a range of fixed prices.
A. RESTRUCTURING AND RATE MATTERS
Connecticut:
Impacts of Standard Market Design: On March 1, 2003, ISO-NE implemented SMD. As part of SMD, LMP is utilized to assign value and causation to transmission congestion and line losses.
CL&P was billed $186 million of incremental LMP costs by its standard offer service suppliers or by ISO-NE. CL&P recovered a portion of these costs through an additional charge on customer bills beginning on May 1, 2003. Billings were on a two-month lag and were recorded as operating revenues when billed. Amounts were recovered subject to refund.
CL&P and its suppliers, including affiliate Select Energy, disputed the responsibility for the $186 million of incremental LMP costs incurred. NU recorded a pre-tax loss in 2003 of approximately $60 million ($36.9 million after-tax) related to an agreement in principle to settle this dispute. On February 23, 2004, CL&P, its suppliers, and other parties reached an agreement in principle to settle the dispute. A settlement agreement is subject to approval by the FERC.
The pre-tax loss of approximately $60 million was reflected in two line items on the consolidated statements of income. Approximately $58 million was recorded as a reduction to operating revenues, and approximately $2 million was recorded in operating expenses.
Disposition of Seabrook Proceeds: CL&P sold its share of the Seabrook nuclear unit on November 1, 2002. The net proceeds in excess of the book value of Seabrook of $16 million were recorded as a regulatory liability and, after being offset by accelerated decommissioning funding and other adjustments, will be refunded to customers. On May 1, 2003, CL&P filed its application with the DPUC for approval of the disposition of the proceeds from the sale. This filing described CL&P's treatment of its share of the proceeds from the sale. Hearings in this docket were held in September 2003, and a draft decision was received on February 3, 2004. Management does not believe that the final decision, which is expected in March 2004, will have a material effect on CL&P's net income or financial position.
CTA and SBC Reconciliation Filing: On April 3, 2003, CL&P filed its annual CTA and SBC reconciliation with the DPUC. For the year ended December 31, 2002, total CTA revenues and excess GSC revenues exceeded the CTA revenue requirement by $93.5 million. This amount was recorded as a regulatory liability. For the same period, SBC revenues exceeded the SBC revenue requirement by $22.4 million. In compliance with a prior decision of the DPUC, a portion of the SBC overcollection reduced regulatory assets, and the remaining overcollection of $18.6 million was applied to the CTA. The DPUC's December 19, 2003 transitional standard offer (TSO) decision addressed $41 million of SBC overcollections and $64 million of CTA overcollections that had been estimated as of December 31, 2003. In its decision, the DPUC ordered that $80 million of the overcollections be used to reduce CTA costs during the 2004 through 2006 TSO period. The DPUC also ordered that $25 million of the overcollections be used to offset SBC costs during the TSO period. The DPUC also ordered that $37 million of GSC overcollections be used to pay CL&P's 0.50 mill/kWh procurement fee during the TSO period.
New Hampshire:
SCRC Reconciliation Filing: On an annual basis, PSNH files with the NHPUC an SCRC reconciliation filing for the preceding calendar year. This filing includes the reconciliation of stranded cost revenues with stranded costs, and transition energy service (TS) revenues with TS costs. The NHPUC reviews the filing, including a prudence review of PSNH's generation operations.
The 2003 SCRC filing is expected to be filed on May 1, 2004. Management does not expect the review of the 2003 SCRC filing to have a material effect on PSNH's net income or financial position.
Massachusetts:
Transition Cost Reconciliations: On March 31, 2003, WMECO filed its 2002 transition cost reconciliation with the Massachusetts Department of Telecommunications and Energy (DTE). This filing reconciled the recovery of generation-related stranded costs for calendar year 2002 and included the renegotiated purchased power contract related to the Vermont Yankee nuclear unit.
On July 15, 2003, the DTE issued a final order on WMECO's 2001 transition cost reconciliation, which addressed WMECO's cost tracking mechanisms. As part of that order, the DTE directed WMECO to revise its 2002 annual transition cost reconciliation filing. The revised filing was submitted to the DTE on September 22, 2003. Hearings have been held, and the timing of a final decision from the DTE is uncertain. Management does not expect the outcome of this docket to have a material adverse impact on WMECO's net income or financial position.
B. NRG ENERGY, INC. EXPOSURES Certain subsidiaries of NU, including CL&P and Yankee Gas, have entered into transactions with NRG Energy, Inc. (NRG) and certain of its subsidiaries. On May 14, 2003, NRG and certain of its subsidiaries filed voluntary bankruptcy petitions. On December 5, 2003, NRG emerged from bankruptcy. NU's NRG- related exposures as a result of these transactions relate to 1) the recovery of congestion charges incurred by NRG prior to the implementation of SMD on March 1, 2003, 2) the recovery of CL&P's station service billings to NRG, and 3) the recovery of Yankee Gas' and CL&P's expenditures that were incurred related to an NRG subsidiary's generating plant construction project that is now abandoned. While it is unable to determine the ultimate outcome of these issues, management does not expect their resolution will have a material adverse effect on NU's consolidated financial condition or results of operations.
C. ENVIRONMENTAL MATTERS General: NU is subject to environmental laws and regulations intended to mitigate or remove the effect of past operations and improve or maintain the quality of the environment. These laws and regulations require the removal or the remedy of the effect on the environment of the disposal or release of certain specified hazardous substances at current and former operating sites. As such, NU has an active environmental auditing and training program and believes that it is substantially in compliance with all enacted laws and regulations.
Environmental reserves are accrued using a probabilistic model approach when assessments indicate that it is probable that a liability has been incurred and an amount can be reasonably estimated. The probabilistic model approach estimates the liability based on the most likely action plan from a variety of available remediation options, ranging from no action to several different remedies ranging from establishing institutional controls to full site remediation and monitoring.
These estimates are subjective in nature as they take into consideration several different remediation options at each specific site. The reliability and precision of these estimates can be affected by several factors including new information concerning either the level of contamination at the site, recently enacted laws and regulations or a change in cost estimates due to certain economic factors.
The amounts recorded as environmental liabilities on the consolidated balance sheets represent management's best estimate of the liability for environmental costs and takes into consideration site assessment and remediation costs. Based on currently available information for estimated site assessment and remediation costs at December 31, 2003 and 2002, NU had $40.8 million and $41.9 million, respectively, recorded as environmental reserves. A reconciliation of the total amount reserved at December 31, 2003 and 2002 is as follows:
-------------------------------------------------------------------
(Millions of Dollars) For the Years Ended December 31,
-------------------------------------------------------------------
2003 2002
-------------------------------------------------------------------
Balance at beginning of year $ 41.9 $ 46.2
Additions and adjustments 4.1 5.4
Payments (5.2) (9.7)
-------------------------------------------------------------------
Balance at end of year $ 40.8 $ 41.9
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|
These liabilities are estimated on an undiscounted basis and do not assume that any amounts are recoverable from insurance companies or other third parties. The environmental reserve includes sites at different stages of discovery and remediation and does not include any unasserted claims. At December 31, 2003, there are nine sites for which there are unasserted claims; however, any related remediation costs are not probable or estimable at this time. NU's environmental liability also takes into account recurring costs of managing hazardous substances and pollutants, mandated expenditures to remediate previously contaminated sites and any other infrequent and non- recurring clean up costs.
NU currently has 50 sites included in the environmental reserve. Of those 50 sites, 20 sites are in the remediation or long-term monitoring phase, 24 sites have had site assessments completed and the remaining six sites are in the preliminary stages of site assessment.
In addition, capital expenditures related to environmental matters are expected to total approximately $106 million in aggregate for the years 2004 through 2008. Of the $106 million, $70 million relates to the proposed conversion of a 50 megawatt oil and coal burning unit at Schiller Station to a wood burning unit. The remainder primarily relates to other environmental remediation programs including programs associated with NU's hydroelectric generation assets.
MGP Sites: Manufactured gas plant (MGP) sites comprise the largest portion of NU's environmental liability. MGPs are sites that manufactured gas from coal and produced certain byproducts that may pose risk to human health and the environment. At December 31, 2003 and 2002, $36.3 million and $38.3 million, respectively, represent amounts for the site assessment and remediation of MGPs. At December 31, 2003 and 2002, the five largest MGP sites comprise approximately 57 percent and 55 percent, respectively, of the total MGP environmental liability. NU currently has 29 MGP sites included in its environmental liability and five contingent MGP sites of which management is aware and for which costs are not probable or estimable at this time. Of the 29 MGP sites, seven are currently undergoing remediation efforts with the remainder in the site assessment stage.
At December 31, 2003, NU has one site that is held for sale. The site, a former MGP site, is currently held for sale under a pending purchase and sale agreement. NU is currently remediating the property and has been deferring the costs associated with those remediation efforts as allowed by a regulatory order. At December 31, 2003, NU had $7.8 million related to remediation efforts at the property and other sale costs recorded in other deferred debits on the accompanying consolidated balance sheets.
The pending purchase and sale agreement releases NU from all environmental claims arising out of or in connection with the property. The purchase price in the pending purchase and sale agreement exceeds the book value of the land including the aforementioned deferred environmental remediation costs.
CERCLA Matters: The Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA) and its' amendments or state equivalents impose joint and several strict liabilities, regardless of fault, upon generators of hazardous substances resulting in removal and remediation costs and environmental damages. Liabilities under these laws can be material and in some instances may be imposed without regard to fault or for past acts that may have been lawful at the time they occurred. NU has five superfund sites under CERCLA for which it has been notified that it is a potentially responsible party (PRP). For sites where there are other PRPs and NU's subsidiaries are not managing the site assessment and remediation, the liability accrued represents NU's estimate of what it will need to pay to settle its obligations with respect to the site.
It is possible that new information or future developments could require a reassessment of the potential exposure to related environmental matters. As this information becomes available management will continue to assess the potential exposure and adjust the reserves as necessary.
Rate Recovery: PSNH and Yankee Gas have rate recovery mechanisms for environmental costs. CL&P recovers a certain level of environmental costs currently in rates but does not have an environmental cost recovery tracking mechanism. Accordingly, changes in CL&P's environmental reserves impact CL&P's earnings. WMECO does not have a regulatory mechanism to recover environmental costs from its customers, and changes in WMECO's environmental reserves impact WMECO's earnings.
D. SPENT NUCLEAR FUEL DISPOSAL COSTS Under the Nuclear Waste Policy Act of 1982, CL&P, PSNH, WMECO, and NAEC must pay the DOE for the disposal of spent nuclear fuel and high-level radioactive waste. The DOE is responsible for the selection and development of repositories for, and the disposal of, spent nuclear fuel and high-level radioactive waste. For nuclear fuel used to generate electricity prior to April 7, 1983 (Prior Period Fuel), an accrual has been recorded for the full liability, and payment must be made prior to the first delivery of spent fuel to the DOE. Until such payment is made, the outstanding balance will continue to accrue interest at the 3-month treasury bill yield rate. At December 31, 2003 and 2002, fees due to the DOE for the disposal of Prior Period Fuel were $256.4 million and $253.6 million, respectively, including interest costs of $174.3 million and $171.5 million, respectively.
Fees for nuclear fuel burned on or after April 7, 1983, were billed currently to customers and were paid to the DOE on a quarterly basis. At December 31, 2003, NU's ownership shares of Millstone and Seabrook have been sold, and NU is no longer responsible for fees relating to fuel burned at these facilities since their sale.
E. NUCLEAR INSURANCE CONTINGENCIES In conjunction with the divestiture of Millstone in 2001 and Seabrook in 2002, NU terminated its nuclear insurance related to these plants, and NU has no further exposure for potential assessments related to Millstone and Seabrook. However, through its continuing association with Nuclear Electric Insurance Limited (NEIL) and CYAPC, NU is subject to potential retrospective assessments totaling $0.8 million under its respective NEIL insurance policies.
F. LONG-TERM CONTRACTUAL ARRANGEMENTS VYNPC: Previously, under the terms of their agreements, NU's companies paid their ownership (or entitlement) shares of costs, which included depreciation, O&M expenses, taxes, the estimated cost of decommissioning, and a return on invested capital to VYNPC and recorded these costs as purchased- power expenses. On July 31, 2002, VYNPC consummated the sale of its nuclear generating unit to a subsidiary of Entergy for approximately $180 million. Under the terms of the sale, CL&P, PSNH and WMECO will continue to buy approximately 16 percent of the plant's output through March 2012 at a range of fixed prices. The total cost of purchases under contracts with VYNPC amounted to $29.9 million in 2003, $27.6 million in 2002 and $25.3 million in 2001.
Electricity Procurement Contracts: CL&P, PSNH and WMECO have entered into various arrangements for the purchase of electricity. The total cost of purchases under these arrangements amounted to $283.4 million in 2003, $278.3 million in 2002 and $363.9 million in 2001. These amounts relate to IPP contracts and do not include contractual commitments related to CL&P's standard offer, PSNH's short-term power supply management or WMECO's standard offer and default service.
Gas Procurement Contracts: Yankee Gas has entered into long-term contracts for the purchase of a specified quantity of gas in the normal course of business as part of its portfolio to meet its actual sales commitments. These contracts extend through 2006. The total cost of Yankee Gas' procurement portfolio, including these contracts, amounted to $218.6 million in 2003, $158 million in 2002 and $195.8 million in 2001.
Hydro-Quebec: Along with other New England utilities, CL&P, PSNH, WMECO, and HWP have entered into agreements to support transmission and terminal facilities to import electricity from the Hydro-Quebec system in Canada. CL&P, PSNH, WMECO, and HWP are obligated to pay, over a 30-year period ending in 2020, their proportionate shares of the annual O&M expenses and capital costs of those facilities.
Estimated Future Annual Utility Group Costs: The estimated future annual costs of NU's significant long-term contractual arrangements are as follows:
-------------------------------------------------------------------------- (Millions of Dollars) 2004 2005 2006 2007 2008 Thereafter -------------------------------------------------------------------------- VYNPC $ 29.5 $ 27.3 $ 28.5 $ 27.5 $ 28.0 $ 97.2 Electricity Procurement Contracts 314.6 318.1 320.9 253.2 217.5 1,302.6 Gas Procurement Contracts 176.8 158.6 150.2 128.7 36.4 122.3 Hydro-Quebec 25.4 24.3 22.8 20.6 19.8 237.6 -------------------------------------------------------------------------- Totals $546.3 $528.3 $522.4 $430.0 $301.7 $1,759.7 -------------------------------------------------------------------------- |
Select Energy: Select Energy maintains long-term agreements to purchase energy in the normal course of business as part of its portfolio of resources to meet its actual or expected sales commitments. The aggregate amount of these purchase contracts was $5.8 billion at December 31, 2003 as follows:
---------------------------------- Year 2004 $4,471.0 2005 761.5 2006 142.9 2007 84.3 2008 84.7 Thereafter 275.4 ---------------------------------- Total $5,819.8 ---------------------------------- |
Select Energy's purchase contract amounts can exceed the amount expected to be reported in fuel, purchased and net interchange power because energy trading transactions are classified in revenues.
G. NUCLEAR DECOMMISSIONING AND PLANT CLOSURE COSTS In conjunction with the Millstone, Seabrook and VYNPC nuclear generation asset divestitures, the applicable liabilities and nuclear decommissioning trusts were transferred to the purchasers, and the purchasers agreed to assume responsibility for decommissioning their respective units.
NU still has significant decommissioning and plant closure cost obligations to the Yankee Companies that own the Yankee Atomic, Connecticut Yankee (CY) and Maine Yankee nuclear power plants. Each plant has been shut down and is undergoing decommissioning. The Yankee Companies collect decommissioning and closure costs through wholesale FERC-approved rates charged under power purchase agreements to NU electric utility companies 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 the decommissioning and closure costs have already been collected, but a substantial portion related to the decommissioning of CY has not yet 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.
In June 2003, CYAPC notified NU that it had terminated its contract with Bechtel Power Corporation (Bechtel) for the decommissioning of the CY nuclear power plant. CYAPC terminated the contract based on its determination that Bechtel's decommissioning work has been incomplete and untimely and that Bechtel refused to perform the remaining decommissioning work. Bechtel has filed a counterclaim against CYAPC asserting a number of claims and seeking a variety of remedies, including monetary and punitive damages and the rescission of the contract. Bechtel has amended its complaint to add claims for wrongful termination.
In November 2003, CYAPC prepared an updated estimate of the cost of decommissioning its nuclear unit. NU's aggregate share of the estimated increased cost primarily related to the termination of Bechtel is approximately $167.7 million. The respective shares of the estimated increased costs recorded in 2003 are as follows: CL&P, $118.1 million; PSNH, $17.1 million; and WMECO, $32.5 million.
CYAPC is seeking recovery of additional decommissioning costs and other damages from Bechtel and, if necessary, its surety. In pursuing this recovery through pending litigation, CYAPC is also exploring options to structure an appropriate rate application to be filed with the FERC, with any resulting adjustments being charged to the owners of the nuclear unit, including CL&P, PSNH and WMECO. The timing, amount and outcome of these filings cannot be predicted at this time.
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 FERC does not allow these costs to be recovered in wholesale rates, NU would expect the state regulatory commissions to disallow these costs in retail rates as well.
At December 31, 2003 and 2002, NU's remaining estimated obligations for decommissioning and closure costs for the shut down units owned by CYAPC, YAEC and MYAPC were $469.2 million and $354.5 million, respectively.
H. CONSOLIDATED EDISON, INC. MERGER LITIGATION Certain gain and loss contingencies exist with regard to the litigation related to the 1999 merger agreement between NU and Consolidated Edison, Inc. (Con Edison).
On March 5, 2001, Con Edison advised NU that it was unwilling to close its merger with NU on the terms set forth in the parties' merger agreement. On March 12, 2001, NU filed suit against Con Edison seeking damages in excess of $1 billion.
On May 11, 2001, Con Edison filed an amended complaint seeking damages for breach of contract, fraudulent inducement and negligent misrepresentation. Con Edison claimed that it is entitled to recover a portion of the merger synergy savings estimated to have a net present value in excess of $700 million. NU disputes both Con Edison's entitlement to any damages as well as its method of computing its alleged damages.
The companies completed discovery in the litigation and both submitted motions for summary judgment. The court denied Con Edison's motion in its entirety, leaving NU's claim for breach of the merger agreement and partially granted NU's motion for summary judgment by eliminating Con Edison's claims against NU for fraud and negligent misrepresentation.
Various other motions in the case are now pending. 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.
The following methods and assumptions were used to estimate the fair value of each of the following financial instruments:
Cash and Cash Equivalents, Unrestricted Cash from Counterparties, Restricted Cash - LMP, and Special Deposits: The carrying amounts approximate fair value due to the short-term nature of these cash items.
SERP Investments: Investments held for the benefit of the SERP are recorded at fair market value based upon quoted market prices. The investments having a cost basis of $33.8 million and $17.9 million held for benefit of the SERP were recorded at their fair market values at December 31, 2003 and 2002, of $36.9 million and $17.8 million, respectively. For information regarding the SERP liabilities, see Note 4E, "Employee Benefits - Supplemental Executive Retirement and Other Plans," to the consolidated financial statements.
Preferred Stock, Long-Term Debt and Rate Reduction Bonds: The fair value of NU's fixed-rate securities is based upon the quoted market price for those issues or similar issues. Adjustable rate securities are assumed to have a fair value equal to their carrying value. The carrying amounts of NU's financial instruments and the estimated fair values are as follows:
---------------------------------------------------------------------
At December 31, 2003
---------------------------------------------------------------------
(Millions of Dollars) Carrying Amount Fair Value
---------------------------------------------------------------------
Preferred stock not subject
to mandatory redemption $ 116.2 $ 87.5
Long-term debt -
First mortgage bonds 743.0 833.3
Other long-term debt 1,810.7 1,896.5
Rate reduction bonds 1,730.0 1,860.7
---------------------------------------------------------------------
---------------------------------------------------------------------
At December 31, 2002
---------------------------------------------------------------------
(Millions of Dollars) Carrying Amount Fair Value
---------------------------------------------------------------------
Preferred stock not subject
to mandatory redemption $ 116.2 $ 84.0
Long-term debt -
First mortgage bonds 771.0 810.0
Other long-term debt 1,577.2 1,597.8
Rate reduction bonds 1,899.3 2,080.6
---------------------------------------------------------------------
|
Other long-term debt includes $256.4 million and $253.6 million of fees and interest due for spent nuclear fuel disposal costs at December 31, 2003 and 2002, respectively.
Other Financial Instruments: The carrying value of financial instruments included in current assets and current liabilities, including investments in securitizable assets, approximates their fair value.
NU has entered into lease agreements, some of which are capital leases, for the use of data processing and office equipment, vehicles, and office space. The provisions of these lease agreements generally provide for renewal options.
Capital lease rental payments charged to operating expense were $3.7 million in 2003, $1.7 million in 2002, and $13.1 million in 2001. Interest included in capital lease rental payments was $2.3 million in 2003, $0.6 million in 2002, and $4.7 million in 2001. Operating lease rental payments charged to expense were $7.6 million in 2003, $7.8 million in 2002, and $7 million in 2001.
Future minimum rental payments excluding executory costs, such as property taxes, state use taxes, insurance, and maintenance, under long-term noncancelable leases, at December 31, 2003 are as follows:
------------------------------------------------------------------ (Millions of Dollars) Capital Operating Year Leases Leases ------------------------------------------------------------------ 2004 $ 3.1 $ 21.9 2005 3.1 19.6 2006 2.9 17.6 2007 2.6 14.2 2008 2.3 12.0 Thereafter 20.1 27.4 ------------------------------------------------------------------ Future minimum lease payments $34.1 $112.7 Less amount representing interest 18.2 ------------------------------------------------------------------ Present value of future minimum lease payments $15.9 ------------------------------------------------------------------ |
The accumulated balance for each other comprehensive income/(loss) item is as follows:
----------------------------------------------------------------------
Current
December 31, Period December 31,
(Millions of Dollars) 2002 Change 2003
----------------------------------------------------------------------
Qualified cash flow
hedging instruments $15.5 $9.3 $24.8
Unrealized
(losses)/gains
on securities (0.1) 2.1 2.0
Minimum supplemental
executive retirement
pension liability
adjustments (0.5) (0.3) (0.8)
----------------------------------------------------------------------
Accumulated other
comprehensive
income $14.9 $11.1 $26.0
----------------------------------------------------------------------
----------------------------------------------------------------------
Current
December 31, Period December 31,
(Millions of Dollars) 2001 Change 2002
----------------------------------------------------------------------
Qualified cash flow
hedging instruments $(36.9) $52.4 $15.5
Unrealized
gains/(losses)
on securities 5.0 (5.1) (0.1)
Minimum supplemental
executive retirement
pension liability
adjustments (0.6) 0.1 (0.5)
----------------------------------------------------------------------
Accumulated other
comprehensive
(loss)/income $(32.5) $47.4 $14.9
----------------------------------------------------------------------
|
The changes in the components of other comprehensive income/(loss) are reported net of the following income tax effects:
---------------------------------------------------------------------- (Millions of Dollars) 2003 2002 2001 ---------------------------------------------------------------------- Qualified cash flow hedging instruments $(6.4) $(33.1) $24.3 Unrealized (losses)/gains on securities (1.4) 3.3 (1.9) Minimum supplemental executive retirement pension liability adjustments - - - ---------------------------------------------------------------------- Accumulated other comprehensive (loss)/income $(7.8) $(29.8) $22.4 ---------------------------------------------------------------------- |
Accumulated other comprehensive income/(loss) fair value adjustments of NU's qualified cash flow hedging instruments are as follows:
----------------------------------------------------------------------
At December 31,
----------------------------------------------------------------------
(Millions of Dollars, Net of Tax) 2003 2002
----------------------------------------------------------------------
Balance at beginning of year $15.5 $(36.9)
----------------------------------------------------------------------
Hedged transactions
recognized into earnings (5.3) 17.0
Change in fair value 5.0 29.2
Cash flow transactions entered
into for the period 9.6 6.2
----------------------------------------------------------------------
Net change associated with the
current period hedging
transactions 9.3 52.4
----------------------------------------------------------------------
Total fair value adjustments
included in accumulated other
comprehensive income $24.8 $ 15.5
----------------------------------------------------------------------
|
EPS is computed based upon the weighted average number of common shares outstanding during each year. Diluted EPS is computed on the basis of the weighted average number of common shares outstanding plus the potential dilutive effect if certain securities are converted into common stock. In 2003, 2002 and 2001, 355,153 options, 2,968,933 options and 1,268,887 options, respectively, were excluded from the following table as these options were antidilutive. The following table sets forth the components of basic and diluted EPS.
-------------------------------------------------------------------------------------------------------- (Millions of Dollars, except share information) 2003 2002 2001 -------------------------------------------------------------------------------------------------------- Income before preferred dividends of subsidiaries $126.7 $157.7 $273.2 Preferred dividends of subsidiaries 5.6 5.6 7.3 -------------------------------------------------------------------------------------------------------- Income before cumulative effect of accounting change 121.1 152.1 265.9 Cumulative effect of accounting change, net of tax benefit (4.7) - (22.4) -------------------------------------------------------------------------------------------------------- Net income $116.4 $152.1 $243.5 -------------------------------------------------------------------------------------------------------- Basic EPS common shares outstanding (average) 127,114,743 129,150,549 135,632,126 Dilutive effect of employee stock options 125,981 190,811 285,297 -------------------------------------------------------------------------------------------------------- Fully diluted EPS common shares outstanding (average) 127,240,724 129,341,360 135,917,423 -------------------------------------------------------------------------------------------------------- Basic earnings per common share: Income before cumulative effect of accounting change $0.95 $1.18 $1.97 Cumulative effect of accounting change, net of tax benefit (0.04) - (0.17) -------------------------------------------------------------------------------------------------------- Net income $0.91 $1.18 $1.80 -------------------------------------------------------------------------------------------------------- Fully diluted earnings per common share: Income before cumulative effect of accounting change $0.95 $1.18 $1.96 Cumulative effect of accounting change, net of tax benefit (0.04) - (0.17) -------------------------------------------------------------------------------------------------------- Net income $0.91 $1.18 $1.79 -------------------------------------------------------------------------------------------------------- |
NU is organized between the Utility Group and NU Enterprises based on each segments' regulatory environment or lack thereof. The Utility Group segment, including both electric and gas utilities, represents approximately 71 percent, 78 percent and 77 percent of NU's total revenues for the years ended December 31, 2003, 2002 and 2001, respectively, and primarily includes the operations of the electric utilities, CL&P, PSNH and WMECO, whose complete financial statements are included in NU's combined report on Form 10-K. The Utility Group - gas segment also includes the operations of Yankee Gas. Utility Group revenues from the sale of electricity and natural gas primarily are derived from residential, commercial and industrial customers and are not dependent on any single customer.
The NU Enterprises segment includes Select Energy, NGC, SESI, NGS, and their respective subsidiaries. The generation operations of HWP and Woods Network are also included in the NU Enterprises segment.
On January 1, 2000, Select Energy began serving one half of CL&P's standard offer load for a four-year period ending on December 31, 2003, at fixed prices. Total Select Energy revenues from CL&P for CL&P's standard offer load and for other transactions with CL&P represented approximately $688 million or 27 percent for the year ended December 31, 2003, approximately $631 million or 35 percent for the year ended December 31, 2002, and approximately $648 million or 31 percent for the year ended December 31, 2001, of total NU Enterprises' revenues. Total CL&P purchases from NU Enterprises are eliminated in consolidation. Select Energy revenues from NSTAR represented approximately $273.3 million or 13 percent of total NU Enterprises revenues for the year ended December 31, 2001. Beginning in 2002, Select Energy also provides basic generation service in the New Jersey market. Select Energy revenues related to these contracts represented approximately $380.4 million or 15 percent of total NU Enterprises' revenues for the year ended December 31, 2003 and approximately $207.4 million or 12 percent for the year ended December 31, 2002. Additionally, WMECO's purchases from Select Energy for standard offer and default service and for other transactions with Select Energy represented approximately $143 million, $14 million and $4 million of total NU Enterprises' revenues for the years ended December 31, 2003, 2002 and 2001, respectively. No other individual customer represented in excess of 10 percent of NU Enterprises' revenues for the years ended December 31, 2003, 2002 or 2001.
Eliminations and other in the following table includes the results for Mode 1 Communications, Inc., an investor in a fiber-optic communications network, the results of the nonenergy-related subsidiaries of Yankee Energy System, Inc., (Yankee Energy Services Company, RMS, Yankee Energy Financial Services, and NorConn Properties, Inc.) the companies' parent and service companies, and the company's investment in Acumentrics. Interest expense included in eliminations and other primarily relates to the debt of NU parent. Inter- segment eliminations of revenues and expenses are also included in eliminations and other. Eliminations and other includes NU's investment in RMS, which was consolidated with NU effective July 1, 2003, resulting in a negative $4.7 million net of tax cumulative effect of an accounting change.
-------------------------------------------------------------------------------------------------------------
For the Year Ended December 31, 2003
-------------------------------------------------------------------------------------------------------------
Utility Group
--------------------- Eliminations
(Millions of Dollars) Electric Gas NU Enterprises And Other Total
-------------------------------------------------------------------------------------------------------------
Operating revenues $3,975.1 $ 361.5 $2,574.8 $(842.2) $ 6,069.2
Depreciation and amortization (494.9) (23.4) (19.6) (2.3) (540.2)
Other operating expenses (3,115.6) (311.7) (2,508.7) 840.4 (5,095.6)
-------------------------------------------------------------------------------------------------------------
Operating income/(loss) 364.6 26.4 46.5 (4.1) 433.4
Interest expense, net (169.6) (13.1) (49.6) (14.0) (246.3)
Other income/(loss), net 2.1 (2.4) 2.4 (2.5) (0.4)
Income tax (expense)/benefit (66.5) (3.6) (2.8) 12.9 (60.0)
Preferred dividends (5.6) - - - (5.6)
-------------------------------------------------------------------------------------------------------------
Income/(loss) before cumulative
effect of accounting change 125.0 7.3 (3.5) (7.7) 121.1
Cumulative effect of accounting
change, net of tax benefit - - - (4.7) (4.7)
-------------------------------------------------------------------------------------------------------------
Net income/(loss) $ 125.0 $ 7.3 $ (3.5) $ (12.4) $ 116.4
-------------------------------------------------------------------------------------------------------------
Total assets $8,218.0 $1,068.6 $2,125.5 $(103.2) $11,308.9
-------------------------------------------------------------------------------------------------------------
Total investments in plant $ 450.6 $ 55.2 $ 17.7 $ 26.4 $ 549.9
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|
-------------------------------------------------------------------------------------------------------------
For the Year Ended December 31, 2002
-------------------------------------------------------------------------------------------------------------
Utility Group
--------------------- Eliminations
(Millions of Dollars) Electric Gas NU Enterprises And Other Total
-------------------------------------------------------------------------------------------------------------
Operating revenues $3,815.0 $ 282.0 $1,800.8 $(660.8) $ 5,237.0
Depreciation and amortization (618.9) (24.0) (21.6) (2.6) (667.1)
Other operating expenses (2,716.7) (218.1) (1,818.5) 650.1 (4,103.2)
-------------------------------------------------------------------------------------------------------------
Operating income/(loss) 479.4 39.9 (39.3) (13.3) 466.7
Interest expense, net (187.2) (14.2) (43.9) (25.2) (270.5)
Other income/(loss), net 42.1 (0.8) 0.6 1.9 43.8
Income tax (expense)/benefit (121.7) (7.3) 29.4 17.3 (82.3)
Preferred dividends (5.6) - - - (5.6)
-------------------------------------------------------------------------------------------------------------
Net income/(loss) $ 207.0 $ 17.6 $ (53.2) $ (19.3) $ 152.1
-------------------------------------------------------------------------------------------------------------
Total assets $ 7,815.1 $1,042.7 $1,978.2 $ (71.1) $ 10,764.9
-------------------------------------------------------------------------------------------------------------
Total investments in plant $ 376.1 $ 69.8 $ 21.0 $ 18.1 $ 485.0
-------------------------------------------------------------------------------------------------------------
|
-------------------------------------------------------------------------------------------------------------
For the Year Ended December 31, 2001
-------------------------------------------------------------------------------------------------------------
Utility Group
--------------------- Eliminations
(Millions of Dollars) Electric Gas NU Enterprises And Other Total
-------------------------------------------------------------------------------------------------------------
Operating revenues $4,075.5 $ 378.0 $2,074.9 $(767.4) $ 5,761.0
Depreciation and amortization (1,619.3) (33.3) (10.3) 478.8 (1,184.1)
Other operating expenses (1,964.7) (294.6) (2,017.4) 239.0 (4,037.7)
-------------------------------------------------------------------------------------------------------------
Operating income/(loss) 491.5 50.1 47.2 (49.6) 539.2
Interest expense, net (199.3) (14.0) (42.5) (23.9) (279.7)
Other income/(loss), net 72.8 4.1 5.8 104.9 187.6
Income tax (expense)/benefit (154.3) (14.3) (4.4) (0.9) (173.9)
Preferred dividends (7.3) - - - (7.3)
-------------------------------------------------------------------------------------------------------------
Income/(loss) before cumulative
effect of accounting change 203.4 25.9 6.1 30.5 265.9
Cumulative effect of accounting
change, net of tax benefit - - (22.0) (0.4) (22.4)
-------------------------------------------------------------------------------------------------------------
Net income/(loss) $ 203.4 $ 25.9 $ (15.9) $ 30.1 $ 243.5
-------------------------------------------------------------------------------------------------------------
Total investments in plant $ 375.3 $ 47.3 $ 14.6 $ 14.2 $ 451.4
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|
Consolidated Statements of Quarterly Financial Data (Unaudited)
--------------------------------------------------------------------------------------------------------------------
Quarter Ended (a)
--------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars, except per share information) March 31, June 30, September 30, December 31,
--------------------------------------------------------------------------------------------------------------------
2003
--------------------------------------------------------------------------------------------------------------------
Operating Revenues $1,584,183 $1,330,038 $1,640,117 $1,514,818
Operating Income 164,032 105,096 129,727 34,511
Income/(Loss) Before Cumulative Effect of
Accounting Change 60,204 26,869 43,979 (9,900)
Cumulative Effect of Accounting Change,
Net of Tax Benefit - - (4,741) -
--------------------------------------------------------------------------------------------------------------------
Net Income $ 60,204 $ 26,869 $ 39,238 $ (9,900)
--------------------------------------------------------------------------------------------------------------------
Basic and Fully Diluted Earnings Per Common Share:
--------------------------------------------------------------------------------------------------------------------
Income Before Cumulative Effect of Accounting Change $ 0.47 $ 0.21 $ 0.35 $ (0.08)
Cumulative Effect of Accounting Change,
Net of Tax Benefit - - (0.04) -
--------------------------------------------------------------------------------------------------------------------
Net Income $ 0.47 $ 0.21 $ 0.31 $ (0.08)
--------------------------------------------------------------------------------------------------------------------
--------------------------------------------------------------------------------------------------------------------
2002
--------------------------------------------------------------------------------------------------------------------
Operating Revenues $1,279,229 $1,164,205 $1,389,366 $1,404,200
Operating Income 114,286 94,051 118,095 140,223
Net Income 18,642 28,857 48,575 56,035
Basic and Fully Diluted Earnings per Common Share $ 0.14 $ 0.22 $ 0.38 $ 0.44
--------------------------------------------------------------------------------------------------------------------
|
(a) Certain reclassifications of prior years' data have been made to conform with the current year's presentation. The summation of quarterly data may not equal annual data due to rounding. Operating revenue amounts have been reclassified from those reported in 2002 and from those reported in the first three quarters of 2003 on the reports on Form 10-Q because of the adoption of EITF Issue No. 03-11. Quarterly operating revenues as previously reported for 2003 and 2002 are as follows (thousands of dollars):
Quarter Ended 2003 2002 ------------------------------------------------------- March 31 $1,688,437 $1,284,461 June 30 1,457,541 1,141,928 September 30 2,054,274 1,414,304 December 31 1,525,104 1,375,628 ------------------------------------------------------- |
Selected Consolidated Financial Data (Unaudited)
------------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars, except
percentages and share information) 2003 2002 2001 2000 1999
------------------------------------------------------------------------------------------------------------------------------
Balance Sheet Data:
Property, Plant and Equipment, Net $ 5,429,916 $ 5,049,369 $ 4,472,977 $ 3,547,215 $ 3,947,434
Total Assets (a) 11,308,884 10,764,880 10,331,923 10,217,149 9,688,052
Total Capitalization (b) 4,926,587 4,670,771 4,576,858 4,739,417 5,216,456
Obligations Under Capital Leases (b) 15,938 16,803 17,539 159,879 181,293
------------------------------------------------------------------------------------------------------------------------------
Income Data:
Operating Revenues (c) $ 6,069,156 $ 5,237,000 $ 5,760,949 $ 5,876,620 $ 4,471,251
Income Before Cumulative Effect of
Accounting Changes and Extraordinary Loss,
Net of Tax Benefits 121,152 152,109 265,942 205,295 34,216
Cumulative Effect of Accounting Changes,
Net of Tax Benefits (4,741) - (22,432) - -
Extraordinary Loss, Net of Tax Benefit - - - (233,881) -
------------------------------------------------------------------------------------------------------------------------------
Net Income/(Loss) $ 116,411 $ 152,109 $ 243,510 $ (28,586) $ 34,216
------------------------------------------------------------------------------------------------------------------------------
Common Share Data:
Basic Earnings/(Loss) Per Common Share:
Income Before Cumulative Effect of
Accounting Changes and Extraordinary Loss,
Net of Tax Benefits $0.95 $1.18 $1.97 $ 1.45 $ 0.26
Cumulative Effect of Accounting Changes,
Net of Tax Benefits (0.04) - (0.17) - -
Extraordinary Loss, Net of Tax Benefit - - - (1.65) -
------------------------------------------------------------------------------------------------------------------------------
Net Income/(Loss) $0.91 $1.18 $1.80 $(0.20) $ 0.26
------------------------------------------------------------------------------------------------------------------------------
Fully Diluted Earnings/(Loss) Per Common Share:
Income Before Cumulative Effect of
Accounting Changes and Extraordinary Loss,
Net of Tax Benefits $0.95 $1.18 $1.96 $ 1.45 $ 0.26
Cumulative Effect of Accounting Changes,
Net of Tax Benefits (0.04) - (0.17) - -
Extraordinary Loss, Net of Tax Benefit - - - (1.65) -
------------------------------------------------------------------------------------------------------------------------------
Net Income/(Loss) $0.91 $1.18 $1.79 $(0.20) $ 0.26
------------------------------------------------------------------------------------------------------------------------------
Basic Common Shares Outstanding (Average) 127,114,743 129,150,549 135,632,126 141,549,860 131,415,126
Fully Diluted Common Shares
Outstanding (Average) 127,240,724 129,341,360 135,917,423 141,967,216 132,031,573
Dividends Per Share $ 0.58 $ 0.53 $ 0.45 $ 0.40 $ 0.10
Market Price - Closing (high) (d) $20.17 $20.57 $23.75 $24.25 $22.00
Market Price - Closing (low) (d) $13.38 $13.20 $16.80 $18.25 $13.56
Market Price - Closing (end of year) (d) $20.17 $15.17 $17.63 $24.25 $20.56
Book Value Per Share (end of year) $17.73 $17.33 $16.27 $15.43 $15.80
Tangible Book Value Per Share (end of year) $15.27 $14.62 $13.71 $13.09 $15.53
Rate of Return Earned on Average
Common Equity (%) 5.2 7.0 11.2 (1.3) 1.6
Market-to-Book Ratio (end of year) 1.1 0.9 1.1 1.6 1.3
------------------------------------------------------------------------------------------------------------------------------
Capitalization:
Common Shareholders' Equity 46% 47% 46% 47% 40%
Preferred Stock (b) (e) 2 3 3 4 5
Long-Term Debt (b) 52 50 51 49 55
------------------------------------------------------------------------------------------------------------------------------
100% 100% 100% 100% 100%
------------------------------------------------------------------------------------------------------------------------------
|
(a) Total assets were not adjusted for cost of removal prior to 2002.
(b) Includes portions due within one year.
(c) Operating revenue amounts have been reclassified from those reported in
2002 and 2001 related to the adoption of EITF Issue No. 03-11.
(d) Market price information reflects closing prices as presented in the
Wall Street Journal.
(e) Excludes $100 million of Monthly Income Preferred Securities.
Consolidated Sales Statistics (Unaudited)
-------------------------------------------------------------------------------------------------------------------------------
2003 2002 2001 2000 1999
Revenues: (Thousands)
Residential $1,669,199 $1,512,397 $1,490,487 $1,469,439 $1,517,913
Commercial 1,409,445 1,294,943 1,303,351 1,256,126 1,272,969
Industrial 514,076 485,592 549,808 566,625 560,801
Other Utilities 1,678,397 1,247,029 1,554,053 1,884,082 926,056
Streetlighting and Railroads 44,977 43,679 43,889 45,998 45,564
Non-franchised Sales - - - 16,932 24,659
Miscellaneous (50,586) 41,357 64,371 96,666 52,357
-------------------------------------------------------------------------------------------------------------------------------
Total Electric 5,265,508 4,624,997 5,005,959 5,335,868 4,400,319
Gas 573,660 430,642 566,814 461,716 -
Other 229,988 181,361 188,176 79,036 70,932
-------------------------------------------------------------------------------------------------------------------------------
Total $6,069,156 $5,237,000 $5,760,949 $5,876,620 $4,471,251
-------------------------------------------------------------------------------------------------------------------------------
Sales: (kWh - Millions)
Residential 14,824 13,923 13,322 12,940 12,912
Commercial 14,471 14,103 13,751 13,023 12,850
Industrial 6,223 6,265 6,790 7,130 7,050
Other Utilities 18,791 82,538 48,336 42,127 33,575
Streetlighting and Railroads 348 344 332 333 314
Non-franchised Sales - - - 107 147
-------------------------------------------------------------------------------------------------------------------------------
Total 54,657 117,173 82,531 75,660 66,848
-------------------------------------------------------------------------------------------------------------------------------
Customers: (Average)
Residential 1,631,582 1,614,239 1,610,154 1,576,068 1,569,932
Commercial 186,792 183,577 171,218 166,114 164,932
Industrial 7,644 7,763 7,730 7,701 7,721
Other 3,858 3,949 3,969 3,917 3,908
-------------------------------------------------------------------------------------------------------------------------------
Total Electric 1,829,876 1,809,528 1,793,071 1,753,800 1,746,493
Gas 192,816 190,855 190,998 185,328 -
-------------------------------------------------------------------------------------------------------------------------------
Total 2,022,692 2,000,383 1,984,069 1,939,128 1,746,493
-------------------------------------------------------------------------------------------------------------------------------
Average Annual Use Per
Residential Customer (kWh) 9,087 8,611 8,251 8,233 8,243
-------------------------------------------------------------------------------------------------------------------------------
Average Annual Bill Per
Residential Customer $1,024.20 $ 934.90 $ 923.70 $ 934.94 $ 969.38
-------------------------------------------------------------------------------------------------------------------------------
Average Revenue Per kWh:
Residential 11.27 cents 10.86 cents 11.20 cents 11.36 cents 11.76 cents
Commercial 9.74 9.18 9.48 9.65 9.91
Industrial 8.26 7.75 8.10 7.95 7.95
-------------------------------------------------------------------------------------------------------------------------------
|
EXHIBIT 13.2
2003 Annual Report
The Connecticut Light and Power Company
Index
Contents Page -------- ---- Management's Discussion and Analysis of Financial Condition and Results of Operations............................ 1 Independent Auditors' Report..................................... 15 Consolidated Balance Sheets...................................... 16-17 Consolidated Statements of Income................................ 18 Consolidated Statements of Comprehensive Income.................. 18 Consolidated Statements of Common Stockholder's Equity........... 19 Consolidated Statements of Cash Flows............................ 20 Notes to Consolidated Financial Statements....................... 21 Consolidated Quarterly Financial Data (Unaudited)................ 36 Selected Consolidated Financial Data (Unaudited)................. 36 Consolidated Statistics (Unaudited).............................. 36 Bondholder Information........................................... Back Cover |
MANAGEMENT'S DISCUSSION AND ANALYSIS
OVERVIEW
The Connecticut Light and Power Company (CL&P), a wholly owned subsidiary
of Northeast Utilities (NU), earned, before preferred dividends, $68.9
million in 2003, compared with $85.6 million in 2002 and $109.8 million in
2001. The lower 2003 income was primarily attributable to lower pension
income, after-tax write-offs of approximately $5 million related to a
distribution rate case that was decided in December 2003, and a loss
recorded for the settlement of a wholesale power contract dispute between
CL&P and its three 2003 standard offer power suppliers, including an NU
subsidiary, Select Energy, Inc., offset by an adjustment to estimated
unbilled revenues. For more information about this dispute and the
settlement, see the "Impacts of Standard Market Design" section of this
Management's Discussion and Analysis. The lower 2002 income was largely
attributable to an after-tax gain of $17.7 million CL&P recorded in 2001
associated with the sale of the Millstone nuclear units (Millstone).
NU's other subsidiaries include Public Service Company of New Hampshire (PSNH), Western Massachusetts Electric Company (WMECO), Yankee Energy System, Inc., North Atlantic Energy Corporation, Select Energy, Inc. (Select Energy), Northeast Generation Company, Northeast Generation Services Company, and Select Energy Services, Inc.
During 2003, pre-tax pension income for CL&P declined $21.5 million, from a credit of $50.6 million in 2002 to a credit of $29.1 million in 2003. Of the $29.1 million and $50.6 million of pension credits recorded during 2003 and 2002, $14 million and $29.8 million, respectively, were recognized in the consolidated statements of income as reductions to operating expenses. The remaining $15.1 million in 2003 and $20.8 million in 2002 relate to employees working on capital projects and were reflected as reductions to capital expenditures. The pre-tax $15.8 million decrease in pension income that reduces operating expenses was reflected evenly throughout 2003, resulting in a decline of $2.4 million in net income per quarter during 2003.
CL&P's revenues for 2003 increased to $2.7 billion from $2.5 billion in 2002 due to both an increase in electric sales and the collection of incremental locational marginal pricing (LMP) costs.
As a result of an adjustment to estimated unbilled revenues resulting from a process to validate and update the assumptions used to estimate unbilled revenues, 2003 CL&P retail sales increased 3.3 percent compared to 2002. Absent that adjustment, CL&P retail sales increased 1.5 percent. The adjustment to CL&P's estimated unbilled revenues increased CL&P's net income by $7.2 million for 2003. For further information regarding the estimate of unbilled revenues, see "Critical Accounting Policies and Estimates - Unbilled Revenues," included in this Management's Discussion and Analysis.
FUTURE OUTLOOK
Management projects CL&P earnings to increase in 2004, compared with 2003.
CL&P is expected to benefit from higher overall transmission and
distribution rates, the implementation of a 0.50 mill per kilowatt-hour
(kWh) procurement fee on transitional standard offer (TSO) purchases made
by CL&P on behalf of retail customers, and higher plant balances on which
CL&P can earn a return. Those factors will be partially offset by a lower
authorized return on equity (ROE) on CL&P's distribution assets, higher
levels of depreciation, and lower pension income. In 2004, CL&P is
projecting to record pre-tax pension income of $13.5 million as compared to
pension income of $29.1 million in 2003. Pension income is annually
adjusted during the second quarter based on updated actuarial valuations,
and the 2004 estimate may change. CL&P's transmission earnings will be
affected by the outcome of a transmission rate case that was filed at the
Federal Energy Regulatory Commission (FERC) in 2003 and is expected to be
decided in late 2004. A $23.7 million annual increase, most of which
affects CL&P, went into effect October 28, 2003, subject to refund.
LIQUIDITY
CL&P's net cash flows provided by operating activities totaled $409 million
in 2003 as compared to $384.7 million in 2002 and $9 million in 2001. Cash
flows provided by operating activities in 2003 increased due to increase in
regulatory overrecoveries in 2003 as compared to 2002, primarily associated
with CL&P's Competitive Transition Assessment (CTA), Generation Service
Charge (GSC) and System Benefits Charge (SBC). The increases were offset
by restricted cash deposited into an escrow account related to the
collection of LMP costs as well as decreases in working capital items,
primarily accounts payable. Accounts payable decreased due to the timing
of payments on amounts outstanding. For a description of the costs
recovered through the CTA, GSC and SBC, see Note 1G, "Summary of
Significant Accounting Policies - Regulatory Accounting," to the
consolidated financial statements.
Cash flows provided by operating activities increased in 2002 primarily due to changes in working capital, primarily receivables and unbilled revenues and accounts payable, partially offset by the decrease in net income in 2002.
There was a comparable level of investing and financing activity in 2003 as compared to 2002, except for $100 million for the repurchase of common shares and $35.9 million from the sale of utility plant, both in 2002. The level of common dividends totaled $60.1 million in 2003, 2002 and 2001.
There was a lower level of investing and financing activities in 2002 as compared to 2001, primarily due to the issuance of rate reduction certificates and the buyout and buydown of independent power producer contracts in 2001.
Aside from the rate reduction bonds outstanding, no CL&P debt issues mature during the eight-year period of 2004 through 2011.
By the end of 2003, CL&P had completed the first stage of a comprehensive restructuring of its business profile. For CL&P that marked the sale of all electric generation in the period of 1999 through 2002 and the recovery of almost all of its unsecuritized stranded costs. The sale of assets and recovery of stranded costs have provided CL&P with extremely strong cash flows over the past five years. Those proceeds allowed CL&P to repay more than half of its debt and preferred securities and to return hundreds of millions of dollars of equity capital to NU. Aided by relatively low cost power supply contracts from 2000 through 2003, CL&P was able to maintain retail rates that were relatively low for New England and generally 10 percent below those charged by CL&P in 1996.
The year 2004, however, will show a significant change in CL&P's financial statements, even if net income remains relatively stable. The settlement of the dispute between CL&P and its standard offer service suppliers over a portion of the incremental costs incurred following the implementation of standard market design (SMD) on March 1, 2003, will have a significant negative impact on CL&P's cash flows in 2004 as compared to 2003. In 2003, CL&P was withholding payment of a portion of the incremental SMD costs from suppliers pending resolution but was recovering the costs from ratepayers at the same time. Through January 31, 2004, CL&P collected approximately $155 million from customers. Of this amount, $31.1 million was used in CL&P's operating cash flows and is secured by a surety bond. The remaining $124 million was deposited into an escrow account, and escrow account deposits through December 31, 2003 were $93.6 million and are included in restricted cash - LMP costs on the accompanying consolidated balance sheets. As a result of the settlement, CL&P will pay approximately $83 million to suppliers and return the remainder to its customers.
Another significant negative impact to CL&P's cash flows will be the refund of previously overcollected stranded costs to CL&P's customers. The Connecticut Department of Public Utility Control (DPUC) stated in CL&P's TSO docket that CL&P should either refund $262 million of overcollections back to customers or use these overcollections to pay for cash expenses over the next four years, beginning in 2004.
These refunds or applications of past cash collections to future expenses, combined with CL&P's capital expansion program, will require CL&P to issue debt securities and receive equity infusions from NU parent over the next several years. CL&P is expected to issue up to $250 million of first mortgage bonds in 2004.
CL&P will continue to increase its distribution and transmission construction program to meet Connecticut's electric service reliability needs. CL&P projects capital spending of approximately $440 million in 2004, compared with $314.6 million in 2003, $239.6 million in 2002 and $236.2 million in 2001. Over time, the capital program will add to CL&P's asset base and net income.
Under FERC policy, transmission owners cannot bill customers for new plant until it enters service. However, transmission owners may capitalize debt and equity costs during the construction period through an allowance for funds used during construction (AFUDC). Debt costs capitalized offset interest expense with no impact on net income, while equity costs capitalized increase net income. CL&P expects to fund its construction expenditures with approximately 45 percent equity and 55 percent debt. As a result of the size of the projects and the duration of the construction, a growing level of CL&P's earnings over the next four years is expected to be in the form of equity-related AFUDC. While the return on and recovery of the capitalized debt and equity AFUDC benefits earnings and cash flows after the projects enter service, AFUDC has no positive effect on cash flows until the projects are reflected in rates.
In November 2003, CL&P renewed a $300 million credit line under terms similar to the previous arrangement that expired in November 2003. CL&P can borrow up to $150 million under this credit line. There were no borrowings outstanding on this credit line at December 31, 2003.
In addition to its revolving credit line, CL&P has an arrangement with a financial institution under which CL&P can sell up to $100 million of accounts receivable. At December 31, 2003 and 2002, CL&P had sold accounts receivable of $80 million and $40 million, respectively, to that financial institution. For more information on the sale of receivables, see "Off- Balance Sheet Arrangements" in this Management's Discussion and Analysis and Note 1N, "Summary of Significant Accounting Policies - Sale of Customer Receivables," to the consolidated financial statements.
In November 2003, CL&P received approval from its preferred shareholders for an extension of a 10-year waiver that allows CL&P's unsecured debt to rise to 20 percent of total capitalization. CL&P preferred shareholders approved a similar waiver in 1993 that will expire in March 2004. The approval waives a requirement that unsecured debt represent no more than 10 percent of total capitalization.
Rate reduction bonds are included on the consolidated balance sheets of CL&P, even though the debt is non-recourse to CL&P. At December 31, 2003, CL&P had a total of $1.1 billion in rate reduction bonds outstanding, compared with $1.2 billion outstanding at December 31, 2002. All outstanding rate reduction bonds of CL&P are scheduled to amortize by December 30, 2010. Interest on the bonds totaled $70.3 million in 2003, compared with $75.7 million in 2002 and $60.6 million in 2001, the year of issuance. Cash flows from the amortization of rate reduction bonds totaled $103.3 million in 2003, compared with $96.5 million in 2002 and $68 million in 2001. Over the next several years, retirement of rate reduction bonds will increase, and interest payments will steadily decrease, resulting in no material changes to debt service costs on the existing issues. CL&P fully recovers the amortization and interest payments from customers through stranded cost revenues each year, and the bonds have no impact on net income. Moreover, as the rate reduction bonds are non-recourse, the three rating agencies that rate the debt of CL&P do not reflect the revenues, expenses, or outstanding securities related to the rate reduction bonds in establishing the credit ratings of CL&P.
The retirement of rate reduction bonds does not equal the amortization of rate reduction bonds because the retirement represents principal payments, while the amortization represents amounts recovered from customers for future principal payments. The timing of recovery does not exactly match the expected principal payments.
IMPACTS OF STANDARD MARKET DESIGN
On March 1, 2003, the New England Independent System Operator (ISO-NE)
implemented SMD. As part of SMD, LMP is utilized to assign value and
causation to transmission congestion and line losses. Transmission
congestion costs represent the additional costs incurred due to the need to
run uneconomic generating units in certain areas that have transmission
constraints, which prevent these areas from obtaining alternative lower-
cost generation. Line losses represent losses of electricity as it is sent
over transmission lines. The costs associated with transmission congestion
and line losses are now assigned to the pricing zone in which they occur,
and the calculation of line losses is now based on an economic formula.
Prior to March 1, 2003, those costs were spread across virtually all New
England electric customers based on engineering data of actual line losses
experienced. As part of the implementation of SMD, ISO-NE established
eight separate pricing zones in New England: three in Massachusetts and one
in each of the five other New England states. The three components of the
LMP for each zone are 1) an energy cost, 2) congestion costs and 3) line
loss charges assigned to the zone. LMP is increasing costs in zones that
have inadequate or less cost-efficient generation and/or transmission
constraints, such as Connecticut, and decreasing costs in zones that have
sufficient or excess generation, such as Maine.
CL&P was billed $186 million of incremental LMP costs by its standard offer service suppliers or by ISO-NE. CL&P recovered a portion of these costs through an additional charge on customer bills beginning on May 1, 2003. Billings were on a two-month lag and were recorded as operating revenues when billed. Amounts were recovered subject to refund.
CL&P and its suppliers, including affiliate Select Energy, disputed the responsibility for the $186 million of incremental LMP costs incurred. CL&P recorded an after-tax loss in 2003 of $1.3 million related to the settlement of this dispute. A settlement agreement was reached among all parties involved. This settlement agreement was filed with the FERC on March 3, 2004 and will not be final until the FERC approves it. Management expects to receive FERC approval in the first half of 2004.
NRG ENERGY, INC. EXPOSURES
CL&P entered into various transactions with subsidiaries of NRG Energy,
Inc. (NRG). On May 14, 2003, NRG and certain of its subsidiaries filed
voluntary bankruptcy petitions in the United States Bankruptcy Court for
the Southern District of New York. On December 5, 2003, NRG emerged from
bankruptcy. NRG-related exposures to CL&P as a result of these
transactions are as follows:
Standard Offer Service Contract: NRG Power Marketing, Inc. (NRG-PMI) contracted with CL&P to supply 45 percent of CL&P's standard offer service load through December 31, 2003. In May 2003, NRG-PMI attempted to terminate the contract with CL&P, but the FERC ordered NRG-PMI to continue serving CL&P under its standard offer service contract. Subsequently, NRG- PMI received a temporary restraining order from the United States District Court for the Southern District of New York (District Court) and stopped serving CL&P with standard offer supply on June 12, 2003. NRG-PMI was ultimately ordered by the FERC and the District Court to resume serving CL&P's standard offer service load and did so on July 2, 2003. During the period NRG-PMI did not serve CL&P under its standard offer service contract, CL&P's net replacement power cost amounted to $8.5 million, which was collected by CL&P from its customers and withheld from standard offer service contract payments to NRG-PMI.
On November 4, 2003, CL&P, NRG, the NRG Creditors' Committee, the DPUC, the Office of Consumer Counsel, and the attorney general of Connecticut entered into a comprehensive settlement agreement. Under the settlement agreement, approved by the bankruptcy court and the FERC on November 21, 2003 and December 18, 2003, respectively, NRG was required to continue to deliver power to CL&P under the terms and conditions of the standard offer service contract through the end of its term, which was December 31, 2003, in exchange for a commitment by CL&P to make payments to NRG on a revised weekly schedule. The settlement agreement also allowed CL&P to retain the aforementioned $8.5 million withheld from NRG for replacement power purchased by CL&P during the period June 12, 2003 through July 2, 2003. CL&P will seek to refund this amount to its customers in 2004 pending DPUC approval. On January 19, 2004, CL&P paid NRG-PMI its last weekly payment.
Pre-March 1, 2003 Congestion Charges: In November 2001, CL&P filed suit against NRG in Connecticut Superior Court seeking judgment for unpaid pre- March 1, 2003 congestion charges under its standard offer supply contract. On August 5, 2002, CL&P withheld the then unpaid congestion charges from payments due to NRG for standard offer service and continued to withhold those amounts through December 31, 2003, the end of the contract term. The total amount of congestion costs withheld from NRG was $28.4 million. If it is ultimately concluded that CL&P is responsible for pre-March 1, 2003 congestion costs, then management believes that CL&P would be allowed to recover these costs from its customers. This litigation is ongoing.
Station Service: Since December 1999, CL&P has provided NRG's Connecticut generating plants with station service, which includes energy and/or delivery services provided when a generator is off-line or unable to satisfy its station service energy requirements. Pursuant to the parties' interconnection agreement dated July 1, 1999, CL&P provides this service at DPUC-approved retail rates. In October 2002, CL&P filed a complaint with 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 and delivery services. The FERC issued a decision on December 20, 2002 that agreed that station service from CL&P would be subject to CL&P's applicable retail rates and that states have jurisdiction over the delivery of power to end users even where, as with station service, power is not delivered by distribution facilities. NRG disputed its obligation and refused to pay CL&P.
In September 2003, the bankruptcy court approved a stipulation between CL&P and NRG to submit the station service dispute to arbitration, and arbitration proceedings have been initiated by the parties. No hearing dates have been scheduled. On December 17, 2003, the DPUC determined that CL&P had appropriately administered its station service rates in providing NRG station service. In unrelated proceedings, the FERC has issued decisions with conflicting policy direction. In January 2004, CL&P filed a request with the FERC for further clarification of this issue.
Management will continue to pursue recovery from NRG of the station service balance, including approximately $4 million NRG placed in an escrow account related to this matter. In 2003, as a result of NRG's bankruptcy, the amount due from NRG in excess of the escrow amount was reserved. Management believes that amounts not collected from NRG are ultimately recoverable from CL&P's customers. Therefore, a regulatory asset of $11.4 million was recorded. At December 31, 2003, NRG owed CL&P $16 million for station service. The $16 million owed to CL&P includes $0.6 million billed to NRG subsequent to its emergence from bankruptcy on December 5, 2003.
Legal Costs: Through December 31, 2003, legal costs incurred by CL&P related to NRG's bankruptcy and the SMD dispute amounted to $2.3 million. This amount has been recorded as a regulatory asset, and CL&P received approval to recover $1.6 million in its recent rate case. CL&P will continue to defer these legal costs as they are incurred, and management believes that amounts in excess of $1.6 million will also be recovered from customers.
Meriden Gas Turbines, LLC: CL&P is involved in ongoing litigation with Meriden Gas Turbines, LLC (MGT), an NRG subsidiary that was not included in NRG's voluntary bankruptcy proceeding, related to the construction of a generating plant which MGT stated it was abandoning.
MGT currently owes CL&P $0.5 million for work on the South Kensington switching station, which was to be the interconnection point for the MGT generating plant. CL&P has joined pending foreclosure proceedings in an effort to recover the outstanding balance.
Management does not expect that the resolution of the aforementioned NRG exposures will have a material adverse effect on the financial condition or results of operations of CL&P.
BUSINESS DEVELOPMENT AND CAPITAL EXPENDITURES
Over the next several years, CL&P's capital spending will be significant.
CL&P is seeking to upgrade and expand an aging and, in some locations,
stressed distribution and transmission system. CL&P's capital
expenditures totaled $314.6 million in 2003, compared with $239.6 million
in 2002 and $236.2 million in 2001. CL&P expects capital expenditures to
increase to $440 million in 2004. CL&P spent $246 million on distribution
in 2003 and anticipates spending $228 million on distribution in 2004.
In its final 2003 CL&P rate decision, the DPUC authorized rate recovery of distribution capital expenditures totaling $236 million in 2004, $220 million in 2005, $216 million in 2006, and $225 million in 2007.
On July 14, 2003, the Connecticut Siting Council (CSC) approved a 345,000 volt transmission line project from Bethel, Connecticut to Norwalk, Connecticut, proposed in October 2001 by CL&P. The configuration of the new transmission line, enhancements to an existing 115,000 volt transmission line, and work in related substations are estimated to cost approximately $200 million. The line will alleviate identified reliability issues in southwest Connecticut and help reduce congestion costs for all of Connecticut. An appeal of the CSC decision by the City of Norwalk is pending, but management does not expect the appeal to be successful. CL&P anticipates placing the new transmission line in service by the end of 2005. This project is exempt from the State of Connecticut's moratorium on the approval of new electric and natural gas transmission projects. At December 31, 2003, CL&P has capitalized $12.4 million associated with this project.
On October 9, 2003, CL&P and United Illuminating (UI) filed for approval of a separate 345,000 volt transmission line from Norwalk, Connecticut to Middletown, Connecticut. Estimated construction costs of this project are approximately $620 million. CL&P will jointly site this project with UI, and CL&P will own 80 percent, or approximately $496 million, of the project. This project is also exempt from the State of Connecticut's moratorium on the approval of new electric and natural gas transmission projects. CL&P expects the CSC to rule on the application in 2004 and for construction to occur from 2005 through 2007. At December 31, 2003, CL&P has capitalized $9.2 million related to this project.
In September 2002, the CSC approved a plan to replace an undersea electric transmission line between Norwalk, Connecticut and Northport - Long Island, New York, at an estimated cost of $90 million. CL&P and the Long Island Power Authority each own approximately 50 percent of the line. The project still requires federal and New York state approvals. Given the approval process, changing pricing and operational rules in the New England and New York energy markets and pending business issues between the parties, the expected in-service date remains under evaluation. This project is also exempt from the State of Connecticut's moratorium on the approval of new electric and natural gas transmission projects. At December 31, 2003, CL&P has capitalized $5.2 million associated with this project.
Construction of these three projects would significantly enhance CL&P's ability to provide reliable electric service to the rapidly growing energy market in southwestern Connecticut. Despite the need for such facilities, significant opposition has been raised. As a result, management cannot be certain as to the expected in-service dates or the ultimate cost of these projects. Should the plans proceed, applicable law provides that CL&P will be able to recover its operating cost and carrying costs through federally- approved transmission tariffs.
Management believes that construction of the 345,000 volt projects is critical to maintaining service reliability in southwest Connecticut. The 345,000 volt projects, in addition to additional transmission spending planned between 2004 and 2007, also represent a significant source of potential earnings growth for NU. Management believes that if the projects now being considered are all built over the next four years, CL&P's net transmission plant investment would triple. Revenues and earnings for CL&P's transmission system are established by the FERC.
REGIONAL TRANSMISSION ORGANIZATION
The FERC has required all transmission owning utilities, including CL&P, to
voluntarily form regional transmission organizations (RTOs) or to state why
this process has not begun.
On October 31, 2003, ISO-NE, along with NU (including CL&P), and six other New England transmission companies filed a proposal with the FERC to create a RTO for New England. The RTO is intended to strengthen the independent and efficient management of the region's power system while ensuring that customers in New England continue to have the most reliable system possible to realize the benefits of a competitive wholesale energy market.
ISO-NE, as a RTO, will have a new independent governance structure and will also become the transmission provider for New England by exercising operational control over New England's transmission facilities pursuant to a detailed contractual arrangement with the New England transmission owners. Under this contractual arrangement, the RTO will have clear authority to direct the transmission owners to operate their facilities in a manner that preserves system reliability, including requiring transmission owners to expand existing transmission lines or build new ones when needed for reliability. Transmission owners will retain their rights over revenue requirements, rates and rate designs. The filing requests that the FERC approve the RTO arrangements for an effective date of March 1, 2004.
In a separate filing made on November 4, 2003, NU including CL&P, along with six other New England transmission owners requested, consistent with the FERC's pricing policy for RTOs and Order-2000-compliant independent system operators, that the FERC approve a single ROE for regional and local rates that would consist of a base ROE as well as incentive adders of 50 basis points for joining a RTO and 100 basis points for constructing new transmission facilities approved by the RTO. If the FERC approves the request, then the transmission owners would receive a 13.3 percent ROE for existing transmission facilities and a 14.3 percent ROE for new transmission facilities. The outcome of this request and its impact on CL&P cannot be determined at this time.
RESTRUCTURING AND RATE MATTERS
On August 26, 2003, NU's electric operating companies, including CL&P,
filed their first transmission rate case at the FERC since 1995. In the
filing, NU requested implementation of a formula rate that would allow
recovery of increasing transmission expenditures on a timelier basis and
that the changes, including a $23.7 million annual rate increase through
2004, take effect on October 27, 2003. NU requested that the FERC maintain
NU's existing 11.75 percent ROE until a ROE for the New England RTO is
established by the FERC. On October 22, 2003, the FERC accepted this
filing implementing the proposed rates subject to refund effective on
October 28, 2003. A final decision in the rate case is expected in 2004.
Increasing transmission rates are generally recovered from distribution companies through FERC-approved transmission rates. Electric distribution companies pass through higher transmission rates to retail customers as approved by the DPUC. In its 2003 rate case, CL&P sought a tracking mechanism to allow it to recover changes in transmission expenses on a timely basis. While the DPUC approved a $28.4 million increase in transmission rates for CL&P's retail customers effective January 1, 2004, it did not grant a tracking mechanism in rates. As a result, CL&P will need to reapply to the DPUC to adjust transmission rates when its revenues are not adequate to recover transmission costs.
Public Act No. 03-135 and Rate Proceedings: On June 25, 2003, the Governor of Connecticut signed into law Public Act No. 03-135 (Act) that amended Connecticut's 1998 electric utility industry legislation. Among key features, the Act created a TSO period from 2004 through 2006 that allowed the base rate cap to return to 1996 levels, which represented a potential increase of up to 11.1 percent. Additional costs related to Federally Mandated Congestion Charges (FMCC) are not included in the cap. Additionally, if energy supply costs were to exceed levels established in the TSO rate, these costs could be recovered through an energy adjustment clause or through the FMCC. The Act also allowed CL&P to collect a procurement fee of at least 0.50 mills per kWh from customers who continue to purchase TSO service. That fee can increase to 0.75 mills if CL&P beats certain regional benchmarks. Management expects that the procurement fee will be between $11 million and $12 million annually, which will add $6 million to $7 million to CL&P's net income. One mill is equal to one-tenth of a cent.
ISO-NE and the New England Power Pool are currently debating the implementation of locational installed capacity (LICAP). LICAP is the requirement 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 its lack of sufficient generation and transmission, is expected to have high LICAP costs. LICAP rules are subject to the jurisdiction of the FERC. ISO-NE filed a proposal with the FERC on March 1, 2004 for implementation in June 2004. Until the exact proposal is approved by the FERC, the financial impact on CL&P's customers cannot be determined. CL&P expects to recover LICAP from its customers as a FMCC.
On July 1, 2003, CL&P filed with the DPUC to establish TSO service and to set the TSO rates equal to December 31, 1996 total rate levels. On December 19, 2003, the DPUC issued a final decision setting the average TSO rate at $0.1076 per kWh for 2004, which the DPUC found to be within the statutory cap. That rate incorporated nine key elements, which combined produced the average TSO rate. The most significant element was an average GSC of $0.05744 per kWh. That charge will allow CL&P to fully recover from customers the amounts to be paid in 2004 to its five TSO suppliers. These suppliers include Select Energy, which was awarded 37.5 percent of CL&P's TSO load through a request for proposal process overseen by the DPUC, and four other suppliers, all of which are investment grade rated by major rating agencies.
The Act also required CL&P to file a four-year transmission and distribution plan with the DPUC. Accordingly, on August 1, 2003, CL&P filed a rate case that amended rate schedules and proposed changes to increase distribution rates. On December 19, 2003, the DPUC issued its final decision in the rate case. In that decision, the DPUC chose to apply $120 million of overcollections from CL&P's customers in prior years against higher distribution rates in the form of credits of $30 million per year. Net of those overcollections, the DPUC ordered that distribution rates be lowered by $1.9 million in 2004 and be raised by $25.1 million in 2005, $11.9 million in 2006, and $7 million in 2007. The decision approved a transmission rate increase of $28.4 million in 2004, but did not allow the tracking mechanism and did not set transmission rates beyond 2004. The DPUC also approved rate recovery of approximately $900 million of CL&P's proposed $1 billion distribution capital budget over the four-year period. The decision set CL&P's authorized ROE at 9.85 percent. Earnings above 9.85 percent will be shared equally by shareholders and ratepayers. The sharing mechanism is not affected by earnings from the procurement fee.
CL&P filed a petition for reconsideration of certain items in the rate case on December 31, 2003. Other parties also filed petitions for reconsideration. On January 21, 2004, the DPUC agreed to reconsider CL&P's items; however, CL&P also filed an appeal with the Connecticut Superior Court on January 30, 2004, which was within the time frame required by law. The appeal was filed in the event that the DPUC's reconsideration is still not acceptable to CL&P.
Disposition of Seabrook Proceeds: CL&P sold its share of the Seabrook nuclear unit on November 1, 2002. The net proceeds in excess of the book value of Seabrook of $16 million were recorded as a regulatory liability and, after being offset by accelerated decommissioning funding and other adjustments, will be refunded to customers. On May 1, 2003, CL&P filed its application with the DPUC for approval of the disposition of the proceeds from the sale. This filing described CL&P's treatment of its share of the proceeds from the sale. Hearings in this docket were held in September 2003, and a draft decision was received on February 3, 2004. The final decision, which was received on March 3, 2004 did not have a material effect on CL&P's net income or financial position.
CTA and SBC Reconciliation Filing: On April 3, 2003, CL&P filed its annual CTA and SBC reconciliation with the DPUC. For the year ended December 31, 2002, total CTA revenues and excess GSC revenues exceeded the CTA revenue requirement by $93.5 million. This amount was recorded as a regulatory liability. For the same period, SBC revenues exceeded the SBC revenue requirement by $22.4 million. In compliance with a prior decision of the DPUC, a portion of the SBC overcollection reduced regulatory assets, and the remaining overcollection of $18.6 million was applied to the CTA. The DPUC's December 19, 2003 TSO decision addressed $41 million of SBC overcollections and $64 million of CTA overcollections that had been estimated as of December 31, 2003. In its decision, the DPUC ordered that $80 million of the overcollections be used to reduce CTA costs during the 2004 through 2006 TSO period. The DPUC also ordered that $25 million of the overcollections be used to offset SBC costs during the TSO period. The DPUC also ordered that $37 million of GSC overcollections be used to pay CL&P's 0.50 mill per kWh procurement fee during the TSO period.
NUCLEAR GENERATION ASSET DIVESTITURES
Millstone: On March 31, 2001, CL&P sold its ownership interest in
Millstone.
Seabrook: On November 1, 2002, CL&P sold its ownership interest in Seabrook.
Vermont Yankee: On July 31, 2002, Vermont Yankee Nuclear Power Corporation (VYNPC) consummated the sale of its nuclear generating unit. In November 2003, CL&P sold back to VYNPC its shares of stock for approximately $0.9 million. CL&P continues to purchase approximately 9.5 percent of the plant's output under a new contract.
Nuclear Decommissioning and Plant Closure Costs: Although the purchasers of CL&P's ownership shares of the Millstone, Seabrook and Vermont Yankee plants assumed the obligation of decommissioning those plants, CL&P still has significant decommissioning and plant closure cost obligations to the companies that own the Yankee Atomic, Connecticut Yankee (CY) and Maine Yankee plants (collectively Yankee Companies). Each plant has been shut down and is undergoing decommissioning. The Yankee Companies collect decommissioning and closure costs through wholesale FERC-approved rates charged under a power purchase agreement with CL&P. CL&P in turn passes these costs on to its customers through state regulatory commission- approved retail rates. A portion of the decommissioning and closure costs have already been collected, but a substantial portion related to the decommissioning of CY has not yet been filed at and approved for collection by the FERC. The cost estimate for CY that has not yet been approved for recovery by FERC at December 31, 2003 is $181.9 million.
CL&P cannot at this time predict the timing or outcome of the FERC proceeding required for the collection of these remaining decommissioning and closure costs or the Bechtel Power Corporation litigation referred to in Note 6G, "Commitments and Contingencies - Nuclear Decommissioning and Plant Closure Costs," to the consolidated financial statements. Although management believes that these costs will ultimately be recovered from CL&P's customers, 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 FERC does not allow these costs to be recovered in wholesale rates, CL&P would expect the state regulatory commissions to disallow these costs in retail rates as well.
OFF-BALANCE SHEET ARRANGEMENTS
The CL&P Receivables Corporation (CRC) was incorporated on September 5,
1997, and is a wholly owned subsidiary of CL&P. CRC has an arrangement
with a highly rated financial institution under which CRC can sell up to
$100 million of accounts receivable. At December 31, 2003 and 2002, CRC
had sold accounts receivable of $80 million and $40 million, respectively,
to that financial institution with limited recourse.
CRC was established for the sole purpose of selling CL&P's accounts receivable and unbilled revenues and is included in the consolidation of NU's financial statements. On July 9, 2003, CRC renewed its Receivables Purchase and Sale Agreement with CL&P and the financial institution. The agreement expires on July 7, 2004. Management plans to renew this agreement prior to its expiration.
The transfer of receivables to the financial institution under this arrangement qualifies for sale treatment under Statement of Financial Accounting Standards (SFAS) No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities - A Replacement of SFAS No. 125." Accordingly, the $80 million and $40 million outstanding under this facility are not reflected as debt or included in the consolidated financial statements at December 31, 2003 and 2002, respectively.
This off-balance sheet arrangement is not significant to CL&P's liquidity or other benefits. There are no known events, demands, commitments, trends, or uncertainties that will, or are reasonably likely to, result in the termination, or material reduction in the amount available to the company under this off-balance sheet arrangement.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States of America requires
management to make estimates, assumptions and at times difficult,
subjective or complex judgments. Changes in these estimates, assumptions
and judgments, in and of themselves, could materially impact the financial
statements of CL&P. Management communicates to and discusses with NU's
Audit Committee of the Board of Trustees all critical accounting policies
and estimates. The following are the accounting policies and estimates
that management believes are the most critical in nature.
Presentation: In accordance with current accounting pronouncements, CL&P's consolidated financial statements include all subsidiaries upon which control is maintained and all variable interest entities for which CL&P is the primary beneficiary, as defined. All intercompany transactions between these subsidiaries are eliminated as part of the consolidation process.
CL&P has less than 50 percent ownership interests in the Connecticut Yankee Atomic Power Company, Yankee Atomic Electric Company and Maine Yankee Atomic Power Company. CL&P does not control these companies and does not consolidate them in its financial statements. CL&P accounts for the investments in these companies using the equity method. Under the equity method, CL&P records its ownership share of the earnings or losses at these companies. Determining whether or not CL&P should apply the equity method of accounting for an investee company requires management judgment.
The required adoption date of Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 46, "Consolidation of Variable Interest Entities" was delayed from July 1, 2003 to December 31, 2003 for CL&P. However, CL&P elected to adopt FIN 46 at the original adoption date. The adoption of FIN 46 had no impact on CL&P. In December 2003, the FASB issued a revised version of FIN 46 (FIN 46R). FIN 46R is effective for CL&P for the first quarter of 2004, but is not expected to have an impact on CL&P's consolidated financial statements.
Revenue Recognition: CL&P retail revenues are based on rates approved by the DPUC. These regulated rates are applied to customers' use of energy to calculate a bill. In general, rates can only be changed through formal proceedings with the DPUC.
CL&P utilizes regulatory commission-approved tracking mechanisms to track the recovery of certain incurred costs. The tracking mechanisms allow for rates to be changed periodically, with overcollections refunded to customers or underrecollections collected from customers in future periods.
The determination of the energy sales to individual customers is based on the reading of meters, which occurs on a systematic basis throughout the month. Billed revenues are based on these meter readings. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated, and an estimated amount of unbilled revenues is recorded.
Wholesale transmission revenues are based on rates and formulas that are approved by the FERC. Most of CL&P's wholesale transmission revenues are collected through a combination of the New England Regional Network Service (RNS) tariff and CL&P's Local Network Service (LNS) tariff. The RNS tariff, which is administered by ISO-NE, recovers the revenue requirements associated with transmission facilities that are deemed by the FERC to be Pool Transmission Facilities. The LNS tariff which was accepted by the FERC on October 22, 2003, provides for the recovery of CL&P's total transmission revenue requirements, net of revenue credits received from various rate components, including revenues received under the RNS rates.
Unbilled Revenues: Unbilled revenues represent an estimate of electricity delivered to customers that has not been billed. Unbilled revenues represent assets on the balance sheet that become accounts receivable in the following month as customers are billed.
The estimate of unbilled revenues is sensitive to numerous factors that can significantly impact the amount of revenues recorded. Estimating the impact of these factors is complex and requires management's judgment. The estimate of unbilled revenues is important to CL&P's consolidated financial statements as adjustments to that estimate could significantly impact operating revenues and earnings. Two potential methods for estimating unbilled revenues are the requirements and the cycle method.
CL&P estimates unbilled revenues monthly using the requirements method. The requirements method utilizes the total monthly volume of electricity delivered to the system and applies a delivery efficiency (DE) factor to reduce the total monthly volume by an estimate of delivery losses in order to calculate total estimated monthly sales to customers. The total estimated monthly sales amount less total monthly billed sales amount results in a monthly estimate of unbilled sales. Unbilled revenues are estimated by applying an average rate to the estimate of unbilled sales.
Differences between the actual DE factor and the estimated DE factor can have a significant impact on estimated unbilled revenue amounts.
In 2003, the unbilled sales estimates for CL&P were tested using the cycle method. The cycle method uses the billed sales from each meter reading cycle and an estimate of unbilled days in each month based on the meter reading schedule. The cycle method is historically more accurate than the requirements method when used in a mostly weather-neutral month. The cycle method resulted in adjustments to the estimate of unbilled revenues that had a positive after-tax earnings impact on CL&P of $7.2 million in 2003.
The testing of the requirements method with the cycle method will be done on at least an annual basis using a weather-neutral month.
Derivative Accounting: Effective January 1, 2001, CL&P adopted SFAS No. 133, as amended.
Many CL&P contracts for the purchase or sale of energy or energy-related products are derivatives. The application of derivative accounting under SFAS No. 133, as amended, is complex and requires management judgment in the following respects: identification of derivatives and embedded derivatives, election, and designation of the normal purchases and sales exception, and determining the fair value of derivatives. All of these judgments, depending upon their timing and effect, can have a significant impact on CL&P's consolidated balance sheets.
In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities," which amended existing derivative accounting guidance. This new statement incorporates interpretations that were included in previous Derivative Implementation Group (DIG) guidance, clarifies certain conditions, and amends other existing pronouncements. It was effective for contracts entered into or modified after June 30, 2003. Management has determined that the adoption of SFAS No. 149 had no impact on the accounting for CL&P contracts.
On June 25, 2003, the DIG cleared Issue No. C-20, which addressed the meaning of "not clearly and closely related regarding contracts with a price adjustment feature" as it relates to the election of the normal purchase and sales exception to derivative accounting. The implementation of this guidance was required for the fourth quarter of 2003 for CL&P. The implementation of Issue No. C-20 resulted in CL&P recording the fair value of two existing power purchase contracts as derivatives, one as a derivative asset, and one as a derivative liability. An offsetting regulatory liability and an offsetting regulatory asset were recorded, as these contracts are part of stranded costs, and management believes that these costs will continue to be recovered or refunded in rates. The fair values of these long-term power purchase contracts include a derivative asset with a fair value of $112.4 million and a derivative liability with a fair value of $54.6 million at December 31, 2003.
CL&P holds financial transmission rights (FTR) contracts to mitigate the risk associated with the congestion price differences associated with LMP in New England. FTR contracts held by CL&P were recorded at a fair value of $3 million. Management believes the amount to be paid for the FTR contracts best represents their fair value. If new markets for these contracts develop, then there may be an impact on CL&P's consolidated financial statements in future periods.
Regulatory Accounting: The accounting policies of CL&P historically reflect the effects of the rate-making process in accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." The transmission and distribution businesses of CL&P continue to be cost-of- service rate regulated, and management believes the application of SFAS No. 71 to that portion of those businesses continues to be appropriate. Management must reaffirm this conclusion at each balance sheet date. If, as a result of a change in circumstances, it is determined that any portion of CL&P no longer meets the criteria of regulatory accounting under SFAS No. 71, that portion of the company will have to discontinue regulatory accounting and write-off their regulatory assets and liabilities. Such a write-off could have a material impact on CL&P's consolidated financial statements.
The application of SFAS No. 71 results in recording regulatory assets and liabilities. Regulatory assets represent the deferral of incurred costs that are probable of future recovery in customer rates. In some cases, CL&P records regulatory assets before approval for recovery has been received from the applicable regulatory commission. Management must use judgment to conclude that costs deferred as regulatory assets are probable of future recovery. Management bases its conclusion on certain factors, including changes in the regulatory environment, recent rate orders issued by the DPUC and the status of any potential new legislation. Regulatory liabilities represent revenues received from customers to fund expected costs that have not yet been incurred or probable future refunds to customers.
Management uses its best judgment when recording regulatory assets and liabilities; however, the DPUC can reach different conclusions about the recovery of costs, and those conclusions could have a material impact on CL&P's consolidated financial statements. Management believes it is probable that CL&P will recover the regulatory assets that have been recorded.
Pension and Postretirement Benefits Other Than Pensions (PBOP): CL&P participates in a uniform noncontributory defined benefit retirement plan (Pension Plan) covering substantially all regular CL&P employees. CL&P also participates in a postretirement benefit plan (PBOP Plan) to provide certain health care benefits, primarily medical and dental, and life insurance benefits through a benefit plan to retired employees. For each of these plans, the development of the benefit obligation, fair value of plan assets, funded status and net periodic benefit credit or cost is based on several significant assumptions. If these assumptions were changed, the resulting change in benefit obligations, fair values of plan assets, funded status and net periodic benefit credits or costs could have a material impact on CL&P's consolidated financial statements.
Results: Pre-tax periodic pension income for the Pension Plan, excluding settlements, curtailments and special termination benefits, totaled $29.1 million, $50.6 million and $61.4 million for the years ended December 31, 2003, 2002 and 2001, respectively. The pension income amounts exclude one- time items recorded under SFAS No. 88, "Employers' Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits," associated with early termination programs and the sale of the Millstone and Seabrook nuclear units. Net SFAS No. 88 items totaled $8.1 million in expense for the year ended December 31, 2002. This amount was recorded as a liability for refund to customers.
The pre-tax net PBOP Plan cost, excluding settlements, curtailments and special termination benefits, totaled $16.6 million, $17.4 million and $14.3 million for the years ended December 31, 2003, 2002 and 2001, respectively.
Long-Term Rate of Return Assumptions: In developing the expected long-term rate of return assumptions, CL&P evaluated input from actuaries, consultants and economists, as well as long-term inflation assumptions and CL&P's historical 20-year compounded return of approximately 11 percent. CL&P's expected long-term rates of return on assets is based on certain target asset allocation assumptions and expected long-term rate of return. The Pension Plan's and PBOP Plan's target asset allocation assumptions and expected long-term rates of return assumptions by asset category are as follows:
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At December 31,
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Pension Benefits Postretirement Benefits
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2003 2002 2003 2002
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Target Assumed Target Assumed Target Assumed Target Assumed
Asset Rate of Asset Rate of Asset Rate of Asset Rate of
Asset Category Allocation Return Allocation Return Allocation Return Allocation Return
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Equity securities:
United States 45.00% 9.25% 45.00% 9.75% 55.00% 9.25% 55.00% 9.75%
Non-United States 14.00% 9.25% 14.00% 9.75% 11.00% 9.25% - -
Emerging markets 3.00% 10.25% 3.00% 10.75% 2.00% 10.25% - -
Private 8.00% 14.25% 8.00% 14.75% - - - -
Debt Securities:
Fixed income 20.00% 5.50% 20.00% 6.25% 27.00% 5.50% 45.00% 6.25%
High yield fixed
income 5.00% 7.50% 5.00% 7.50% 5.00% 7.50% - -
Real estate 5.00% 7.50% 5.00% 7.50% - - - -
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The actual asset allocations at December 31, 2003 and 2002 approximated these target asset allocations. CL&P regularly reviews the actual asset allocations and periodically rebalances the investments to the targeted asset allocations when appropriate. For information regarding actual asset allocations, see Note 4, "Pension Benefits and Postretirement Benefits Other Than Pensions," to the consolidated financial statements.
CL&P reduced the long-term rate of return assumption 50 basis points from 9.25 percent to 8.75 percent in 2003 for the Pension Plan and PBOP Plan due to lower expected market returns. CL&P believes that 8.75 percent is a reasonable long-term rate of return on Pension Plan and PBOP Plan assets for 2003, and CL&P expects to use 8.75 percent in 2004. CL&P will continue to evaluate the actuarial assumptions, including the expected rate of return, at least annually, and will adjust the appropriate assumptions as necessary.
Actuarial Determination of Income and Expense: CL&P bases the actuarial determination of Pension Plan and PBOP Plan income/expense on a market- related valuation of assets, which reduces year-to-year volatility. This market-related valuation calculation recognizes investment gains or losses over a four-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the fair value of assets. Since the market-related valuation calculation recognizes gains or losses over a four-year period, the future value of the market-related assets will be impacted as previously deferred gains or losses are recognized. There will be no impact on the fair value of Pension Plan and PBOP Plan assets.
At December 31, 2003, the Pension Plan had cumulative unrecognized investment losses of $49 million, which will increase pension expense over the next four years by reducing the expected return on Pension Plan assets. At December 31, 2003, the Pension Plan also had cumulative unrecognized actuarial losses of $63.1 million, which will increase pension expense over the expected future working lifetime of active Pension Plan participants, or approximately 13 years. The combined total of unrecognized investment and actuarial losses at December 31, 2003 is $112.1 million. These losses impact the determination of pension expense and the actuarially determined prepaid pension amount recorded on the consolidated balance sheets but have no impact on expected Pension Plan funding.
At December 31, 2003, the PBOP Plan had cumulative unrecognized investment losses of $3.2 million, which will increase PBOP Plan cost over the next four years by reducing the expected return on plan assets. At December 31, 2003, the PBOP Plan also had cumulative unrecognized actuarial losses of $45.3 million, which will increase PBOP Plan expense over the expected future working lifetime of active PBOP Plan participants, or approximately 13 years. The combined total of unrecognized investment and actuarial losses at December 31, 2003 is $48.5 million. These losses impact the determination of PBOP Plan cost and the actuarially determined accrued PBOP Plan cost recorded on the consolidated balance sheets.
Discount Rate: The discount rate that is utilized in determining future pension and PBOP obligations is based on a basket of long-term bonds that receive one of the two highest ratings given by a recognized rating agency. To compensate for the Pension Plan's longer duration 25 basis points were added to the benchmark. The discount rate determined on this basis has decreased from 6.75 percent at December 31, 2002 to 6.25 percent at December 31, 2003.
Expected Pension Income: Due to the effect of the unrecognized actuarial losses and based on an expected rate of return on Pension Plan assets of 8.75 percent, a discount rate of 6.25 percent and various other assumptions, CL&P estimates that expected contributions to and pension income for the Pension Plan will be as follows (millions):
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Expected
Year Contributions Pension Income
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2004 $ - $13.5
2005 $ - $ 3.3
2006 $ - $ 0.1
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Future actual pension income/expense will depend on future investment performance, changes in future discount rates and various other factors related to the populations participating in the Pension Plan.
Sensitivity Analysis: The following represents the increase/(decrease) to the Pension Plan's reported cost and to the PBOP Plan's reported cost as a result of the change in the following assumptions by 50 basis points (in millions):
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At December 31,
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Pension Plan Postretirement Plan
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Assumption Change 2003 2002 2003 2002
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Lower long-term
rate of return $ 4.9 $ 4.9 $0.3 $0.4
Lower discount
rate $ 4.9 $ 4.4 $0.4 $0.5
Lower compensation
increase $(2.0) $(1.8) N/A N/A
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Plan Assets: The value of the Pension Plan assets has increased from $752.7 million at December 31, 2002 to $899.3 million at December 31, 2003. The investment performance returns, despite declining discount rates, have increased the overfunded status of the Pension Plan on a projected benefit obligation (PBO) basis from $72.3 million at December 31, 2002 to $168 million at December 31, 2003. The PBO includes expectations of future employee compensation increases. The accumulated benefit obligation (ABO) of the Pension Plan was approximately $253 million less than Pension Plan assets at December 31, 2003 and approximately $158 million less than Pension Plan assets at December 31, 2002. The ABO is the obligation for employee service and compensation provided through December 31, 2003. If the ABO for the entire Pension Plan exceeds all Pension Plan assets at a future plan measurement date, NU will record an additional minimum liability of which CL&P will be allocated its proportionate share. CL&P has not made employer contributions since 1991.
The value of PBOP Plan assets has increased from $50.3 million at December 31, 2002 to $64.3 million at December 31, 2003. The investment performance returns, despite declining discount rates, have decreased the underfunded status of the PBOP Plan on an accumulated projected benefit obligation basis from $116.7 million at December 31, 2002 to $105 million at December 31, 2003. CL&P has made a contribution each year equal to the PBOP Plan's postretirement benefit cost, excluding curtailments, settlements and special termination benefits.
Health Care Cost: The health care cost trend assumption used to project increases in medical costs is 9 percent for 2003, decreasing one percentage point per year to an ultimate rate of 5 percent in 2007. The effect of increasing the health care cost trend by one percentage point would have increased 2003 service and interest cost components of the PBOP Plan cost by $0.3 million in 2003 and $0.4 million in 2002.
Accounting for the Effect of Medicare Changes on PBOP: On December 8, 2003, the President signed into law a bill that expands Medicare, primarily by adding a prescription drug benefit and by adding a federal subsidy to qualifying plan sponsors of retiree health care benefit plans. Management believes that CL&P currently qualifies.
Specific authoritative accounting guidance on how to account for the effect the Medicare federal subsidy has on CL&P's PBOP Plan has not been issued by the FASB. FASB Staff Position (FSP) No. FAS 106-1, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003," required CL&P to make an election for 2003 financial reporting. The election was to either defer the impact of the subsidy until the FASB issues guidance or to reflect the impact of the subsidy on December 31, 2003 reported amounts. CL&P chose to reflect the impact on December 31, 2003 reported amounts.
Reflecting the impact of the Medicare change decreased the PBOP benefit obligation by approximately $9.4 million and increased actuarial gains by approximately $9.4 million with no impact on 2003 expenses, assets, or liabilities. The $9.4 million actuarial gain will be amortized as a reduction to PBOP expense over 13 years beginning in 2004. PBOP expense in 2004 will also reflect a lower interest cost due to the reduction in the December 31, 2003 benefit obligation. Management estimates that the reduction in PBOP expense in 2004 will be approximately $0.7 million.
When accounting guidance is issued by the FASB, it may require CL&P to change the accounting described above and change the information included in this annual report.
Income Taxes: Income tax expense is calculated each year in each of the jurisdictions in which CL&P operates. This process involves estimating CL&P's actual current tax exposures as well as assessing temporary differences resulting from differing treatment of items, such as timing of the deduction and expenses for tax and book accounting purposes. These differences result in deferred tax assets and liabilities, which are included in CL&P's consolidated balance sheets. Adjustments made to income taxes could significantly affect CL&P's consolidated financial statements. Management must also assess the likelihood that deferred tax assets will be recovered from future taxable income, and to the extent that recovery is not likely, a valuation allowance must be established. Significant management judgment is required in determining income tax expense and deferred tax assets and liabilities.
CL&P accounts for deferred taxes under SFAS No. 109, "Accounting for Income Taxes." For temporary differences recorded as deferred tax liabilities that will be recovered in rates in the future, CL&P has established a regulatory asset. The regulatory asset amounted to $140.9 million and $165 million at December 31, 2003 and 2002, respectively. Regulatory agencies in certain jurisdictions in which CL&P operates require the tax effect of specific temporary differences to be "flowed through" to utility customers. Flow through treatment means that deferred tax expense is not recorded in the consolidated statements of income. Instead, the tax effect of the temporary difference impacts both amounts for income tax expense currently included in customers' rates and the company's net income. Flow through treatment can result in effective income tax rates that are significantly different than expected income tax rates. Recording deferred taxes on flow through items is required by SFAS No. 109, and the offset to the deferred tax amounts is the regulatory asset referred to above. A reconciliation from expected tax expense at the statutory federal income tax rate to actual tax expense recorded is included in Note 12, "Income Tax Expense," to the consolidated financial statements.
The estimates that are made by management in order to record income tax expense, accrued taxes and deferred taxes are compared each year to the actual tax amounts filed on CL&P's income tax returns. The income tax returns were filed in the fall of 2003 for the 2002 tax year. In the fourth quarter, CL&P recorded differences between income tax expense, accrued taxes and deferred taxes on its consolidated financial statements and the amounts that were on its income tax returns. Recording these differences in income tax expense resulted in a positive impact of approximately $2.7 million on CL&P's 2003 earnings.
Depreciation: Depreciation expense is calculated based on an asset's useful life, and judgment is involved when estimating the useful lives of certain assets. A change in the estimated useful lives of these assets could have a material impact on CL&P's consolidated financial statements absent timely rate relief for CL&P's assets.
Accounting for Environmental Reserves: Environmental reserves are accrued using a probabilistic model approach when assessments indicate that it is probable that a liability has been incurred and an amount can be reasonably estimated. Adjustments made to environmental liabilities could have a significant effect on earnings. The probabilistic model approach estimates the liability based on the most likely action plan from a variety of available remediation options, ranging from no action to remedies ranging from establishing institutional controls to full site remediation and long- term monitoring. The probabilistic model approach estimates the liabilities associated with each possible action plan based on findings through various phases of site assessments. These estimates are based on currently available information from presently enacted state and federal environmental laws and regulations and several cost estimates from outside engineering and remediation contractors. These amounts also take into consideration prior experience in remediating contaminated sites and data released by the United States Environmental Protection Agency and other organizations.
These estimates are subjective in nature partly because there are usually several different remediation options from which to choose when working on a specific site. These estimates are subject to revisions in future periods based on actual costs or new information concerning either the level of contamination at the site or newly enacted laws and regulations. The amounts recorded as environmental liabilities on the consolidated balance sheets represent management's best estimate of the liability for environmental costs based on current site information from site assessments and remediation estimates. These liabilities are estimated on an undiscounted basis.
CL&P recovers a certain level of environmental costs currently in rates but does not have an environmental cost recovery tracking mechanism. Accordingly, changes in CL&P's environmental reserves impact CL&P's earnings.
Asset Retirement Obligations: CL&P adopted SFAS No. 143, "Accounting for Asset Retirement Obligations" on January 1, 2003. SFAS No. 143 requires that legal obligations associated with the retirement of property, plant and equipment be recorded as a liability on the balance sheet at fair value when incurred and when a reasonable estimate of the fair value can be made. SFAS No. 143 defines an asset retirement obligation (ARO) as a legal obligation that is required to be settled due to an existing or enacted law, statute, ordinance or a written or oral promise to remove an asset. AROs may stem from environmental laws, state laws and regulations, easement agreements, building codes, contracts, franchise grants and agreements, oral promises made upon which third parties have relied, or the dismantlement, restoration, or reclamation of properties.
Upon adoption of SFAS No. 143, certain removal obligations were identified that management believes are AROs but either have not been incurred or are not material. These removal obligations arise in the ordinary course of business or have a low probability of occurring. The types of obligations primarily relate to transmission and distribution lines and poles, telecommunication towers, transmission cables and certain FERC or state regulatory agency re-licensing issues. There was no impact to CL&P's earnings upon adoption of SFAS No. 143; however, if there are changes in certain laws and regulations, orders, interpretations or contracts entered into by CL&P there may be future AROs that need to be recorded.
Under SFAS No. 71, regulated utilities, including CL&P, currently recover amounts in rates for future costs of removal of plant assets. Future removals of assets do not represent legal obligations and are not AROs. Historically, these amounts were included as a component of accumulated depreciation until spent. At December 31, 2003 and 2002, these amounts totaling $150 million and $154 million, respectively, were reclassified to regulatory liabilities on the accompanying consolidated balance sheets.
In June 2003, the FASB issued a proposed FSP, "Applicability of SFAS No. 143, 'Accounting for Asset Retirement Obligations', to Legislative Requirements on Property Owners to Remove and Dispose of Asbestos or Asbestos-Containing Materials." In the FSP, the FASB staff concludes that current legislation creates a legal obligation for the owner of a building to remove and dispose of asbestos-containing materials. In the FSP, the FASB staff also concludes that this legal obligation constitutes an ARO that should be recognized as a liability under SFAS No. 143. This FSP changes a FASB staff interpretation of SFAS No. 143 that an obligating event did not occur until a building containing asbestos was demolished. In November 2003, the FASB indicated that, based on the diverse views it received in comment letters on the proposed FSP, it was considering a proposal for a FASB agenda project to address this issue. If this FSP is adopted in its current form, then CL&P would be required to record an ARO. Management has not estimated this potential ARO at December 31, 2003.
Special Purpose Entities: In addition to the special purpose entity that is described in the "Off-Balance Sheet Arrangements" section of this Management's Discussion and Analysis, during 2001, to facilitate the issuance of rate reduction certificates intended to finance certain stranded costs, CL&P established CL&P Funding LLC. CL&P Funding LLC was created as part of a state-sponsored securitization program. CL&P Funding LLC is restricted from engaging in non-related activities and is required to operate in a manner intended to reduce the likelihood that it would be included in CL&P's bankruptcy estate if it ever became involved in a bankruptcy proceeding. CL&P Funding LLC and the securitization amounts are consolidated in the accompanying consolidated financial statements.
For further information regarding the matters in this "Critical Accounting Policies and Estimates" section see Note 1, "Summary of Significant Accounting Policies," Note 3, "Derivative Instruments and Risk Management Activities," Note 4, "Pension Benefits and Postretirement Benefits Other Than Pensions," Note 12, "Income Tax Expense," and Note 6C, "Commitments and Contingencies - Environmental Matters," to the consolidated financial statements.
OTHER MATTERS
Commitments and Contingencies: For further information regarding other
commitments and contingencies, see Note 6, "Commitments and Contingencies,"
to the consolidated financial statements.
Contractual Obligations and Commercial Commitments: Information regarding CL&P's contractual obligations and commercial commitments at December 31, 2003 is summarized through 2008 and thereafter as follows:
------------------------------------------------------------------------------------------------------ (Millions of Dollars) 2004 2005 2006 2007 2008 Thereafter ------------------------------------------------------------------------------------------------------ Long-term debt (a) $ - $ - $ - $ - $ - $ 622.7 Capital leases (b) (c) 2.6 2.6 2.5 2.4 2.1 20.1 Operating leases (c) 11.8 11.2 10.1 9.0 8.3 16.4 Long-term contractual arrangements (c) (d) 222.9 222.1 223.6 225.3 215.5 1,252.1 ------------------------------------------------------------------------------------------------------ Totals $237.3 $235.9 $236.2 $236.7 $225.9 $1,911.3 ------------------------------------------------------------------------------------------------------ |
(a) Included in CL&P's debt agreements are usual and customary positive, negative and financial covenants. Non-compliance with certain covenants, for example the timely payment of principal and interest, may constitute an event of default, which could cause an acceleration of principal in the absence of receipt by the company of a waiver or amendment. Such acceleration would change the obligations outlined in the table of contractual obligations and commercial commitments. Long-term debt excludes fees and interest for spent nuclear fuel disposal costs and amortized premium and discount, net.
(b) The capital lease obligations include imputed interest of $17.4 million.
(c) CL&P has no provisions in its capital or operating lease agreements or agreements related to its long-term contractual arrangements that could trigger a change in terms and conditions, such as acceleration of payment obligations.
(d) Amounts are not included on CL&P's consolidated balance sheets.
Rate reduction bond amounts are non-recourse to CL&P, have no required payments over the next five years and are not included in this table. Additionally, this table does not include notes payable to affiliated companies totaling $91.1 million at December 31, 2003 and CL&P's expected contribution to the PBOP Plan in 2004 of $19.9 million. CL&P's standard offer service contracts and default service contracts are also not included in this table. For further information regarding CL&P's contractual obligations and commercial commitments, see Note 8, "Leases," Note 6F, "Commitments and Contingencies - Long-Term Contractual Arrangements," and Note 11, "Long-Term Debt," to the consolidated financial statements.
Forward Looking Statements: This discussion and analysis includes forward looking statements, which are statements of future expectations and not facts including, but not limited to, statements regarding future earnings, refinancings, regulatory proceedings, the use of proceeds from restructuring, and the recovery of operating costs. Words such as estimates, expects, anticipates, intends, plans, and similar expressions identify forward looking statements. Actual results or outcomes could differ materially as a result of further actions by state and federal regulatory bodies, competition and industry restructuring, changes in economic conditions, changes in weather patterns, changes in laws, developments in legal or public policy doctrines, technological developments, volatility in electric commodity markets, and other presently unknown or unforeseen factors.
Website: Additional financial information is available through NU's website at www.nu.com.
RESULTS OF OPERATIONS
The following table provides the variances in income statement line items for the consolidated statements of income included in this annual report for the past two years.
---------------------------------------------------------------------------------------------------
2003 over/(under) 2002 2002 over/(under) 2001
Income Statement Variances ---------------------- ----------------------
(Millions of Dollars) Amount Percent Amount Percent
---------------------------------------------------------------------------------------------------
Operating Revenues $197 8% $(139) (5)%
Operating Expenses:
Fuel, purchased and net interchange power 125 8 (37) (2)
Other operation 79 26 (10) (3)
Maintenance (7) (9) (26) (25)
Depreciation 6 6 2 2
Amortization 17 21 (597) (88)
Amortization of rate reduction bonds 7 7 29 42
Taxes other than income taxes 5 4 7 5
Gain on sale of utility plant 16 100 505 97
---------------------------------------------------------------------------------------------------
Total operating expenses 248 11 (127) (5)
---------------------------------------------------------------------------------------------------
Operating income (51) (20) (12) (4)
Interest expense, net (10) (9) - -
Other income, net (17) (79) (30) (58)
---------------------------------------------------------------------------------------------------
Income before income tax expense (58) (38) (42) (22)
Income tax expense (41) (62) (18) (21)
---------------------------------------------------------------------------------------------------
Net income $(17) (20)% $ (24) (22)%
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OPERATING REVENUES
Operating revenues increased by $197 million in 2003, primarily due to
higher retail revenues ($144 million), and higher wholesale revenues ($51
million). Retail revenues were higher primarily due to the collection of
incremental LMP costs beginning in May 2003 ($72 million) net of amounts to
be returned to customers and higher retail sales volumes ($72 million)
which includes a positive adjustment in estimated unbilled revenue of
approximately $39 million. Retail kWh sales increased by 3.3 percent in
2003 with the adjustment to unbilled sales. Wholesale revenues were higher
primarily due to higher market prices in 2003.
Operating revenues decreased $139 million in 2002, primarily due to lower wholesale and other revenues ($184 million), partially offset by higher retail revenues ($45 million). Wholesale revenues were lower due to the inclusion in 2001 of revenue from the output of the Millstone nuclear units ($62 million), lower revenues from sales of energy and capacity ($63 million) resulting from the buyout of cogenerator purchase contracts and lower wholesale market prices, and lower revenue from expiring market based contracts ($24 million). Retail revenues were higher due to the collection of deferred fuel costs ($25 million) and higher retail sales. Retail sales increased 1.8 percent compared to 2001.
FUEL, PURCHASED AND NET INTERCHANGE POWER
Fuel, purchased and net interchange power expense increased $125 million in
2003, primarily due to incremental LMP costs that were recovered from
customers ($72 million) and higher standard offer purchases as a result of
higher retail sales ($47 million).
Fuel, purchased and net interchange power expense decreased $37 million in 2002 primarily due to lower purchased-power costs resulting from the buydown and buyout of various cogeneration contracts ($50 million), lower market-based contracts ($23 million) and lower nuclear fuel expense ($8 million), partially offset by the 2002 amortization of deferred fuel expenses, which are being recovered ($25 million), and the higher expenses related to the standard offer supply and associated deferrals ($17 million).
OTHER OPERATION
Other operation expenses increased $79 million in 2003, primarily due to
higher administrative costs ($37 million) resulting from lower pension
income, higher reliability must run related transmission costs ($30
million), higher C&LM expenses ($8 million) and higher distribution
expenses ($5 million), partially offset by lower related nuclear expenses
($4 million) as a result of the final DPUC order regarding the CL&P
Millstone use of proceeds docket in the first quarter of 2003.
Other operation expenses decreased $10 million in 2002, primarily due to lower nuclear expense as a result of the sale of Millstone at the end of the first quarter of 2001 ($24 million), lower distribution expenses ($8 million), partially offset by higher transmission expenses ($16 million) and higher administrative and general expenses ($10 million).
MAINTENANCE
Maintenance expenses decreased $7 million in 2003, primarily due to lower
nuclear related expenses ($6 million) as a result of the final DPUC order
regarding the CL&P Millstone use of proceeds docket in the first quarter of
2003.
Maintenance expenses decreased $26 million in 2002, primarily due to lower nuclear expense as a result of the sale of Millstone at the end of the first quarter of 2001 ($28 million), partially offset by higher transmission expenses ($3 million).
DEPRECIATION
Depreciation expense increased $6 million in 2003, primarily due to higher
utility plant balances in 2003 resulting from plant additions.
Depreciation expense increased $2 million in 2002, primarily due to higher utility plant balances.
AMORTIZATION
Amortization increased $17 million in 2003, primarily due to higher
amortization related to the recovery of stranded costs ($73 million),
partially offset by lower amortization of recoverable nuclear costs ($38
million), and amortization expense recorded in 2002 related to gain on the
sale of CL&P's ownership share in Seabrook ($16 million).
Amortization decreased $597 million in 2002, primarily due to lower amortizations related to the sale of Millstone ($522 million) and lower amortizations of the nuclear investment ($42 million).
AMORTIZATION OF RATE REDUCTION BONDS
Amortization of rate reduction bonds increased $7 million in 2003 due to
the repayment of principal.
TAXES OTHER THAN INCOME TAXES
Taxes other than income taxes increased $5 million in 2003, primarily due
to higher gross earnings taxes ($2 million), the recognition in 2002 of a
Connecticut sales and use tax audit settlement ($7 million), partially
offset by lower tax payments to the Town of Waterford in 2003 as compared
to 2002 ($4 million).
Taxes other than income taxes increased $7 million in 2002, primarily due to payments to the Town of Waterford for its loss of property tax resulting from electric utility restructuring ($15 million), partially offset by the recognition of a Connecticut sales and use tax audit settlement for the years 1993 through 2001 ($7 million). CL&P is recovering through rates the additional property tax payments to the Town of Waterford.
GAIN ON SALE OF UTILITY PLANT
Gain on sale of utility plant decreased due to the $16 million gain
recorded in 2002 on the sale of CL&P's ownership share in Seabrook versus
no gain recorded in 2003.
CL&P recorded a gain on the sale of its ownership share in Seabrook in 2002 ($16 million) as compared to the 2001 gain on the sale of Millstone ($522 million). A corresponding amount of amortization expenses was recorded.
INTEREST EXPENSE, NET
Interest expense, net decreased $10 million in 2003 primarily due to lower
interest on rate reduction bonds ($5 million) and other interest ($3
million).
OTHER INCOME, NET
Other income, net decreased $17 million in 2003, primarily due to lower
interest and dividend income ($4 million), lower equity in earnings from
the nuclear entitlements ($4 million), lower conservation and load management
incentive income ($2 million), and higher charitable donations ($2 million).
Other income, net decreased $30 million in 2002, primarily due to the gain recognized in 2001 on the sale of Millstone ($29 million).
INCOME TAX EXPENSE
Income tax expense decreased in 2003 and in 2002 primarily due to lower
book taxable income. For further information regarding income tax expense,
see Note 12, "Income Tax Expense," to the consolidated financial
statements.
Management is responsible for the preparation, integrity, and fair presentation of the accompanying consolidated financial statements of The Connecticut Light and Power Company and subsidiaries and other sections of this annual report. These financial statements, which were audited by Deloitte & Touche LLP, have been prepared in conformity with accounting principles generally accepted in the United States of America using estimates and judgments, where required, and giving consideration to materiality.
The company has endeavored to establish a control environment that encourages the maintenance of high standards of conduct in all of its business activities. Management is responsible for maintaining a system of internal control over financial reporting that is designed to provide reasonable assurance, at an appropriate cost-benefit relationship, to the company's management and Board of Trustees of Northeast Utilities regarding the preparation of reliable, published financial statements. The system is supported by an organization of trained management personnel, policies and procedures, and a comprehensive program of internal audits. Through established programs, the company regularly communicates to its management employees their internal control responsibilities and obtains information regarding compliance with policies prohibiting conflicts of interest and policies segregating information between regulated and unregulated subsidiary companies. The company has standards of business conduct for all employees, as well as a code of ethics for senior financial officers.
The Audit Committee of the Board of Trustees of Northeast Utilities is composed entirely of independent trustees and includes two members that the Board of Trustees considers "audit committee financial experts." The Audit Committee meets regularly with management, the internal auditors and the independent auditors to review the activities of each and to discuss audit matters, financial reporting matters, and the system of internal controls over financial reporting. The Audit Committee also meets periodically with the internal auditors and the independent auditors without management present.
Because of inherent limitations in any system of internal controls, errors or irregularities may occur and not be detected. The company believes, however, that its system of internal controls over financial reporting and control environment provide reasonable assurance that its assets are safeguarded from loss or unauthorized use and that its financial records, which are the basis for the preparation of all financial statements, are reliable. Additionally, management believes that its disclosure controls and procedures are in place and operating effectively. Disclosure controls and procedures are designed to ensure that information included in reports such as this annual report is recorded, processed, summarized, and reported within the time periods required and that the information disclosed is accumulated and reviewed by management for discussion and approval.
To the Board of Directors of
The Connecticut Light and Power Company:
We have audited the accompanying consolidated balance sheets of The Connecticut Light and Power Company and subsidiaries (a Connecticut corporation and a wholly owned subsidiary of Northeast Utilities) (the "Company") as of December 31, 2003 and 2002, and the related consolidated statements of income, comprehensive income, common stockholder's equity, and cash flows for each of the three years in the period ended December 31, 2003. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of The Connecticut Light and Power Company and subsidiaries as of December 31, 2003 and 2002, and the results of their operations and their cash flows for the each of the three years in the period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America.
/s/ DELOITTE & TOUCHE LLP
DELOITTE & TOUCHE LLP
Hartford, Connecticut
February 23, 2004
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THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
----------------------------------------------------------------------------------------------
At December 31, 2003 2002
----------------------------------------------------------------------------------------------
(Thousands of Dollars)
ASSETS
------
Current Assets:
Cash $ 5,814 $ 159
Restricted cash - LMP costs 93,630 -
Investments in securitizable assets 166,465 178,908
Receivables, less provision for uncollectible
accounts of $21,790 in 2003 and $525 in 2002 60,759 88,001
Accounts receivable from affiliated companies 73,986 51,060
Unbilled revenues 6,961 5,801
Notes receivable from affiliated companies - 1,900
Materials and supplies, at average cost 31,583 32,379
Derivative assets 115,370 -
Prepayments and other 12,521 19,407
---------------- ----------------
567,089 377,615
---------------- ----------------
Property, Plant and Equipment:
Electric utility 3,355,794 3,139,128
Less: Accumulated depreciation 1,018,173 959,991
---------------- ----------------
2,337,621 2,179,137
Construction work in progress 224,277 153,556
---------------- ----------------
2,561,898 2,332,693
---------------- ----------------
Deferred Debits and Other Assets:
Regulatory assets 1,673,010 1,702,677
Prepaid pension 305,320 276,173
Other 99,577 96,925
---------------- ----------------
2,077,907 2,075,775
---------------- ----------------
Total Assets $ 5,206,894 $ 4,786,083
================ ================
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The accompanying notes are an integral part of these consolidated financial statements.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
----------------------------------------------------------------------------------------------
At December 31, 2003 2002
----------------------------------------------------------------------------------------------
(Thousands of Dollars)
LIABILITIES AND CAPITALIZATION
------------------------------
Current Liabilities:
Notes payable to affiliated companies $ 91,125 $ -
Accounts payable 138,155 174,890
Accounts payable to affiliated companies 176,948 117,904
Accrued taxes 65,587 34,350
Accrued interest 10,361 10,077
Derivative liabilities 54,566 -
Other 49,674 48,495
---------------- ----------------
586,416 385,716
---------------- ----------------
Rate Reduction Bonds 1,124,779 1,245,728
---------------- ----------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 609,068 756,461
Accumulated deferred investment tax credits 90,885 93,408
Deferred contractual obligations 318,043 234,537
Regulatory liabilities 752,992 343,754
Other 79,935 86,571
---------------- ----------------
1,850,923 1,514,731
---------------- ----------------
Capitalization:
Long-Term Debt 830,149 827,866
---------------- ----------------
Preferred Stock - Non-redeemable 116,200 116,200
---------------- ----------------
Common Stockholder's Equity:
Common stock, $10 par value - authorized
24,500,000 shares; 6,035,205 shares outstanding
in 2003 and 2002 60,352 60,352
Capital surplus, paid in 326,629 327,299
Retained earnings 311,793 308,554
Accumulated other comprehensive loss (347) (363)
---------------- ----------------
Common Stockholder's Equity 698,427 695,842
---------------- ----------------
Total Capitalization 1,644,776 1,639,908
---------------- ----------------
Commitments and Contingencies (Note 6)
Total Liabilities and Capitalization $ 5,206,894 $ 4,786,083
================ ================
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The accompanying notes are an integral part of these consolidated financial statements.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
----------------------------------------------------------------------------------------------------------
For the Years Ended December 31, 2003 2002 2001
----------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Operating Revenues $ 2,704,524 $ 2,507,036 $ 2,646,123
-------------- -------------- -------------
Operating Expenses:
Operation -
Fuel, purchased and net interchange power 1,602,240 1,477,347 1,514,418
Other 380,039 300,439 310,477
Maintenance 73,066 80,132 106,228
Depreciation 104,513 98,360 96,212
Amortization of regulatory assets, net 98,670 81,785 678,651
Amortization of rate reduction bonds 103,285 96,489 68,042
Taxes other than income taxes 142,339 137,299 130,656
Gain on sale of utility plant - (16,143) (521,590)
-------------- -------------- -------------
Total operating expenses 2,504,152 2,255,708 2,383,094
-------------- -------------- -------------
Operating Income 200,372 251,328 263,029
Interest Expense:
Interest on long-term debt 39,815 41,332 56,527
Interest on rate reduction bonds 70,284 75,705 60,644
Other interest 508 3,925 3,958
-------------- -------------- -------------
Interest expense, net 110,607 120,962 121,129
-------------- -------------- -------------
Other Income, Net 4,564 22,112 52,804
-------------- -------------- -------------
Income Before Income Tax Expense 94,329 152,478 194,704
Income Tax Expense 25,421 66,866 84,901
-------------- -------------- -------------
Net Income $ 68,908 $ 85,612 $ 109,803
============== ============== =============
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Net Income $ 68,908 $ 85,612 $ 109,803
-------------- -------------- -------------
Other comprehensive income/(loss), net of tax:
Unrealized gains/(losses) on securities 152 (408) (439)
Minimum supplemental executive retirement
pension liability adjustments (136) (22) -
-------------- -------------- -------------
Other comprehensive income/(loss), net of tax 16 (430) (439)
-------------- -------------- -------------
Comprehensive Income $ 68,924 85,182 $ 109,364
============== ============== =============
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The accompanying notes are an integral part of these consolidated financial statements.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
--------------------------------------------------------------------------------------------------------------------------------
Accumulated
Common Stock Capital Other
---------------------- Surplus, Retained Comprehensive Total
Shares Amount Paid In Earnings Income/(Loss) (a)
--------------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars, except share information)
Balance at January 1, 2001 7,584,884 $ 75,849 $413,192 $243,197 $ 506 $732,744
Net income for 2001 109,803 109,803
Cash dividends on preferred stock (5,559) (5,559)
Cash dividends on common stock (60,072) (60,072)
Capital stock expenses, net 826 826
Allocation of benefits - ESOP (468) (468)
Other comprehensive loss (439) (439)
---------- -------- -------- -------- ----- --------
Balance at December 31, 2001 7,584,884 75,849 414,018 286,901 67 776,835
Net income for 2002 85,612 85,612
Cash dividends on preferred stock (5,559) (5,559)
Cash dividends on common stock (60,145) (60,145)
Repurchase of common stock (1,549,679) (15,497) (84,493) (99,990)
Capital stock expenses, net 232 232
Allocation of benefits - ESOP (2,458) 1,745 (713)
Other comprehensive loss (430) (430)
---------- -------- -------- -------- ----- --------
Balance at December 31, 2002 6,035,205 60,352 327,299 308,554 (363) 695,842
Net income for 2003 68,908 68,908
Cash dividends on preferred stock (5,559) (5,559)
Cash dividends on common stock (60,110) (60,110)
Capital stock expenses, net 186 186
Allocation of benefits - ESOP (856) (856)
Other comprehensive income 16 16
---------- -------- -------- -------- ----- --------
Balance at December 31, 2003 6,035,205 $ 60,352 $326,629 $311,793 $(347) $698,427
========== ======== ======== ======== ===== ========
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(a) The Federal Power Act and the Public Utility Holding Act of 1935 (the 1935 Act)limit the payment of dividends by the company to its retained earnings balance.
The company also has dividend restrictions imposed by its long-term debt agreements. These restrictions limit the amount of retained earnings available for common dividends.
The Utility Group credit agreement also limits dividend payments subject to the requirements that the company's total debt to total capitalization ratio does not exceed 65 percent.
At December 31, 2003, retained earnings available for payment of dividends is restricted to $275.0 million.
The accompanying notes are an integral part of these consolidated financial statements.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
-------------------------------------------------------------------------------------------------------------------------
For the Years Ended December 31, 2003 2002 2001
-------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Operating Activities:
Net income $ 68,908 $ 85,612 $ 109,803
Adjustments to reconcile to net cash flows
provided by operating activities:
Depreciation 104,513 98,360 96,212
Deferred income taxes and investment tax credits, net (118,425) (71,880) (144,559)
Amortization of regulatory assets, net 98,670 81,785 678,651
Amortization of rate reduction bonds 103,285 96,489 68,042
Amortization of recoverable energy costs 19,191 30,787 5,162
Gain on sale of utility plant - (16,143) (521,590)
Increase in prepaid pension (29,147) (42,481) (63,020)
Regulatory overrecoveries/(refunds) 275,015 92,743 (49,443)
Other sources of cash 2,283 11,646 26,465
Other uses of cash (99,827) (44,245) (86,635)
Changes in current assets and liabilities:
Restricted cash - LMP costs (93,630) - -
Receivables and unbilled revenues, net 3,156 (37,435) (144,419)
Materials and supplies 796 (1,017) 3,247
Investments in securitizable assets 12,443 27,459 61,779
Other current assets (excludes cash) 6,886 (1,535) 14,418
Accounts payable 22,309 74,831 (58,400)
Accrued taxes 31,237 (643) 1,922
Other current liabilities 1,385 351 11,414
----------- ---------- ----------
Net cash flows provided by operating activities 409,048 384,684 9,049
----------- ---------- ----------
Investing Activities:
Investments in plant (314,628) (239,634) (236,218)
NU system Money Pool borrowing/(lending) 93,025 75,300 (39,200)
Investments in nuclear decommissioning trusts - (1,086) (74,866)
Net proceeds from the sale of utility plant - 35,887 827,681
Buyout/buydown of IPP contracts - - (1,029,008)
Other investment activities 5,448 23,395 (10,164)
----------- ---------- ----------
Net cash flows used in investing activities (216,155) (106,138) (561,775)
----------- ---------- ----------
Financing Activities:
Repurchase of common shares - (99,990) -
Issuance of rate reduction bonds - - 1,438,400
Retirement of rate reduction bonds (120,949) (112,924) (79,747)
Decrease in short-term debt - - (115,000)
Reacquistions and retirements of long-term debt - - (416,155)
Retirement of monthly income preferred securities - - (100,000)
Retirement of capital lease obligation - - (145,800)
Cash dividends on preferred stock (5,559) (5,559) (5,559)
Cash dividends on common stock (60,110) (60,145) (60,072)
Other financing activities (620) (542) 31,971
----------- ---------- ----------
Net cash flows (used in)/provided by financing activities (187,238) (279,160) 548,038
----------- ---------- ----------
Net increase/(decrease) in cash 5,655 (614) (4,688)
Cash - beginning of year 159 773 5,461
----------- ---------- ----------
Cash - end of year $ 5,814 $ 159 $ 773
=========== ========== ==========
Supplemental Cash Flow Information:
Cash paid during the year for:
Interest, net of amounts capitalized $ 112,258 $ 117,718 $ 120,645
=========== ========== ==========
Income taxes $ 105,167 $ 141,724 $ 230,144
=========== ========== ==========
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The accompanying notes are an integral part of these consolidated financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A. ABOUT THE CONNECTICUT LIGHT AND POWER COMPANY The Connecticut Light and Power Company (CL&P or the company) is a wholly owned subsidiary of Northeast Utilities (NU). CL&P is registered with the Securities and Exchange Commission (SEC) under the Securities Exchange Act of 1934. NU is registered with the SEC as a holding company under the Public Utility Holding Company Act of 1935 (1935 Act), and NU, including CL&P, is subject to the provisions of the 1935 Act. Arrangements among CL&P, other NU companies, outside agencies, and other utilities covering interconnections, interchange of electric power and sales of utility property, are subject to regulation by the Federal Energy Regulatory Commission (FERC) and/or the SEC. CL&P is subject to further regulation for rates, accounting and other matters by the FERC and the Connecticut Department of Public Utility Control (DPUC). CL&P, Public Service Company of New Hampshire (PSNH), and Western Massachusetts Electric Company (WMECO), furnish franchised retail electric service in Connecticut, New Hampshire and Massachusetts, respectively.
Several wholly owned subsidiaries of NU provide support services for NU's companies, including CL&P. Northeast Utilities Service Company (NUSCO) provides centralized accounting, administrative, engineering, financial, information technology, legal, operational, planning, purchasing, and other services to NU's companies.
On January 1, 2000, Select Energy, Inc. (Select Energy), another NU subsidiary, began serving one half of CL&P's standard offer load for a four- year period ending on December 31, 2003, at fixed prices. Total CL&P purchases from Select Energy for CL&P's standard offer load and for other transactions with Select Energy represented approximately $688 million, approximately $631 million and approximately $648 million, for the years ended December 31, 2003, 2002, and 2001, respectively.
B. PRESENTATION The consolidated financial statements of CL&P and of its subsidiaries, as applicable, include the accounts of all their respective subsidiaries. Intercompany transactions have been eliminated in consolidation.
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingencies at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Certain reclassifications of prior years' data have been made to conform with the current year's presentation. Reclassifications were made to cost of removal and regulatory asset and liability amounts on the accompanying consolidated balance sheets. Reclassifications have also been made to the accompanying consolidated statements of cash flows.
C. NEW ACCOUNTING STANDARDS Derivative Accounting: Effective January 1, 2001, CL&P adopted Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended. In April 2003, the Financial Accounting Standards Board (FASB) issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities," which amends SFAS No. 133. This new statement incorporates interpretations that were included in previous Derivative Implementation Group (DIG) guidance, clarifies certain conditions, and amends other existing pronouncements. It is effective for contracts entered into or modified after June 30, 2003. Management has determined that the adoption of SFAS No. 149 did not change CL&P's accounting for contracts, or the ability of CL&P to elect the normal purchases and sales exception.
In August of 2003, the FASB ratified the consensus reached by its Emerging Issues Task Force (EITF) in July 2003 on EITF Issue No. 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." Prior to Issue No. 03-11, no specific guidance existed to address the classification in the income statement of derivative contracts that are not held for trading purposes. The consensus states that determining whether realized gains and losses on contracts that physically deliver and are not held for trading purposes should be reported on a net or gross basis is a matter of judgment that depends on the relevant facts and circumstances. EITF Issue No. 03-11 did not have an impact on CL&P's consolidated financial statements.
On June 25, 2003, the DIG cleared Issue No. C-20, which addressed the meaning of "not clearly and closely related regarding contracts with a price adjustment feature" as it relates to the election of the normal purchase and sales exception to derivative accounting. The implementation of this guidance was required to be adopted in the fourth quarter of 2003 for CL&P. Issue No. C-20 resulted in CL&P recording the fair value of two existing power purchase contracts as derivatives, one as a derivative asset and one as a derivative liability with offsetting regulatory liabilities and assets, as these contracts are part of stranded costs and as management believes that these costs will continue to be recovered or refunded in rates. The fair values of these long-term power purchase contracts include a derivative asset with a fair value of $112.4 million and a derivative liability with a fair value of $54.6 million at December 31, 2003.
Employers' Disclosures about Pensions and Other Postretirement Benefits:
In December 2003, the FASB issued SFAS No. 132 (Revised 2003), "Employers'
Disclosures about Pensions and Other Postretirement Benefits," (SFAS No.
132R). This statement revises employers' disclosures about pension plans
and other postretirement benefit plans, requires additional disclosures
about the assets, obligations, cash flows, and the net periodic benefit
cost of defined benefit pension plans and other defined benefit
postretirement plans and requires companies to disclose various elements of
pension and postretirement benefit costs in interim period financial
statements. The revisions in SFAS No. 132R are effective for 2003, and
CL&P included the disclosures required by SFAS No. 132R in this annual
report. For the required disclosures, see Note 4, "Pension Benefits and
Postretirement Benefits Other Than Pensions," to the consolidated financial
statements.
Liabilities and Equity: In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity." SFAS No. 150 establishes standards on how to classify and measure certain financial instruments with characteristics of both liabilities and equity. SFAS No. 150 is effective for financial instruments entered into or modified after May 31, 2003, and was otherwise effective for CL&P for the third quarter of 2003. The adoption of SFAS No. 150 did not have an impact on CL&P's consolidated financial statements.
Consolidation of Variable Interest Entities: In December 2003, the FASB issued a revised version of FASB Interpretation No. (FIN) 46 "Consolidation of Variable Interest Entities," (FIN 46R). FIN 46R is effective for CL&P for the first quarter of 2004 but is not expected to have an impact on CL&P's consolidated financial statements.
D. GUARANTEES CL&P has obtained surety bonds in the amount of $31.1 million related to the collection of March 2003 and April 2003 incremental locational marginal pricing (LMP) costs in compliance with a DPUC order. These surety bonds are guaranteed by NU.
E. REVENUES CL&P retail revenues are based on rates approved by the DPUC. These regulated rates are applied to customers' use of energy to calculate a bill. In general, rates can only be changed through formal proceedings with the DPUC.
CL&P utilizes regulatory commission-approved tracking mechanisms to track the recovery of certain incurred costs. The tracking mechanisms allow for rates to be changed periodically, with overcollections refunded to customers or underrecollections collected from customers in future periods.
Unbilled revenues represent an estimate of electricity delivered to customers that has not been billed. Unbilled revenues represent assets on the balance sheet that become accounts receivable in the following month as customers are billed. Billed revenues are based on meter readings.
Unbilled revenues are estimated monthly using the requirements method. The requirements method utilizes the total monthly volume of electricity or gas delivered to the system and applies a delivery efficiency factor to reduce the total monthly volume by an estimate of delivery losses in order to calculate total estimated monthly sales to customers. The total estimated monthly sales amount less total monthly billed sales amount results in a monthly estimate of unbilled sales. Unbilled revenues are estimated by applying an average rate to the estimate of unbilled sales.
In 2003, the unbilled sales estimates for CL&P were tested using the cycle method. The cycle method uses the billed sales from each meter reading cycle and an estimate of unbilled days in each month based on the meter reading schedule. The cycle method is historically more accurate than the requirements method when used in a mostly weather-neutral month. The cycle method resulted in adjustments to the estimate of unbilled revenues that had a positive after-tax earnings impact on CL&P of $7.2 million in 2003.
Wholesale transmission revenues are based on rates and formulas that are approved by the FERC. Most of CL&P's wholesale transmission revenues are collected through a combination of the New England Regional Network Service (RNS) tariff and CL&P's Local Network Service (LNS) tariff. The RNS tariff, which is administered by the New England Independent System Operator (ISO-NE), recovers the revenue requirements associated with transmission facilities that are deemed by the FERC to be Pool Transmission Facilities. The LNS tariff which was accepted by the FERC on October 22, 2003, provides for the recovery of CL&P's total transmission revenue requirements, net of revenue credits received from various rate components, including revenues received under the RNS rates.
F. ACCOUNTING FOR ENERGY CONTRACTS The accounting treatment for energy contracts entered into varies between contracts and depends on the intended use of the particular contract and on whether or not the contracts are derivatives.
Non-derivative contracts that are entered into for the normal purchase or sale of energy to customers that will result in physical delivery are recorded at the point of delivery under accrual accounting.
Derivative contracts that are entered into for the normal purchase and sale of energy and meet the normal purchase and sale exception to derivative accounting, as defined in SFAS No. 133 and amended by SFAS No. 149 (normal), are also recorded at the point of delivery under accrual accounting.
Both non-derivative contracts and derivative contracts that are normal are recorded in revenues when these contracts represent sales, and recorded in fuel, purchased and net interchange power when these contracts represent purchases, except for sales contracts that relate to procurement activities. These contracts are recorded in fuel, purchased and net interchange power when settled.
Derivative contracts that are not held for trading purposes and that do not qualify as normal purchases and sales or hedges are non-trading derivative contracts. These contracts are recorded on the consolidated balance sheets at fair value, and since management believes that these costs will continue to be recovered or refunded in rates, the changes in fair value are offset by regulatory assets and liabilities.
For further information regarding these contracts and their accounting, see Note 3, "Derivative Instruments and Risk Management Activities," to the consolidated financial statements.
G. REGULATORY ACCOUNTING The accounting policies of CL&P conform to accounting principles generally accepted in the United States of America applicable to rate-regulated enterprises and historically reflect the effects of the rate-making process in accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation."
The transmission and distribution businesses of CL&P continue to be cost-of- service rate regulated. Management believes the application of SFAS No. 71 to that portion of those businesses continues to be appropriate. Management also believes it is probable that CL&P will recover their investments in long-lived assets, including regulatory assets. In addition, all material net regulatory assets are earning an equity return, except for securitized regulatory assets, which are not supported by equity.
The components of CL&P's regulatory assets are as follows:
--------------------------------------------------------------------------
At December 31,
--------------------------------------------------------------------------
(Millions of Dollars) 2003 2002
--------------------------------------------------------------------------
Recoverable nuclear costs $ 16.4 $ 10.6
Securitized assets 1,123.7 1,244.5
Income taxes, net 140.9 165.0
Unrecovered contractual obligations 221.8 116.8
Recoverable energy costs 30.1 49.3
Other 140.1 116.5
--------------------------------------------------------------------------
Totals $1,673.0 $1,702.7
--------------------------------------------------------------------------
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Additionally, CL&P had $12.2 million and $6.1 million of regulatory assets at December 31, 2003 and 2002, respectively, that are included in deferred debits and other assets - other on the accompanying consolidated balance sheets. These amounts represent regulatory assets that have not yet been approved by the applicable regulatory agency. Management believes these assets are recoverable in future rates.
Recoverable Nuclear Costs: In March 2001, CL&P sold its ownership interest in the Millstone nuclear units (Millstone). The gain on the sale of $521.6 million was used to offset recoverable nuclear costs, resulting in unamortized balances of $16.4 million and $6 million at December 31, 2003 and 2002, respectively. Also included in recoverable nuclear costs for 2002 are $4.6 million related to Millstone 1 recoverable nuclear costs associated with the undepreciated plant and related assets at the time Millstone 1 was shut down.
Securitized Assets: In March 2001, CL&P issued $1.4 billion in rate reduction certificates. CL&P used $1.1 billion of those proceeds to buy out or buy down certain contracts with independent power producers (IPP). The remaining balance is $960 million and $1.1 billion at December 31, 2003 and 2002, respectively. CL&P also securitized a portion of its SFAS No. 109, "Accounting for Income Taxes," regulatory asset which had a balance of $164 million and $180 million at December 31, 2003 and 2002, respectively.
Securitized assets are being recovered over the amortization period of their associated rate reduction bonds. All outstanding rate reduction bonds of CL&P are scheduled to amortize by December 30, 2010.
Income Taxes, Net: The tax effect of temporary differences (differences between the periods in which transactions affect income in the financial statements and the periods in which they affect the determination of taxable income) is accounted for in accordance with the rate-making treatment of the DPUC and SFAS No. 109. Differences in income taxes between SFAS No. 109 and the rate-making treatment of the DPUC are recorded as regulatory assets. For further information regarding income taxes, see Note 1H, "Summary of Significant Accounting Policies - Income Taxes," and Note 12, "Income Tax Expense," to the consolidated financial statements.
Unrecovered Contractual Obligations: CL&P, under the terms of contracts with the Yankee Companies, is responsible for its proportionate share of the remaining costs of the units, including decommissioning. These amounts are recorded as unrecovered contractual obligations. A portion of these obligations was securitized in 2001 and is included in securitized regulatory assets. During 2002, CL&P was notified by the Yankee Companies that the estimated cost of decommissioning their units had increased over prior estimates due to higher anticipated costs for spent fuel storage, security and liability and property insurance. In December 2002, CL&P recorded an additional $115.6 million in deferred contractual obligations and a corresponding increase in the unrecovered contractual obligations regulatory asset as a result of these increased costs.
In November 2003, the Connecticut Yankee Atomic Power Company (CYAPC) prepared an updated estimate of the cost of decommissioning its nuclear unit. CL&P's aggregate share of the estimated increased cost is $118.1 million. CL&P recorded an additional $118.1 million in deferred contractual obligations and a corresponding increase in the unrecovered contractual obligations regulatory asset as a result of these increased costs.
Recoverable Energy Costs: Under the Energy Policy Act of 1992 (Energy Act), CL&P was assessed for its proportionate shares of the costs of decontaminating and decommissioning uranium enrichment plants owned by the United States Department of Energy (DOE) (D&D Assessment). The Energy Act requires that regulators treat D&D Assessments as a reasonable and necessary current cost of fuel, to be fully recovered in rates like any other fuel cost. CL&P no longer owns nuclear generation but continues to recover these costs through rates. At December 31, 2003 and 2002, CL&P's total D&D Assessment deferrals were $14.3 million and $17.6 million, respectively, and have been recorded as recoverable energy costs.
Through December 31, 1999, CL&P had an energy adjustment clause under which fuel prices above or below base-rate levels were charged to or credited to customers. CL&P's energy costs deferred and not yet collected under the energy adjustment clause amounted to $31.7 million at December 31, 2002, which were recorded as recoverable energy costs. On July 26, 2001, the DPUC authorized CL&P to assess a charge of approximately $0.002 per kilowatt-hour (kWh) to collect these costs from August 2001 through December 31, 2003, at which time no unrecovered costs remained. During 2003, CL&P paid for a temporary generation resource in southwest Connecticut to help maintain reliability. Costs for this resource of $15.8 million were recorded as recoverable energy costs at December 31, 2003. The DPUC has authorized recovery of these costs in 2004 through a non- bypassable Federally Mandated Congestion Charge.
The majority of the recoverable energy costs are recovered in rates currently from CL&P's customers.
Regulatory Liabilities: CL&P maintained $753 million and $343.8 million of regulatory liabilities at December 31, 2003 and 2002, respectively. These amounts are comprised of the following:
---------------------------------------------------------------------
At December 31,
---------------------------------------------------------------------
(Millions of Dollars) 2003 2002
---------------------------------------------------------------------
Cost of removal $150.0 $154.0
CL&P CTA, GSC, and SBC overcollections 333.7 133.6
Regulatory liabilities offsetting
derivative assets 115.4 -
CL&P LMP overcollections 83.6 -
Other regulatory liabilities 70.3 56.2
---------------------------------------------------------------------
Totals $753.0 $343.8
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Under SFAS No. 71, CL&P currently recovers amounts in rates for future costs of removal of plant assets. Historically, these amounts were included as a component of accumulated depreciation until spent. These amounts were reclassified to regulatory liabilities on the accompanying consolidated balance sheets.
The Competitive Transition Assessment (CTA) allows CL&P to recover stranded costs, such as securitization costs associated with the rate reduction bonds, amortization of regulatory assets, and IPP over market costs while the Generation Service Charge (GSC) allows CL&P to recover the costs of the procurement of energy for standard offer service. The System Benefits Charge (SBC) allows CL&P to recover certain regulatory and energy public policy costs, such as public education outreach costs, hardship protection costs, transition period property taxes, and displaced workers protection costs.
The regulatory liabilities offsetting derivative assets relate to the fair value of IPP contracts that will benefit ratepayers in the future. CL&P also has financial transmission rights (FTR) contracts which are derivative assets offset by a regulatory liability.
H. INCOME TAXES The tax effect of temporary differences (differences between the periods in which transactions affect income in the financial statements and the periods in which they affect the determination of taxable income) is accounted for in accordance with the rate-making treatment of the applicable regulatory commissions and SFAS No. 109.
The tax effects of temporary differences that give rise to the net accumulated deferred tax obligation are as follows:
---------------------------------------------------------------------
At December 31,
---------------------------------------------------------------------
(Millions of Dollars) 2003 2002
---------------------------------------------------------------------
Deferred tax liabilities:
Accelerated depreciation and
other plant-related differences $533.8 $514.8
Regulatory amounts:
Securitized contract termination
costs and other 51.0 57.5
Income tax gross-up 136.5 156.7
Employee benefits 121.1 115.5
Other 46.2 86.3
---------------------------------------------------------------------
Total deferred tax liabilities 888.6 930.8
---------------------------------------------------------------------
Deferred tax assets:
Regulatory deferrals 199.3 101.5
Employee benefits 7.0 6.8
Income tax gross-up 20.9 22.3
Other 52.3 43.7
---------------------------------------------------------------------
Total deferred tax assets 279.5 174.3
---------------------------------------------------------------------
Totals $609.1 $756.5
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NU and its subsidiaries, including CL&P, file a consolidated federal income tax return. Likewise NU and its subsidiaries, including CL&P, file state income tax returns, with some filing in more than one state. NU and its subsidiaries, including CL&P, are parties to a tax allocation agreement under which each taxable subsidiary pays a quarterly estimate (or settlement) of no more than it would have otherwise paid had it filed a stand-alone tax return. Generally these quarterly estimated payments are settled to actual payments within three months after filing the associated return. Subsidiaries generating tax losses are similarly paid for their losses when utilized.
In 2000, NU requested from the Internal Revenue Service (IRS) a Private Letter Ruling (PLR) regarding the treatment of unamortized investment tax credits (ITC) and excess deferred income taxes (EDIT) related to generation assets that have been sold. EDIT are temporary differences between book and taxable income that were recorded when the federal statutory tax rate was higher than it is now or when those differences were expected to be resolved. The PLR addresses whether or not EDIT and ITC can be returned to customers, which without a PLR management believes would represent a violation of current tax law. The IRS declared a moratorium on issuing PLRs until final regulations on the return of EDIT and ITC to regulated customers are issued by the Treasury Department. Proposed regulations were issued in March 2003, and a hearing took place in June 2003. The proposed new regulations would allow the return of EDIT and ITC to regulated customers without violating the tax law. Also, under the proposed regulations, a company could elect to apply the regulation retroactively. The Treasury Department is currently deliberating the comments received at the hearing. If final regulations consistent with the proposed regulations are issued, then there could be an impact on CL&P's financial statements.
I. DEPRECIATION The provision for depreciation is calculated using the straight-line method based on the estimated remaining useful lives of depreciable plant-in- service, which range primarily from 3 years to 50 years, adjusted for salvage value and removal costs, as approved by the appropriate regulatory agency where applicable. Depreciation rates are applied to plant-in- service from the time it is placed in service. When plant is retired from service, the original cost of the plant, including costs of removal less salvage, is charged to the accumulated provision for depreciation. Cost of removal is now classified as a regulatory liability. The depreciation rates for the several classes of electric utility plant-in-service are equivalent to a composite rate of 3.3 percent in 2003, 3.2 percent in 2002 and 3.1 percent in 2001.
J. EQUITY INVESTMENTS AND JOINTLY OWNED ELECTRIC UTILITY PLANT Regional Nuclear Companies: At December 31, 2003, CL&P owns common stock in three regional nuclear companies (Yankee Companies). CL&P's ownership interest in the Yankee Companies at December 31, 2003, which are accounted for on the equity method are 34.5 percent of the CYAPC, 24.5 percent of the Yankee Atomic Electric Company (YAEC) and 12 percent of the Maine Yankee Atomic Power Company (MYAPC). Effective November 7, 2003, CL&P sold its 10.1 percent ownership interest in Vermont Yankee Nuclear Power Corporation (VYNPC). CL&P's total equity investment in the Yankee Companies at December 31, 2003 and 2002, is $21.8 million and $32.2 million, respectively. Each of the remaining Yankee Companies owns a single nuclear generating plant which is being decommissioned.
K. ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION The allowance for funds used during construction (AFUDC) is a non-cash item that is included in the cost of utility plant and represents the cost of borrowed and equity funds used to finance construction. The portion of AFUDC attributable to borrowed funds is recorded as a reduction of other interest expense, and the cost of equity funds is recorded as other income on the consolidated statements of income:
----------------------------------------------------------------
For the Years Ended December 31,
----------------------------------------------------------------
(Millions of Dollars,
except percentages) 2003 2002 2001
----------------------------------------------------------------
Borrowed funds $3.0 $2.7 $3.2
Equity funds 5.8 5.1 2.0
----------------------------------------------------------------
Totals $8.8 $7.8 $5.2
----------------------------------------------------------------
Average AFUDC rates 7.9% 8.2% 8.5%
----------------------------------------------------------------
|
L. ASSET RETIREMENT OBLIGATIONS In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." This statement requires that legal obligations associated with the retirement of property, plant and equipment be recognized as a liability at fair value when incurred and when a reasonable estimate of the fair value of the liability can be made. SFAS No. 143 was effective on January 1, 2003, for CL&P. Management has completed its review process for potential asset retirement obligations (ARO) and has not identified any material AROs that have been incurred. However, management has identified certain removal obligations that arise in the ordinary course of business or have a low probability of occurring. These types of obligations primarily relate to transmission and distribution lines and poles, telecommunication towers, transmission cables and certain FERC or state regulatory agency re-licensing issues. These obligations are AROs that have not been incurred or are not material in nature.
A portion of CL&P's rates are intended to recover the cost of removal of certain utility assets. The amounts recovered do not represent AROs. At December 31, 2003 and 2002, cost of removal was approximately $150 million and $154 million, respectively.
M. MATERIALS AND SUPPLIES Materials and supplies include materials purchased primarily for construction, operation and maintenance (O&M) purposes. Materials and supplies are valued at the lower of average cost or market.
N. SALE OF CUSTOMER RECEIVABLES CL&P has an arrangement with a financial institution under which CL&P can sell up to $100 million of accounts receivable and unbilled revenues. At December 31, 2003 and 2002, CL&P had sold accounts receivable of $80 million and $40 million, respectively, to the financial institution with limited recourse through CL&P Receivables Corporation (CRC), a wholly owned subsidiary of CL&P. At December 31, 2003 and 2002, the reserve requirements calculated in accordance with the Receivables Purchase and Sale Agreement were $29.3 million and $3.8 million, respectively. These reserve amounts are deducted from the amount of receivables eligible for sale at the time. Concentrations of credit risk to the purchaser under this agreement with respect to the receivables are limited due to CL&P's diverse customer base within its service territory. At December 31, 2003 and 2002, amounts sold to CRC by CL&P but not sold to the financial institution totaling $166.5 million and $178.9 million, respectively, are included in investments in securitizable assets on the accompanying consolidated balance sheets. These amounts would be excluded from CL&P's assets in the event of CL&P's bankruptcy. On July 9, 2003, CL&P renewed this arrangement.
The transfer of receivables to the financial institution under this arrangement qualifies for sale treatment under SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishment of Liabilities - A Replacement of SFAS No. 125." This agreement expires on July 7, 2004. Management plans to renew this agreement prior to its expiration.
O. RESTRICTED CASH - LMP COSTS Restricted cash - LMP costs represents incremental LMP cost amounts that have been collected by CL&P and deposited into an escrow account.
P. EXCISE TAXES Certain excise taxes levied by state or local governments are collected by CL&P from its customers. These excise taxes are accounted for on a gross basis with collections in revenues and payments in expenses. For the years ended December 31, 2003, 2002 and 2001, gross receipts taxes, franchise taxes and other excise taxes of approximately $76.3 million, $74.4 million and $74.8 million, respectively, are included in operating revenues and taxes other than income taxes on the accompanying consolidated statements of income.
Q. OTHER INCOME The pre-tax components of CL&P's other income/(loss) items are as follows:
---------------------------------------------------------------------
For the Years Ended December 31,
---------------------------------------------------------------------
(Millions of Dollars) 2003 2002 2001
---------------------------------------------------------------------
Seabrook-related gains $ - $ 2.1 $ -
Gain related to Millstone sale - - 29.5
Investment income 2.7 10.2 12.9
Charitable donations (4.6) (2.8) (3.5)
Other 6.5 12.6 13.9
---------------------------------------------------------------------
Totals $4.6 $22.1 $52.8
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Limits: The amount of short-term borrowings that may be incurred by CL&P is subject to periodic approval by either the SEC under the 1935 Act or by the DPUC. On June 30, 2003, the SEC granted authorization allowing CL&P to incur total short-term borrowings up to a maximum of $375 million through June 30, 2006, with authorization for borrowings from the NU Money Pool (Pool) granted through June 30, 2004.
The charter of CL&P contains preferred stock provisions restricting the amount of unsecured debt that CL&P may incur. At meetings in November 2003, CL&P obtained authorization from its stockholders to issue unsecured indebtedness with a maturity of less than 10 years in excess of the 10 percent of total capitalization limitation in CL&P's charter, provided that all unsecured indebtedness would not exceed 20 percent of total capitalization for a ten-year period expiring March 2014. As of December 31, 2003, CL&P is permitted to incur $366 million of additional unsecured debt.
Credit Agreement: On November 10, 2003, CL&P, PSNH, WMECO and Yankee Gas entered into a 364-day unsecured revolving credit facility for $300 million. This facility replaces a similar credit facility that expired on November 11, 2003 and CL&P may draw up to $150 million. Unless extended, the credit facility will expire on November 8, 2004. At December 31, 2003 and 2002, there were no CL&P borrowings under these credit facilities.
Under the aforementioned credit agreement, CL&P may borrow at fixed or variable rates plus an applicable margin based upon certain debt ratings, as rated by the lower of Standard and Poor's or Moody's Investors Service.
Under the credit agreement, CL&P must comply with certain financial and non- financial covenants as are customarily included in such agreements, including but not limited to, consolidated debt ratios and interest coverage ratios. The most restrictive financial covenant is the interest coverage ratio. CL&P currently is and expects to remain in compliance with these covenants.
Pool: CL&P is a member of the Pool. The Pool provides a more efficient use of the cash resources of NU and reduces outside short-term borrowings. NUSCO administers the Pool as agent for the member companies. Short-term borrowing needs of the member companies are first met with available funds of other member companies, including funds borrowed by NU parent. NU parent may lend to the Pool but may not borrow. Funds may be withdrawn from or repaid to the Pool at any time without prior notice. Investing and borrowing subsidiaries receive or pay interest based on the average daily federal funds rate. Borrowings based on loans from NU parent, however, bear interest at NU parent's cost and must be repaid based upon the terms of NU parent's original borrowing. At December 31, 2003 and 2002, CL&P had borrowings of $91.1 million and lendings of $1.9 million to the Pool, respectively. The interest rate on borrowings from and lendings to the Pool at December 31, 2003 and 2002 was 5 percent and 1.2 percent, respectively.
A. DERIVATIVE INSTRUMENTS Effective January 1, 2001, CL&P adopted SFAS No. 133, as amended. Derivatives that do not meet the definition of a cash flow hedge and cannot be designated as being used for normal purchases or normal sales are also recorded at fair value with changes in fair value included in earnings unless recorded as a regulatory asset or liability. Derivative contracts that are entered into as a normal purchase or sale and will result in physical delivery, and are documented as such, are recorded under accrual accounting. For information regarding accounting changes related to derivative instruments, see Note 1C, "Summary of Significant Accounting Policies - New Accounting Standards," to the consolidated financial statements.
In 2003, there were changes to the interpretations of as well as an amendment to SFAS No. 133, and the FASB continues to consider changes that could affect the way CL&P records and discloses derivative and hedging activities.
CL&P has two IPP contracts to purchase power that contain pricing provisions that are not clearly and closely related to the price of power. Because of a clarification in the definition of "clearly and closely related" in Issue No. C-20, these contracts no longer qualify for the normal purchases and sales exception to SFAS No. 133, as amended. The fair values of these IPP non-trading derivatives at December 31, 2003 include a derivative asset with a fair value of $112.4 million and a derivative liability with a fair value of $54.6 million with offsetting regulatory liabilities and regulatory assets, respectively. These fair values were determined by comparing the IPP contract prices to projected market prices and discounting the estimated over or under-market portions back to December 31, 2003. To mitigate the risk associated with certain supply contracts, CL&P purchased FTRs. FTRs are derivatives that cannot qualify for the normal purchases and sales exception. The fair value of these FTR non-trading derivatives at December 31, 2003 was an asset of $3 million. CL&P had no non-trading derivatives at December 31, 2002 that were required to be recorded at fair value.
B. RISK MANAGEMENT ACTIVITIES CL&P is subject to credit risk from certain long-term or high-volume supply contracts with energy marketing companies. Credit risks and market risks at CL&P are monitored regularly by a Risk Oversight Council operating outside of the business units that create or actively manage these risk exposures to ensure compliance with NU's stated risk management policies.
Pension Benefits: CL&P participates in a uniform noncontributory defined benefit retirement plan (Pension Plan) covering substantially all regular NU employees. Benefits are based on years of service and the employees' highest eligible compensation during 60 consecutive months of employment. Pre-tax pension income was $29.1 million in 2003, $50.6 million in 2002, and $61.4 million in 2001. These amounts exclude pension settlements, curtailments and net special termination expenses of $8.1 million in 2002 and $1.2 million in 2001. CL&P uses a December 31 measurement date for the Pension Plan. Pension income attributable to earnings is as follows:
--------------------------------------------------------------------
For the Years Ended December 31,
--------------------------------------------------------------------
(Millions of Dollars) 2003 2002 2001
--------------------------------------------------------------------
Pension income before
settlements, curtailments
and special termination benefits $(29.1) $(50.6) $(61.4)
Net pension income
capitalized as utility plant 15.1 20.8 24.8
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Net pension income before
settlements, curtailments
and special termination
benefits (14.0) (29.8) (36.6)
Settlements, curtailments and
special termination benefits
reflected in earnings - - 3.3
---------------------------------------------------------------------
Total pension income
included in earnings $(14.0) $(29.8) $(33.3)
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Pension Settlements, Curtailments and Special Termination Benefits: There were no settlements, curtailments or special termination benefits in 2003.
Effective February 1, 2002, certain CL&P employees who were displaced were eligible for a Voluntary Retirement Program (VRP). The VRP supplements the Pension Plan and provides special provisions. Eligible employees include non-bargaining unit employees or employees belonging to a collective bargaining unit that agreed to accept the VRP who were active participants in the Pension Plan at January 1, 2002, and that were displaced as part of the reorganization between January 22, 2002 and March 2003. Eligible employees received a special retirement benefit under the VRP whose value was roughly equivalent to a multiple of base pay based on years of credited service. During 2002, CL&P recorded an expense of $8.1 million associated with special pension termination benefits related to the VRP. The cost of the VRP was recovered through regulated utility rates and the $8.1 million was recorded as a regulatory asset with no impact on 2002 earnings.
In conjunction with the Voluntary Separation Program (VSP) that was announced in December 2000, CL&P recorded $1.6 million in settlement income and $0.8 million in curtailment income in 2001. The VSP was intended to reduce the generation-related support staff between March 1, 2001 and February 28, 2002, and was available to non-bargaining unit employees who, by February 1, 2002, were at least age 50, with a minimum of five years of credited service, and at December 15, 2000, were assigned to certain groups and in eligible job classifications.
One component of the VSP included special pension termination benefits equal to the greater of 5 years added to both age and credited service of eligible participants or two weeks of pay for each year of service subject to a minimum level of 12 weeks and a maximum of 52 weeks for eligible participants. The special pension termination benefits expense associated with the VSP totaled $3.6 million in 2001. The net total of the settlement and curtailment income and the special termination benefits expense was $1.2 million, of which $3.3 million of costs were included in operating expenses, $2.1 million was deferred as a regulatory liability and has been returned to customers.
Postretirement Benefits Other Than Pensions (PBOP): CL&P also provides certain health care benefits, primarily medical and dental, and life insurance benefits through a benefit plan to retired employees (PBOP Plan). These benefits are available for employees retiring from CL&P who have met specified service requirements. For current employees and certain retirees, the total benefit is limited to two times the 1993 per retiree health care cost. These costs are charged to expense over the estimated work life of the employee. CL&P uses a December 31 measurement date for the PBOP Plan. CL&P annually funds postretirement costs through external trusts with amounts that have been rate-recovered and which also are tax deductible.
In 2002, the PBOP Plan was amended to change the claims experience basis, to increase minimum retiree contributions and to reduce the cap on the company's subsidy to the dental plan. These amendments resulted in a $10.6 million decrease in CL&P's benefit obligation under the PBOP Plan at December 31, 2002.
Impact of New Medicare Changes on PBOP: On December 8, 2003, the President signed into law a bill that expands Medicare, primarily by adding a prescription drug benefit starting in 2006 for Medicare-eligible retirees as well as a federal subsidy to plan sponsors of retiree health care benefit plans who provide a prescription drug benefit at least actuarially equivalent to the new Medicare benefit.
Based on the current PBOP Plan provisions, CL&P's actuaries believe that CL&P will qualify for this federal subsidy because the actuarial value of CL&P's PBOP Plan is estimated to be 60 percent greater than that of the standard Medicare benefit. CL&P will directly benefit from the federal subsidy for retirees who retired before 1991. For other retirees, management does not believe that CL&P will benefit from the subsidy because CL&P's cost support for these retirees is capped at a fixed dollar commitment.
The aggregate effect of recognizing the Medicare change is a decrease to the PBOP benefit obligation of $9.4 million. This amount includes the present value of the future government subsidy, which was estimated by discounting the expected payments using the actuarial assumptions used to determine the PBOP liability at December 31, 2003. Also included in the $9.4 million estimate is a decrease in the assumed participation in NU's retiree health plan from 95 percent to 85 percent for future retirees, which reflects the expectation that the Medicare prescription benefit will produce insurer-sponsored health plans that are more financially attractive to future retirees. The per capita claims cost estimate was not changed. Management reduced the PBOP benefit obligation as of December 31, 2003 by $9.4 million and recorded this amount as an actuarial gain within unrecognized net loss/(gain) in the tables that follow. The $9.4 million actuarial gain will be amortized beginning in 2004 as a reduction to PBOP expense over the future working lifetime of employees covered under the plan (approximately 13 years). PBOP expense in 2004 will also reflect a lower interest cost due to the reduction in the December 31, 2003 benefit obligation.
Specific authoritative guidance on accounting for the effect of the Medicare federal subsidy on PBOP plans and amounts is pending from the FASB. When issued, that guidance could require CL&P to change the accounting described above and change the information reported herein.
PBOP Settlements, Curtailments and Special Termination Benefits: There were no settlements, curtailments or special termination benefits in 2002 or 2003. In 2001, CL&P recorded PBOP special termination benefits expense of $0.7 million in connection with the VSP. This amount was recorded as a regulatory asset and collected through rates in 2002.
The following table represents information on the plans' benefit obligation, fair value of plan assets, and the respective plans' funded status:
----------------------------------------------------------------------------------------------------------
At December 31,
----------------------------------------------------------------------------------------------------------
Pension Benefits Postretirement Benefits
----------------------------------------------------------------------------------------------------------
(Millions of Dollars) 2003 2002 2003 2002
----------------------------------------------------------------------------------------------------------
Change in benefit obligation
Benefit obligation at beginning of year $(680.3) $(626.0) $(167.0) $(165.7)
Service cost (12.8) (11.7) (2.0) (2.0)
Interest cost (44.4) (44.8) (11.3) (12.0)
Medicare impact - - 9.4 -
Plan amendment - (4.5) - 10.6
Transfers 1.4 (2.2) - -
Actuarial loss (39.1) (45.2) (14.2) (16.2)
Benefits paid - excluding lump sum payments 41.7 41.5 15.8 18.3
Benefits paid - lump sum payments 2.2 20.7 - -
Special termination benefits - (8.1) - -
----------------------------------------------------------------------------------------------------------
Benefit obligation at end of year $(731.3) $(680.3) $(169.3) $(167.0)
----------------------------------------------------------------------------------------------------------
Change in plan assets
Fair value of plan assets at beginning of year $ 752.7 $ 910.4 $ 50.3 $ 55.7
Actual return on plan assets 191.9 (97.7) 13.2 (4.9)
Employer contribution - - 16.6 17.6
Transfers (1.4) 2.2 - 0.2
Benefits paid - excluding lump sum payments (41.7) (41.5) (15.8) (18.3)
Benefits paid - lump sum payments (2.2) (20.7) - -
----------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of year $ 899.3 $ 752.7 $ 64.3 $ 50.3
----------------------------------------------------------------------------------------------------------
Funded status at December 31 $ 168.0 $ 72.3 $(105.0) $(116.7)
Unrecognized transition (asset)/obligation (0.9) (1.8) 56.5 62.7
Unrecognized prior service cost 26.1 29.1 - -
Unrecognized net loss 112.1 176.6 48.5 53.6
----------------------------------------------------------------------------------------------------------
Prepaid/(accrued) benefit cost $ 305.3 $ 276.2 $ - $ (0.4)
----------------------------------------------------------------------------------------------------------
|
The accumulated benefit obligation for the Pension Plan was $645.9 million and $594.6 million at December 31, 2003 and 2002, respectively.
The following actuarial assumptions were used in calculating the plans' year end funded status:
-------------------------------------------------------------------------------
At December 31,
-------------------------------------------------------------------------------
Balance Sheets Pension Benefits Postretirement Benefits
-------------------------------------------------------------------------------
2003 2002 2003 2002
-------------------------------------------------------------------------------
Discount rate 6.25% 6.75% 6.25% 6.75%
Compensation/progression rate 3.75% 4.00% N/A N/A
Health care cost trend N/A N/A 9.00% 10.00%
-------------------------------------------------------------------------------
|
The components of net periodic (income)/expense are as follows:
------------------------------------------------------------------------------------------------------------
For the Year Ended December 31,
------------------------------------------------------------------------------------------------------------
Pension Benefits Postretirement Benefits
------------------------------------------------------------------------------------------------------------
(Millions of Dollars) 2003 2002 2001 2003 2002 2001
------------------------------------------------------------------------------------------------------------
Service cost $ 12.8 $ 11.7 $ 10.0 $ 2.0 $ 2.0 $ 1.9
Interest cost 44.4 44.8 43.7 11.3 12.0 11.1
Expected return on plan assets (84.1) (94.2) (95.3) (5.1) (5.4) (5.5)
Amortization of unrecognized net
transition (asset)/obligation (0.9) (0.9) (0.9) 6.3 6.9 7.3
Amortization of prior service cost 3.0 3.0 2.6 - - -
Amortization of actuarial gain (4.3) (15.0) (21.5) - - -
Other amortization, net - - - 2.1 1.9 (0.5)
------------------------------------------------------------------------------------------------------------
Net periodic (income)/expense - before
settlements, curtailments and special
termination benefits (29.1) (50.6) (61.4) 16.6 17.4 14.3
------------------------------------------------------------------------------------------------------------
Settlement income - - (1.6) - - -
Curtailment income - - (0.8) - - -
Special termination benefits expense - 8.1 3.6 - - 0.7
------------------------------------------------------------------------------------------------------------
Total - settlements, curtailments and special
termination benefits - 8.1 1.2 - - 0.7
------------------------------------------------------------------------------------------------------------
Total - net periodic (income)/expense $(29.1) $(42.5) $(60.2) $16.6 $17.4 $15.0
------------------------------------------------------------------------------------------------------------
|
For calculating pension and postretirement benefit income and expense amounts, the following assumptions were used:
-----------------------------------------------------------------------------------------
For the Years Ended December 31,
-----------------------------------------------------------------------------------------
Statements of Income Pension Benefits Postretirement Benefits
-----------------------------------------------------------------------------------------
2003 2002 2001 2003 2002 2001
-----------------------------------------------------------------------------------------
Discount rate 6.75% 7.25% 7.50% 6.75% 7.25% 7.50%
Expected long-term rate of return 8.75% 9.25% 9.50% 8.75% 9.25% 9.50%
Compensation/progression rate 4.00% 4.25% 4.50% N/A N/A N/A
-----------------------------------------------------------------------------------------
|
The following table represents the PBOP assumed health care cost trend rate for the next year and the assumed ultimate trend rate:
---------------------------------------------------------------------
Year Following December 31,
---------------------------------------------------------------------
2003 2002
---------------------------------------------------------------------
Health care cost trend rate
assumed for next year 8.00% 9.00%
Rate to which health care cost
trend rate is assumed to
decline (the ultimate trend rate) 5.00% 5.00%
Year that the rate reaches the
ultimate trend rate 2007 2007
---------------------------------------------------------------------
|
The annual per capita cost of covered health care benefits was assumed to decrease by one percentage point each year through 2007. Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. The effect of changing the assumed health care cost trend rate by one percentage point in each year would have the following effects:
---------------------------------------------------------------------
One Percentage One Percentage
(Millions of Dollars) Point Increase Point Decrease
---------------------------------------------------------------------
Effect on total service and
interest cost components $0.3 $(0.3)
Effect on postretirement
benefit obligation $5.3 $(4.8)
---------------------------------------------------------------------
|
CL&P's investment strategy for its Pension Plan and PBOP Plan is to maximize the long-term rate of return on those plans' assets within an acceptable level of risk. The investment strategy establishes target allocations, which are regularly reviewed and periodically rebalanced. CL&P's expected long-term rates of return on Pension Plan assets and PBOP Plan assets are based on these target asset allocation assumptions and related expected long-term rates of return. In developing its expected long-term rate of return assumptions for the Pension Plan and the PBOP Plan, CL&P also evaluated input from actuaries, consultants and economists as well as long-term inflation assumptions and CL&P's historical 20-year compounded return of approximately 11 percent. The Pension Plan's and PBOP Plan's target asset allocation assumptions and expected long-term rate of return assumptions by asset category are as follows:
-----------------------------------------------------------------------------------------------------------------
At December 31,
-----------------------------------------------------------------------------------------------------------------
Pension Benefits Postretirement Benefits
-----------------------------------------------------------------------------------------------------------------
2003 2002 2003 2002
-----------------------------------------------------------------------------------------------------------------
Target Assumed Target Assumed Target Assumed Target Assumed
Asset Rate of Asset Rate of Asset Rate of Asset Rate of
Asset Category Allocation Return Allocation Return Allocation Return Allocation Return
-----------------------------------------------------------------------------------------------------------------
Equity securities:
United States 45.00% 9.25% 45.00% 9.75% 55.00% 9.25% 55.00% 9.75%
Non-United States 14.00% 9.25% 14.00% 9.75% 11.00% 9.25% - -
Emerging markets 3.00% 10.25% 3.00% 10.75% 2.00% 10.25% - -
Private 8.00% 14.25% 8.00% 14.75% - - - -
Debt Securities:
Fixed income 20.00% 5.50% 20.00% 6.25% 27.00% 5.50% 45.00% 6.25%
High yield fixed
income 5.00% 7.50% 5.00% 7.50% 5.00% 7.50% - -
Real estate 5.00% 7.50% 5.00% 7.50% - - - -
-----------------------------------------------------------------------------------------------------------------
|
The actual asset allocations at December 31, 2003 and 2002, approximated these target asset allocations. The plans' actual weighted-average asset allocations by asset category are as follows:
--------------------------------------------------------------------------
At December 31,
--------------------------------------------------------------------------
Postretirement
Pension Benefits Benefits
--------------------------------------------------------------------------
Asset Category 2003 2002 2003 2002
--------------------------------------------------------------------------
Equity securities:
United States 47.00% 46.00% 59.00% 55.00%
Non-United States 18.00% 17.00% 12.00% -
Emerging markets 3.00% 3.00% 1.00% -
Private 3.00% 3.00% - -
Debt Securities:
Fixed income 19.00% 21.00% 25.00% 45.00%
High yield fixed
income 5.00% 5.00% 3.00% -
Real estate 5.00% 5.00% - -
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Total 100.00% 100.00% 100.00% 100.00%
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|
Currently, CL&P's policy is to annually fund an amount at least equal to that which will satisfy the requirements of the Employee Retirement Income Security Act and Internal Revenue Code.
CL&P does not expect to make any contributions to the Pension Plan in 2004 and expects to make $19.9 million in contributions to the PBOP Plan in 2004.
Postretirement health plan assets for non-union employees are subject to federal income taxes.
Seabrook: On November 1, 2002, CL&P consummated the sale of its 4.06 percent ownership interest in Seabrook to a subsidiary of FPL Group, Inc. (FPL). CL&P, North Atlantic Energy Corporation and certain other of the joint owners collectively sold 88.2 percent of Seabrook to FPL. CL&P received approximately $36 million of total cash proceeds from the sale of Seabrook. CL&P recorded a gain on the sale in the amount of approximately $16 million, which was primarily used to offset stranded costs.
In the third quarter of 2002, CL&P received regulatory approvals for the sale of Seabrook from the DPUC. As a result of this approval, CL&P eliminated $0.6 million, on an after-tax basis, of reserves related to its ownership share of certain Seabrook assets.
VYNPC: On July 31, 2002, VYNPC consummated the sale of its nuclear generating plant to a subsidiary of Entergy Corporation (Entergy) for approximately $180 million. As part of the sale, Entergy assumed responsibility for decommissioning VYNPC's nuclear generating unit. On November 7, 2003, CL&P sold its 10.1 percent ownership interest in VYNPC. CL&P will continue to buy approximately 9.5 percent of the plant's output through March 2012 at a range of fixed prices.
A. RESTRUCTURING AND RATE MATTERS Impacts of Standard Market Design: On March 1, 2003, ISO-NE implemented standard market design (SMD). As part of SMD, LMP is utilized to assign value and causation to transmission congestion and line losses.
CL&P was billed $186 million of incremental LMP costs by its standard offer service suppliers or by ISO-NE. CL&P recovered a portion of these costs through an additional charge on customer bills beginning on May 1, 2003. Billings were on a two-month lag and were recorded as operating revenues when billed. Amounts were recovered subject to refund.
CL&P and its suppliers, including affiliate Select Energy, disputed the responsibility for the $186 million in 2003 of incremental LMP costs incurred. CL&P recorded after-tax loss in 2003 of $1.3 million related to an agreement in principle to settle this dispute. On February 23, 2004, CL&P, its suppliers, and other parties reached an agreement in principle to settle the dispute. A settlement agreement is subject to approval by the FERC.
Disposition of Seabrook Proceeds: CL&P sold its share of the Seabrook nuclear unit on November 1, 2002. The net proceeds in excess of the book value of Seabrook of $16 million were recorded as a regulatory liability and, after being offset by accelerated decommissioning funding and other adjustments, will be refunded to customers. On May 1, 2003, CL&P filed its application with the DPUC for approval of the disposition of the proceeds from the sale. This filing described CL&P's treatment of its share of the proceeds from the sale. Hearings in this docket were held in September 2003, and a draft decision was received on February 3, 2004. Management does not believe that the final decision, which is expected in March 2004, will have a material effect on CL&P's net income or financial position.
CTA and SBC Reconciliation Filing: On April 3, 2003, CL&P filed its annual CTA and SBC reconciliation with the DPUC. For the year ended December 31, 2002, total CTA revenues and excess GSC revenues exceeded the CTA revenue requirement by $93.5 million. This amount was recorded as a regulatory liability. For the same period, SBC revenues exceeded the SBC revenue requirement by $22.4 million. In compliance with a prior decision of the DPUC, a portion of the SBC overcollection reduced regulatory assets, and the remaining overcollection of $18.6 million was applied to the CTA. The DPUC's December 19, 2003 transitional standard offer (TSO) decision addressed $41 million of SBC overcollections and $64 million of CTA overcollections that had been estimated as of December 31, 2003. In its decision, the DPUC ordered that $80 million of the overcollections be used to reduce CTA costs during the 2004 through 2006 TSO period. The DPUC also ordered that $25 million of the overcollections be used to offset SBC costs during the TSO period. The DPUC also ordered that $37 million of GSC overcollections be used to pay CL&P's 0.50 mill/kWh procurement fee during the TSO period.
B. NRG ENERGY, INC. EXPOSURES Certain subsidiaries of NU, including CL&P have entered into transactions with NRG Energy, Inc. (NRG) and certain of its subsidiaries. On May 14, 2003, NRG and certain of its subsidiaries filed voluntary bankruptcy petitions. On December 5, 2003, NRG emerged from bankruptcy. CL&P's NRG- related exposures as a result of these transactions relate to 1) the recovery of congestion charges incurred by NRG prior to the implementation of SMD on March 1, 2003, 2) the recovery of CL&P's station service billings to NRG, and 3) the recovery of CL&P's expenditures that were incurred related to an NRG subsidiary's generating plant construction project that is now abandoned. While it is unable to determine the ultimate outcome of these issues, management does not expect their resolution will have a material adverse effect on CL&P's consolidated financial condition or results of operations.
C. ENVIRONMENTAL MATTERS General: CL&P is subject to environmental laws and regulations intended to mitigate or remove the effect of past operations and improve or maintain the quality of the environment. These laws and regulations require the removal or the remedy of the effect on the environment of the disposal or release of certain specified hazardous substances at current and former operating sites. As such, CL&P has an active environmental auditing and training program and believes that it is substantially in compliance with all enacted laws and regulations.
Environmental reserves are accrued using a probabilistic model approach when assessments indicate that it is probable that a liability has been incurred and an amount can be reasonably estimated. The probabilistic model approach estimates the liability based on the most likely action plan from a variety of available remediation options, ranging from no action to several different remedies ranging from establishing institutional controls to full site remediation and monitoring.
These estimates are subjective in nature as they take into consideration several different remediation options at each specific site. The reliability and precision of these estimates can be affected by several factors including new information concerning either the level of contamination at the site, recently enacted laws and regulations or a change in cost estimates due to certain economic factors.
The amounts recorded as environmental liabilities on the consolidated balance sheets represent management's best estimate of the liability for environmental costs and takes into consideration site assessment and remediation costs. Based on currently available information for estimated site assessment and remediation costs at December 31, 2003 and 2002, CL&P had $7.9 million and $7.3 million, respectively, recorded as environmental reserves. A reconciliation of the total amount reserved at December 31, 2003 and 2002 is as follows:
---------------------------------------------------------------------
(Millions of Dollars) For the Years Ended December 31,
---------------------------------------------------------------------
2003 2002
---------------------------------------------------------------------
Balance at beginning of year $ 7.3 $ 1.8
Additions and adjustments 0.7 5.8
Payments (0.1) (0.3)
---------------------------------------------------------------------
Balance at end of year $ 7.9 $ 7.3
---------------------------------------------------------------------
|
These liabilities are estimated on an undiscounted basis and do not assume that any amounts are recoverable from insurance companies or other third parties. The environmental reserve includes sites at different stages of discovery and remediation and does not include any unasserted claims. At December 31, 2003, there are three sites for which there are unasserted claims; however, any related remediation costs are not probable or estimable at this time. CL&P's environmental liability also takes into account recurring costs of managing hazardous substances and pollutants, mandated expenditures to remediate previously contaminated sites and any other infrequent and non-recurring clean up costs.
CL&P currently has 11 sites included in the environmental reserve. Of those 11 sites, two sites are in the remediation or long-term monitoring phase, seven sites have had site assessments completed and the remaining two sites are in the preliminary stages of site assessment.
In addition, capital expenditures related to environmental matters are expected to total approximately $8 million in aggregate for the years 2004 through 2008. These expenditures relate to CL&P's PCB removal program.
MGP Sites: Manufactured gas plant (MGP) sites comprise the largest portion of CL&P's environmental liability. MGPs are sites that manufactured gas from coal and produced certain byproducts that may pose risk to human health and the environment. At December 31, 2003 and 2002, $6.5 million and $6.1 million, respectively, represent amounts for the site assessment and remediation of MGPs. CL&P currently has five MGP sites included in its environmental liability and one contingent MGP site of which management is aware and for which costs are not probable or estimable at this time. All of the five MGP sites are currently in the site assessment stage.
At December 31, 2003, CL&P has one site that is held for sale. The site, a former MGP site, is currently held for sale under a pending purchase and sale agreement. CL&P is currently remediating the property and has been deferring the costs associated with those remediation efforts as allowed by a regulatory order. At December 31, 2003, CL&P had $7.8 million related to remediation efforts at the property and other sale costs recorded in other deferred debits on the accompanying consolidated balance sheets.
The pending purchase and sale agreement releases CL&P from all environmental claims arising out of or in connection with the property. The purchase price in the pending purchase and sale agreement exceeds the book value of the land including the aforementioned deferred environmental remediation costs.
CERCLA Matters: The Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA) and its' amendments or state equivalents impose joint and several strict liabilities, regardless of fault, upon generators of hazardous substances resulting in removal and remediation costs and environmental damages. Liabilities under these laws can be material and in some instances may be imposed without regard to fault or for past acts that may have been lawful at the time they occurred. CL&P has two superfund sites under CERCLA for which it has been notified that it is a potentially responsible party (PRP). For sites where there are other PRPs and CL&P is not managing the site assessment and remediation, the liability accrued represents CL&P's estimate of what it will need to pay to settle its obligations with respect to the site.
It is possible that new information or future developments could require a reassessment of the potential exposure to related environmental matters. As this information becomes available management will continue to assess the potential exposure and adjust the reserves as necessary.
CL&P recovers a certain level of environmental costs currently in rates but does not have an environmental cost recovery tracking mechanism. Accordingly, changes in CL&P's environmental reserves impact CL&P's earnings.
D. SPENT NUCLEAR FUEL DISPOSAL COSTS Under the Nuclear Waste Policy Act of 1982, CL&P must pay the DOE for the disposal of spent nuclear fuel and high-level radioactive waste. The DOE is responsible for the selection and development of repositories for, and the disposal of, spent nuclear fuel and high-level radioactive waste. For nuclear fuel used to generate electricity prior to April 7, 1983 (Prior Period Fuel), an accrual has been recorded for the full liability, and payment must be made prior to the first delivery of spent fuel to the DOE. Until such payment is made, the outstanding balance will continue to accrue interest at the 3-month treasury bill yield rate. At December 31, 2003 and 2002, fees due to the DOE for the disposal of Prior Period Fuel were $207.7 million and $205.5 million, respectively, including interest costs of $141.2 million and $138.9 million, respectively.
Fees for nuclear fuel burned on or after April 7, 1983, were billed currently to customers and were paid to the DOE on a quarterly basis. At December 31, 2003, CL&P's ownership shares of Millstone and Seabrook have been sold, and CL&P is no longer responsible for fees relating to fuel burned at these facilities since their sale.
E. NUCLEAR INSURANCE CONTINGENCIES In conjunction with the divestiture of Millstone in 2001 and Seabrook in 2002, CL&P terminated its nuclear insurance related to these plants, and CL&P has no further exposure for potential assessments related to Millstone and Seabrook. However, through its continuing association with Nuclear Electric Insurance Limited (NEIL) and CYAPC, NU is subject to potential retrospective assessments totaling $0.8 million under its respective NEIL insurance policies.
F. LONG-TERM CONTRACTUAL ARRANGEMENTS VYNPC: Previously, under the terms of its agreement, CL&P paid its ownership (or entitlement) shares of costs, which included depreciation, O&M expenses, taxes, the estimated cost of decommissioning, and a return on invested capital to VYNPC and recorded these costs as purchased-power expenses. On July 31, 2002, VYNPC consummated the sale of its nuclear generating unit to a subsidiary of Entergy for approximately $180 million. Under the terms of the sale, CL&P will continue to buy approximately 9.5 percent of the plant's output through March 2012 at a range of fixed prices. The total cost of purchases under contracts with VYNPC amounted to $17.8 million in 2003, $16.4 million in 2002 and $14.7 million in 2001.
Electricity Procurement Contracts: CL&P has entered into various arrangements for the purchase of electricity. The total cost of purchases under these arrangements amounted to $157.8 million in 2003, $154.6 million in 2002 and $205 million in 2001. These amounts relate to IPP contracts and do not include contractual commitments related to CL&P's standard offer.
Hydro-Quebec: Along with other New England utilities, CL&P has entered into agreements to support transmission and terminal facilities to import electricity from the Hydro-Quebec system in Canada. CL&P is obligated to pay, over a 30-year period ending in 2020, their proportionate shares of the annual O&M expenses and capital costs of those facilities.
Estimated Future Annual Utility Group Costs: The estimated future annual costs of CL&P's significant long-term contractual arrangements are as follows:
---------------------------------------------------------------------- (Millions of Dollars) 2004 2005 2006 2007 2008 Thereafter ---------------------------------------------------------------------- VYNPC $ 17.5 $ 16.2 $16.9 $ 16.3 $ 16.6 $ 57.7 Electricity Procurement Contracts 190.9 192.1 193.7 197.2 187.5 1,057.6 Hydro-Quebec 14.5 13.8 13.0 11.8 11.4 136.8 ---------------------------------------------------------------------- Totals $222.9 $222.1 $223.6 $225.3 $215.5 $1,252.1 ---------------------------------------------------------------------- |
G. NUCLEAR DECOMMISSIONING AND PLANT CLOSURE COSTS In conjunction with the Millstone, Seabrook and VYNPC nuclear generation asset divestitures, the applicable liabilities and nuclear decommissioning trusts were transferred to the purchasers, and the purchasers agreed to assume responsibility for decommissioning their respective units.
CL&P still has significant decommissioning and plant closure cost obligations to the Yankee Companies that own the Yankee Atomic, Connecticut Yankee (CY) and Maine Yankee nuclear power plants. Each plant has been shut down and is undergoing decommissioning. The Yankee Companies collect decommissioning and closure costs through wholesale FERC-approved rates charged under power purchase agreements to CL&P. CL&P in turn passes these costs on to its customers through state regulatory commission-approved retail rates. A portion of the decommissioning and closure costs have already been collected, but a substantial portion related to the decommissioning of CY has not yet been filed at and approved for collection by the FERC.
During 2002, CL&P 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. CL&P's share of this increase is $118.9 million. Following FERC rate cases by the Yankee Companies, CL&P expects to recover the higher decommissioning costs from its retail customers.
In June 2003, CYAPC notified NU that it had terminated its contract with Bechtel Power Corporation (Bechtel) for the decommissioning of the CY nuclear power plant. CYAPC terminated the contract based on its determination that Bechtel's decommissioning work has been incomplete and untimely and that Bechtel refused to perform the remaining decommissioning work. Bechtel has filed a counterclaim against CYAPC asserting a number of claims and seeking a variety of remedies, including monetary and punitive damages and the rescission of the contract. Bechtel has amended its complaint to add claims for wrongful termination.
In November 2003, CYAPC prepared an updated estimate of the cost of decommissioning its nuclear unit. CL&P's aggregate share of the estimated increased cost, primarily related to the termination of Bechtel, is $118.1 million.
CYAPC is seeking recovery of additional decommissioning costs and other damages from Bechtel and, if necessary, its surety. In pursuing this recovery through pending litigation, CYAPC is also exploring options to structure an appropriate rate application to be filed with the FERC, with any resulting adjustments being charged to the owners of the nuclear unit, including CL&P. The timing, amount and outcome of these filings cannot be predicted at this time.
CL&P 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 CL&P's customers, 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 FERC does not allow these costs to be recovered in wholesale rates, CL&P would expect the state regulatory commissions to disallow these costs in retail rates as well.
At December 31, 2003 and 2002, CL&P's remaining estimated obligations for decommissioning and closure costs for the shut down units owned by CYAPC, YAEC and MYAPC were $318 million and $234.5 million, respectively.
The following methods and assumptions were used to estimate the fair value of each of the following financial instruments:
Restricted Cash - LMP: The carrying amounts approximate fair value due to the short-term nature of this cash item.
Preferred Stock, Long-Term Debt and Rate Reduction Bonds: The fair value of CL&P's fixed-rate securities is based upon the quoted market price for those issues or similar issues. Adjustable rate securities are assumed to have a fair value equal to their carrying value. The carrying amounts of CL&P's financial instruments and the estimated fair values are as follows:
---------------------------------------------------------------------
At December 31, 2003
---------------------------------------------------------------------
(Millions of Dollars) Carrying Amount Fair Value
---------------------------------------------------------------------
Preferred stock not subject
to mandatory redemption $ 116.2 $ 87.5
Long-term debt -
First mortgage bonds 198.8 244.9
Other long-term debt 631.6 650.1
Rate reduction bonds 1,124.8 1,197.5
---------------------------------------------------------------------
---------------------------------------------------------------------
At December 31, 2002
---------------------------------------------------------------------
(Millions of Dollars) Carrying Amount Fair Value
---------------------------------------------------------------------
Preferred stock not subject
to mandatory redemption $ 116.2 $ 84.0
Long-term debt -
First mortgage bonds 198.8 242.0
Other long-term debt 629.4 643.0
Rate reduction bonds 1,245.7 1,356.1
---------------------------------------------------------------------
|
Other long-term debt includes $207.7 million and $205.5 million of fees and interest due for spent nuclear fuel disposal costs at December 31, 2003 and 2002, respectively.
Other Financial Instruments: The carrying value of financial instruments included in current assets and current liabilities, including investments in securitizable assets, approximates their fair value.
CL&P has entered into lease agreements, some of which are capital leases, for the use of data processing and office equipment, vehicles, and office space. The provisions of these lease agreements generally provide for renewal options.
Capital lease rental payments charged to operating expense were $3.1 million in 2003, $3 million in 2002, and $9.2 million in 2001. Interest included in capital lease rental payments was $2 million in 2003 and 2002, and $3.4 million in 2001. Operating lease rental payments charged to expense were $7.3 million in 2003, $6.9 million in 2002, and $7.1 million in 2001.
Future minimum rental payments excluding executory costs, such as property taxes, state use taxes, insurance, and maintenance, under long-term noncancelable leases, at December 31, 2003 are as follows:
--------------------------------------------------------------------- (Millions of Dollars) Capital Operating Year Leases Leases --------------------------------------------------------------------- 2004 $ 2.6 $ 11.8 2005 2.6 11.2 2006 2.5 10.1 2007 2.4 9.0 2008 2.1 8.3 Thereafter 20.1 16.4 --------------------------------------------------------------------- Future minimum lease payments $32.3 $66.8 Less amount representing interest 17.4 --------------------------------------------------------------------- Present value of future minimum lease payments $14.9 --------------------------------------------------------------------- |
The accumulated balance for each other comprehensive income/(loss) item is as follows:
-----------------------------------------------------------------------
Current
December 31, Period December 31,
(Millions of Dollars) 2002 Change 2003
-----------------------------------------------------------------------
Unrealized
(losses)/gains
on securities $(0.1) $ 0.2 $ 0.1
Minimum supplemental
executive retirement
pension liability
adjustments (0.3) (0.1) (0.4)
-----------------------------------------------------------------------
Accumulated other
comprehensive
(loss)/income $(0.4) $ 0.1 $(0.3)
-----------------------------------------------------------------------
-----------------------------------------------------------------------
Current
December 31, Period December 31,
(Millions of Dollars) 2001 Change 2002
-----------------------------------------------------------------------
Unrealized
gains/(losses)
on securities $ 0.4 $(0.5) $(0.1)
Minimum supplemental
executive retirement
pension liability
adjustments (0.3) - (0.3)
-----------------------------------------------------------------------
Accumulated other
comprehensive
income/(loss) $ 0.1 $(0.5) $(0.4)
-----------------------------------------------------------------------
|
The changes in the components of other comprehensive income/(loss) are reported net of the following income tax effects:
----------------------------------------------------------------------- (Millions of Dollars) 2003 2002 2001 ----------------------------------------------------------------------- Unrealized (losses)/gains on securities $(0.1) $0.3 $0.3 Minimum supplemental executive retirement pension liability adjustments - - - ----------------------------------------------------------------------- Accumulated other comprehensive (loss)/income $(0.1) $0.3 $0.3 ----------------------------------------------------------------------- |
Details of preferred stock not subject to mandatory redemption are as follows:
-------------------------------------------------------------------------------
Shares
December 31, Outstanding
2003 at December 31,
Redemption December 31, ----------------
Description Price 2003 2003 2002
-------------------------------------------------------------------------------
(Millions of Dollars)
$1.90 Series
of 1947 $52.50 163,912 $ 8.2 $ 8.2
$2.00 Series
of 1947 54.00 336,088 16.8 16.8
$2.04 Series
of 1949 52.00 100,000 5.0 5.0
$2.20 Series
of 1949 52.50 200,000 10.0 10.0
3.90% Series
of 1949 50.50 160,000 8.0 8.0
$2.06 Series E
of 1954 51.00 200,000 10.0 10.0
$2.09 Series F
of 1955 51.00 100,000 5.0 5.0
4.50% Series
of 1956 50.75 104,000 5.2 5.2
4.96% Series
of 1958 50.50 100,000 5.0 5.0
4.50% Series
of 1963 50.50 160,000 8.0 8.0
5.28% Series
of 1967 51.43 200,000 10.0 10.0
$3.24 Series G
of 1968 51.84 300,000 15.0 15.0
6.56% Series
of 1968 51.44 200,000 10.0 10.0
-------------------------------------------------------------------------------
Totals $116.2 $116.2
-------------------------------------------------------------------------------
|
Details of long-term debt outstanding are as follows:
-------------------------------------------------------------------------------
At December 31, 2003 2002
-------------------------------------------------------------------------------
(Millions of Dollars)
First Mortgage Bonds:
8.50% Series C due 2024 $ 59.0 $ 59.0
7.875% Series D due 2024 139.8 139.8
-------------------------------------------------------------------------------
Total First Mortgage Bonds 198.8 198.8
-------------------------------------------------------------------------------
Pollution Control Notes:
5.85%-5.90%, fixed rate,
due 2016-2022 46.4 46.4
5.85%-5.95%, fixed rate
tax exempt, due 2028 315.5 315.5
Variable rate, tax exempt, due 2031 62.0 62.0
-------------------------------------------------------------------------------
Total Pollution Control Notes 423.9 423.9
-------------------------------------------------------------------------------
Total First Mortgage Bonds and
Pollution Control Notes 622.7 622.7
-------------------------------------------------------------------------------
Fees and interest due for spent
nuclear fuel disposal costs 207.7 205.5
-------------------------------------------------------------------------------
Less amounts due within one year - -
Unamortized premium and
discount, net (0.3) (0.3)
-------------------------------------------------------------------------------
Long-term debt $830.1 $827.9
-------------------------------------------------------------------------------
|
Essentially, all utility plant of CL&P is subject to the liens of the company's first mortgage bond indenture.
CL&P has $315.5 million of pollution control notes secured by second mortgage liens on transmission assets, junior to the liens of their first mortgage bond indentures.
CL&P has $62 million of tax-exempt Pollution Control Revenue Bonds (PCRBs) with bond insurance secured by the first mortgage bonds. For financial reporting purposes, these first mortgage bonds would not be considered outstanding unless CL&P failed to meet its obligations under the PCRBs. On October 1, 2003, CL&P fixed the interest rate on $62 million of variable- rate, tax-exempt notes for five years at 3.35 percent. These notes mature in 2031.
The average effective interest rates on the variable-rate PCRBs, which were fixed in 2003, ranged from 1 percent to 1.9 percent for 2002.
The components of the federal and state income tax provisions were charged/(credited) to operations as follows:
-------------------------------------------------------------------------------
For the Years
Ended December 31, 2003 2002 2001
-------------------------------------------------------------------------------
(Millions of Dollars)
Current income taxes:
Federal $ 115.0 $114.4 $190.7
State 28.8 24.3 38.8
-------------------------------------------------------------------------------
Total current 143.8 138.7 229.5
-------------------------------------------------------------------------------
Deferred income taxes, net:
Federal (82.7) (53.3) (117.0)
State (33.2) (15.2) (23.8)
-------------------------------------------------------------------------------
Total deferred (115.9) (68.5) (140.8)
-------------------------------------------------------------------------------
Investment tax credits, net (2.5) (3.3) (3.8)
-------------------------------------------------------------------------------
Total income tax expense $ 25.4 $ 66.9 $ 84.9
-------------------------------------------------------------------------------
|
Deferred income taxes are comprised of the tax effects of temporary differences as follows:
-------------------------------------------------------------------------------
For the Years
Ended December 31, 2003 2002 2001
-------------------------------------------------------------------------------
(Millions of Dollars)
Depreciation $ 23.5 $ 34.4 $ (9.2)
Net regulatory deferral (128.9) (68.3) (33.1)
Regulatory disallowance 0.4 0.3 -
Sale of generation assets - (18.4) (197.6)
Pension (deferral)/accrual (1.4) (6.3) 19.9
Contract termination
costs, net of amortization (6.5) (5.9) 63.4
Other (3.0) (4.3) 15.8
-------------------------------------------------------------------------------
Deferred income taxes, net $(115.9) $(68.5) $(140.8)
-------------------------------------------------------------------------------
|
A reconciliation between income tax expense and the expected tax expense at the statutory rate is as follows:
-------------------------------------------------------------------------------
For the Years
Ended December 31, 2003 2002 2001
-------------------------------------------------------------------------------
(Millions of Dollars)
Expected federal income tax $33.0 $53.4 $68.1
Tax effect of differences:
Depreciation (0.3) 3.8 10.7
Amortization of
regulatory assets 3.7 13.7 1.6
Investment tax credit
amortization (2.5) (3.3) (3.8)
State income taxes,
net of federal benefit (2.9) 5.9 9.8
Tax reserve adjustments (5.5) (1.3) (9.1)
Other, net (0.1) (5.3) 7.6
-------------------------------------------------------------------------------
Total income tax expense $25.4 $66.9 $84.9
-------------------------------------------------------------------------------
|
NU is organized between the Utility Group and NU Enterprises based on each segments' regulatory environment or lack thereof. CL&P is included in the Utility Group segment of NU and has no other reportable segments.
------------------------------------------------------------------------------- 2003 March 31, June 30, September 30, December 31, ------------------------------------------------------------------------------- Operating Revenues $705,916 $615,268 $797,896 $585,445 Operating Income $ 69,087 $ 38,299 $ 73,151 $ 19,835 Net Income $ 26,722 $ 6,064 $ 30,431 $ 5,691 ------------------------------------------------------------------------------- 2002 ------------------------------------------------------------------------------- Operating Revenues $604,420 $581,731 $687,938 $632,947 Operating Income $ 64,111 $ 45,528 $ 72,946 $ 68,743 Net Income $ 21,684 $ 11,407 $ 29,297 $ 23,224 ------------------------------------------------------------------------------- |
-------------------------------------------------------------------------------------------------------------------------------- Selected Consolidated Financial Data (Unaudited) -------------------------------------------------------------------------------------------------------------------------------- (Thousands of Dollars) 2003 2002 2001 2000 1999 -------------------------------------------------------------------------------------------------------------------------------- Operating Revenues $2,704,525 $2,507,036 $2,646,123 $2,935,922 $2,452,855 Net Income/(Loss) 68,908 85,612 109,803 148,135 (13,568) Cash Dividends on Common Stock 60,110 60,145 60,072 72,014 - Gross Property, Plant and Equipment (b) 3,580,071 3,292,684 3,265,811 5,964,605 6,007,421 Total Assets (c) 5,206,894 4,786,083 4,727,727 4,764,198 5,298,284 Rate Reduction Bonds 1,124,779 1,245,728 1,358,653 - - Long-Term Debt (d) 830,149 827,866 824,349 1,232,688 1,400,056 Preferred Stock Not Subject to Mandatory Redemption 116,200 116,200 116,200 116,200 116,200 Preferred Stock Subject to Mandatory Redemption (d) - - - - 99,539 Obligations Under Capital Leases (d) 14,879 15,499 16,040 129,869 144,400 -------------------------------------------------------------------------------------------------------------------------------- |
--------------------------------------------------------------------------------------------------------------------------------
Consolidated Statistics (Unaudited)
--------------------------------------------------------------------------------------------------------------------------------
2003 2002 2001 2000 1999
--------------------------------------------------------------------------------------------------------------------------------
Revenues: (Thousands)
Residential $1,151,707 $1,028,425 $ 991,946 $ 965,528 $1,014,215
Commercial 960,678 874,713 855,348 823,130 850,729
Industrial 290,526 274,228 285,479 285,877 291,062
Other Utilities 322,955 271,484 420,664 745,399 235,688
Streetlighting and Railroads 35,359 33,788 33,356 34,967 34,807
Non-franchised Sales - - - 1,390 4,125
Miscellaneous (56,700) 24,398 59,330 79,631 22,229
--------------------------------------------------------------------------------------------------------------------------------
Total $2,704,525 $2,507,036 $2,646,123 $2,935,922 $2,452,855
--------------------------------------------------------------------------------------------------------------------------------
Sales: (kWh - Millions)
Residential 10,359 9,699 9,340 9,084 9,071
Commercial 9,829 9,644 9,460 9,037 8,973
Industrial 3,630 3,707 3,850 4,000 4,004
Other Utilities 5,885 6,281 9,709 19,713 6,919
Streetlighting and Railroads 298 292 286 286 267
Non-franchised Sales - - - 59 83
--------------------------------------------------------------------------------------------------------------------------------
Total 30,001 29,623 32,645 42,179 29,317
--------------------------------------------------------------------------------------------------------------------------------
Customers: (Average)
Residential 1,058,247 1,048,096 1,050,633 1,022,466 1,022,005
Commercial 104,750 103,408 95,782 92,303 92,046
Industrial 3,989 4,035 4,028 3,983 3,987
Other 2,643 2,768 2,791 2,799 2,808
--------------------------------------------------------------------------------------------------------------------------------
Total 1,169,629 1,158,307 1,153,234 1,121,551 1,120,846
--------------------------------------------------------------------------------------------------------------------------------
Average Annual Use Per
Residential Customer (kWh) 9,790 9,244 8,884 8,976 8,969
--------------------------------------------------------------------------------------------------------------------------------
Average Annual Bill Per
Residential Customer $1,089.63 $979.86 $943.48 $954.15 $1,002.73
--------------------------------------------------------------------------------------------------------------------------------
Average Revenue Per kWh:
Residential 11.13 cents 10.60 cents 10.62 cents 10.63 cents 11.18 cents
Commercial 9.77 9.07 9.04 9.11 9.48
Industrial 8.00 7.40 7.42 7.15 7.27
--------------------------------------------------------------------------------------------------------------------------------
Employees 2,141 2,130 2,160 2,057 2,377
--------------------------------------------------------------------------------------------------------------------------------
|
(a) Certain reclassifications of prior years' data have been made to conform
with the current year's presentation.
(b) Amount includes construction work in progress.
(c) Total assets were not adjusted for cost of removal prior to 2002.
(d) Includes portions due within one year.
EXHIBIT 13.3
2003 Annual Report
Public Service Company of New Hampshire
Index
Contents Page -------- ---- Management's Discussion and Analysis of Financial Condition and Results of Operations.............................. 1 Independent Auditors' Report....................................... 12 Consolidated Balance Sheets........................................ 14-15 Consolidated Statements of Income.................................. 16 Consolidated Statements of Comprehensive Income.................... 16 Consolidated Statements of Common Stockholder's Equity............. 17 Consolidated Statements of Cash Flows.............................. 18 Notes to Consolidated Financial Statements......................... 19 Consolidated Quarterly Financial Data (Unaudited).................. 32 Selected Consolidated Financial Data (Unaudited)................... 32 Consolidated Statistics (Unaudited)................................ 33 Bondholder Information............................................. Back Cover |
MANAGEMENT'S DISCUSSION AND ANALYSIS
OVERVIEW
Public Service Company of New Hampshire (PSNH or the company), a wholly owned
subsidiary of Northeast Utilities (NU), earned $45.6 million in 2003,
compared with $62.9 million in 2002 and $81.8 million in 2001. The 2003
decline in earnings is due to a lower level of regulatory assets earning a
return, the positive resolution of certain contingencies related to a
regulatory proceeding decided in 2002, and higher pension costs. The lower
2002 net income was largely due to an after-tax gain of $15.5 million PSNH
recorded in 2001 as a result of the sale of PSNH's share of the Millstone 3
nuclear unit (Millstone).
NU's other subsidiaries include The Connecticut Light and Power Company (CL&P), Western Massachusetts Electric Company, Yankee Energy System, Inc., North Atlantic Energy Corporation (NAEC), Select Energy, Inc., Northeast Generation Company, Northeast Generation Services Company, and Select Energy Services, Inc. PSNH purchased all of NAEC's entitlement to the capacity and output of the Seabrook nuclear unit (Seabrook) under two full cost recovery contracts (Seabrook Power Contracts) through the sale of Seabrook on November 1, 2002.
During 2003, pre-tax pension expense for PSNH increased $6.2 million, from $0.6 million in 2002 to $6.8 million in 2003. Of the $6.8 million and $0.6 million of pension expense recorded during 2003 and 2002, $4.8 million and $0.4 million, respectively, were recognized in the consolidated statements of income. The remaining $2 million in 2003 and $0.2 million in 2002 relate to employees working on capital projects and were reflected as capital expenditures. The pre-tax $4.4 million increase in pension expense was reflected evenly throughout 2003, resulting in a decline of $0.7 million in net income per quarter during 2003.
PSNH's revenues for 2003 decreased to $888.2 million from $947.2 million in 2002. The decrease in revenues is primarily due to lower wholesale revenues as a result of NAEC's sale of its share of Seabrook in November 2002, the cancellation of the Seabrook Power Contracts and PSNH's related loss of Seabrook output, some of which was sold. The reduction in wholesale revenues was partially offset by increases in electric sales in 2003 as compared to 2002.
As a result of an adjustment to estimated unbilled electric revenues resulting from a process to validate and update the assumptions used to estimate unbilled revenues, 2003 PSNH retail electric sales increased 4.7 percent compared to 2002. Absent that adjustment, PSNH retail electric sales increased 4 percent. The adjustment to PSNH's estimated unbilled revenues increased PSNH's net income by $3.3 million for 2003. For further information regarding the estimate of unbilled revenues, see "Critical Accounting Policies and Estimates - Unbilled Revenues," included in this Management's Discussion and Analysis.
FUTURE OUTLOOK
PSNH is expected to have reduced earnings in 2004 compared to 2003 partially
as a result of a continued increase in pension expense. In 2004, PSNH is
projecting to record pre-tax pension expense of approximately $10.6 million
as compared to pension expense of $6.8 million in 2003. Pension expense is
annually adjusted during the second quarter based on updated actuarial
valuations, and the 2004 estimate may change.
PSNH's 2004 earnings will also be impacted by uncertainties over the outcome of a pending PSNH rate case before the New Hampshire Public Utilities Commission (NHPUC) and the outcome of the transmission rate case before the Federal Energy Regulatory Commission (FERC). Management expects both cases to be decided in the second half of 2004.
LIQUIDITY
PSNH's net cash flows provided by operating activities totaled $82.2 million
in 2003 as compared to $325 million in 2002 and $271.7 million in 2001. Cash
flows provided by operating activities in 2003 decreased due to decreases in
working capital items. Seabrook was sold on November 1, 2002 and taxes of
$93 million were paid in March of 2003. The decrease in these working
capital items were offset by an increase in regulatory recoveries in 2003
as compared to 2002, primarily associated with PSNH's Stranded Cost Recovery
Charge (SCRC). For a description of the costs recovered through this
mechanism, see Note 1G, "Summary of Significant Accounting Policies -
Regulatory Accounting," to the consolidated financial statements.
Cash flows provided by operating activities increased in 2002 primarily due to changes in working capital, primarily accrued taxes and accounts payable, partially offset by the decrease in net income in 2002. The increase in accrued taxes relates primarily to the refund PSNH received from NAEC related to the gain on the sale of Seabrook.
There was a comparable level of investing and financing activity in 2003 as compared to 2002, except for $37 million for the repurchase of common shares and the issuance of rate reduction bonds in 2002. The level of common dividends totaled $16.8 million in 2003, $45 million in 2002 and $27 million in 2001.
There was a lower level of financing activities in 2002 as compared to 2001, primarily due to the issuance and retirements of long-term debt and rate reduction bonds.
Aside from the rate reduction bonds outstanding, no PSNH debt issues mature during the eight-year period of 2004 through 2011.
Capital spending at PSNH totaled $105.6 million in 2003, compared with $108.7 million in 2002. In 2003, PSNH spent over $20 million to buy down contracts with 14 small power producers and funded $30.1 million to acquire the assets of Connecticut Valley Electric Company (CVEC) and buy out a related wholesale power contract. The $30.1 million was placed in escrow at December 31, 2003 and is included in special deposits on the accompanying consolidated balance sheets. PSNH expects to increase its capital spending to approximately $160 million in 2004, assuming it receives satisfactory regulatory approval for a $70 million conversion of a 50 megawatt generating unit at its Schiller Station to burn wood chips. Such a level of spending is likely to require PSNH to issue in 2004 its first new debt since it exited bankruptcy in 1991.
In November 2003, PSNH renewed a $300 million credit line under terms similar to the previous arrangement that expired in November 2003. PSNH can borrow up to $100 million and had $10 million in borrowings outstanding on this credit line at December 31, 2003.
Rate reduction bonds are included on the consolidated balance sheets of PSNH, even though the debt is non-recourse to PSNH. At December 31, 2003, PSNH had a total of $472.2 million in rate reduction bonds outstanding, compared with $510.8 million outstanding at December 31, 2002. All outstanding rate reduction bonds of PSNH are scheduled to fully amortize by May 1, 2013. Interest on the bonds totaled $29.1 million in 2003, compared with $30.5 million in 2002 and $20.7 million in 2001, the year of issuance. Cash flows from the amortization of rate reduction bonds totaled $40 million in 2003, compared with $42.7 million in 2002 and $26.8 million in 2001. Over the next several years, retirement of rate reduction bonds will increase, and interest payments will steadily decrease, resulting in no material changes to debt service costs on the existing issues. PSNH fully recovers the amortization and interest payments from customers through stranded cost revenues each year, and the bonds have no impact on net income. Moreover, as the rate reduction bonds are non-recourse, the three rating agencies that rate the debt of PSNH do not reflect the revenues, expenses, or outstanding securities related to the rate reduction bonds in establishing the credit ratings of PSNH.
The retirement of rate reduction bonds does not equal the amortization of rate reduction bonds because the retirement represents principal payments, while the amortization represents amounts recovered from customers for future principal payments. The timing of recovery does not exactly match the expected principal payments.
BUSINESS DEVELOPMENT AND CAPITAL EXPENDITURES
PSNH capital spending totaled $105.6 million in 2003 and is projected to
total $160 million in 2004. The primary reason for the increase is PSNH's
proposal to convert a 50 megawatt oil and coal burning unit at Schiller
Station in Portsmouth, New Hampshire to burn wood chips. The $70 million
project will commence if PSNH receives satisfactory approval from the NHPUC.
PSNH believes that the conversion can be accomplished without impacting
retail rates because of certain government incentives to promote renewable
resource projects. Another reason for the projected increase in capital
spending is PSNH's transmission projects.
Effective January 1, 2004, PSNH completed the purchase of the electric system and retail franchise of CVEC, a subsidiary of Central Vermont Public Service Corporation (CVPS), for $30.1 million. CVEC's 11,000 customers in western New Hampshire have been added to PSNH's customer base of more than 460,000 customers. The purchase price included the book value of CVEC's plant assets of approximately $9 million and an additional $21 million to terminate an above-market wholesale power purchase agreement CVEC had with CVPS. CVEC is expected to add approximately $1.1 million to PSNH's annual earnings.
REGIONAL TRANSMISSION ORGANIZATION
The FERC has required all transmission owning utilities, including PSNH, to
voluntarily form regional transmission organizations (RTOs) or to state why
this process has not begun.
On October 31, 2003, the New England Independent System Operator (ISO-NE), along with NU (including PSNH), and six other New England transmission companies filed a proposal with the FERC to create a RTO for New England. The RTO is intended to strengthen the independent and efficient management of the region's power system while ensuring that customers in New England continue to have the most reliable system possible to realize the benefits of a competitive wholesale energy market.
ISO-NE, as a RTO, will have a new independent governance structure and will also become the transmission provider for New England by exercising operational control over New England's transmission facilities pursuant to a detailed contractual arrangement with the New England transmission owners. Under this contractual arrangement, the RTO will have clear authority to direct the transmission owners to operate their facilities in a manner that preserves system reliability, including requiring transmission owners to expand existing transmission lines or build new ones when needed for reliability. Transmission owners will retain their rights over revenue requirements, rates and rate designs. The filing requests that the FERC approve the RTO arrangements for an effective date of March 1, 2004.
In a separate filing made on November 4, 2003, NU including PSNH, along with six other New England transmission owners requested, consistent with the FERC's pricing policy for RTOs and Order-2000-compliant independent system operators, that the FERC approve a single return on equity (ROE) for regional and local rates that would consist of a base ROE as well as incentive adders of 50 basis points for joining a RTO and 100 basis points for constructing new transmission facilities approved by the RTO. If the FERC approves the request, then the transmission owners would receive a 13.3 percent ROE for existing transmission facilities and a 14.3 percent ROE for new transmission facilities. The outcome of this request and its impact on PSNH cannot be determined at this time.
RESTRUCTURING AND RATE MATTERS
On August 26, 2003, NU's electric operating companies, including PSNH, filed
their first transmission rate case at the FERC since 1995. In the filing, NU
requested implementation of a formula rate that would allow recovery of
increasing transmission expenditures on a timelier basis and that the
changes, including a $23.7 million annual rate increase through 2004, take
effect on October 27, 2003. NU requested that the FERC maintain NU's
existing 11.75 percent ROE until a ROE for the New England RTO is
established by the FERC. On October 22, 2003, the FERC accepted this filing
implementing the proposed rates subject to refund effective on October 28,
2003. A final decision in the rate case is expected in 2004.
Increasing transmission rates are generally recovered from distribution companies through FERC-approved transmission rates. Electric distribution companies pass through higher transmission rates to retail customers as approved by the NHPUC. PSNH requested a tracking mechanism from the NHPUC when it filed its rate case on December 29, 2003, which will allow it to recover changes in transmission expenses on a timely basis.
Transition Energy Service: In accordance with the "Agreement to Settle PSNH Restructuring" (Restructuring Settlement) and state law, PSNH must file for updated transition energy service (TS) rates annually. The TS rate recovers PSNH's generation and purchased power costs, including a return on PSNH's generation investment. During the February 1, 2004 through January 31, 2005 time period when current rates will be effective, PSNH will defer any difference between its TS revenues and the actual costs incurred. On December 19, 2003, the NHPUC approved a $0.0536 per kilowatt-hour (kWh) TS rate effective February 1, 2004.
Delivery Rate Case: PSNH's delivery rates were fixed by the Restructuring Settlement until February 1, 2004. Consistent with the requirements of the Restructuring Settlement and state law, PSNH filed a delivery service rate case and tariffs with the NHPUC on December 29, 2003 to increase electricity delivery rates by approximately $21 million, or approximately 2.6 percent, effective February 1, 2004. In addition, PSNH is requesting that recovery of FERC-regulated transmission costs be adjusted annually through a tracking mechanism. The NHPUC suspended the proposed rate increase until the conclusion of the delivery rate case. Hearings are expected in August 2004, and a decision is expected in the third quarter of 2004 with rates retroactively applied to February 1, 2004.
SCRC Reconciliation Filings: On an annual basis, PSNH files with the NHPUC a SCRC reconciliation filing for the preceding calendar year. This filing includes the reconciliation of stranded cost revenues with stranded costs, and TS revenues with TS costs. The NHPUC reviews the filing, including a prudence review of PSNH's generation operations.
On May 1, 2003, PSNH filed with the NHPUC an SCRC reconciliation filing for the period January 1, 2002, through December 31, 2002. This filing included the reconciliation of stranded cost revenues with stranded costs and a net proceeds calculation related to the sale of NAEC's share of Seabrook and the subsequent transfer of those net proceeds to PSNH. Upon the completion of discovery and technical sessions with the NHPUC staff and the New Hampshire Office of the Consumer Advocate (OCA), PSNH, the NHPUC Staff and the OCA entered into a stipulation and settlement agreement that was filed with the NHPUC on September 15, 2003. An order from the NHPUC approving the settlement agreement on October 24, 2003 did not have a material impact on PSNH's net income or financial position.
The 2003 SCRC filing is expected to be filed on May 1, 2004. Management does not expect the review of the 2003 SCRC filing to have a material effect on PSNH's net income or financial position. The recovery of stranded costs is expected to be a significant source of cash flow for PSNH through 2007. On May 22, 2003, the NHPUC issued an order approving a settlement between PSNH, owners of 14 small hydroelectric power producers, the NHPUC staff and the OCA calling for the termination of PSNH's obligations to purchase power from the hydroelectric units at above market prices. On May 30, 2003, under the terms of this settlement, PSNH made lump sum payments to those owners amounting to $20.4 million. The buyout payments were recorded as regulatory assets and will be recovered, including a return, over the initial term of the obligations as Part 2 stranded costs. PSNH is entitled to retain 20 percent of the estimated savings from the buyouts. PSNH is expected to recover $21 million of the purchase price of CVEC over the next three to four years.
For information regarding commitments and contingencies related to restructuring and rate matters, see Note 7A, "Commitments and Contingencies - Restructuring and Rate Matters," to the consolidated financial statements.
NUCLEAR GENERATION ASSET DIVESTITURES
Millstone: On March 31, 2001, PSNH sold its ownership interest in Millstone.
Vermont Yankee: On July 31, 2002, Vermont Yankee Nuclear Power Corporation (VYNPC) consummated the sale of its nuclear generating unit. In November 2003, PSNH sold back to VYNPC its shares of stock for approximately $0.4 million. PSNH continues to purchase approximately 4 percent of the plant's output under a new contract.
Nuclear Decommissioning and Plant Closure Costs: Although the purchasers of PSNH's ownership shares of the Millstone and Vermont Yankee plants assumed the obligation of decommissioning those plants, PSNH still has significant decommissioning and plant closure cost obligations to the companies that own the Yankee Atomic, Connecticut Yankee (CY) and Maine Yankee plants (collectively Yankee Companies). Each plant has been shut down and is undergoing decommissioning. The Yankee Companies collect decommissioning and closure costs through wholesale FERC-approved rates charged under a power purchase agreement with PSNH. PSNH in turn passes these costs on to its customers through state regulatory commission-approved retail rates. A portion of the decommissioning and closure costs have already been collected, but a substantial portion related to the decommissioning of CY has not yet been filed at and approved for collection by the FERC. The cost estimate for CY that has not yet been approved for recovery by FERC at December 31, 2003 is $26.3 million.
PSNH cannot at this time predict the timing or outcome of the FERC proceeding required for the collection of these remaining decommissioning and closure costs or the Bechtel Power Corporation litigation referred to in Note 7E, "Commitments and Contingencies - Nuclear Decommissioning and Plant Closure Costs," to the consolidated financial statements. Although management believes that these costs will ultimately be recovered from PSNH's customers, 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 FERC does not allow these costs to be recovered in wholesale rates, PSNH would expect the state regulatory commissions to disallow these costs in retail rates as well.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States of America requires
management to make estimates, assumptions and at times difficult, subjective
or complex judgments. Changes in these estimates, assumptions and judgments,
in and of themselves, could materially impact the financial statements of
PSNH. Management communicates to and discusses with NU's Audit Committee of
the Board of Trustees all critical accounting policies and estimates. The
following are the accounting policies and estimates that management believes
are the most critical in nature.
Presentation: In accordance with current accounting pronouncements, PSNH's consolidated financial statements include all subsidiaries which control is maintained and all variable interest entities for which PSNH is the primary beneficiary, as defined. All intercompany transactions between these subsidiaries are eliminated as part of the consolidation process.
PSNH has less than 50 percent ownership interests in the Connecticut Yankee Atomic Power Company, Yankee Atomic Electric Company, and Maine Yankee Atomic Power Company. PSNH does not control these companies and does not consolidate them in its financial statements. PSNH accounts for the investments in these companies using the equity method. Under the equity method, PSNH records its ownership share of the earnings or losses at these companies. Determining whether or not PSNH should apply the equity method of accounting for an investee company requires management judgment.
The required adoption date of Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 46, "Consolidation of Variable Interest Entities" was delayed from July 1, 2003 to December 31, 2003 for PSNH. However, PSNH elected to adopt FIN 46 at the original adoption date. The adoption of FIN 46 had no impact on PSNH. In December 2003, the FASB issued a revised version of FIN 46 (FIN 46R). FIN 46R is effective for PSNH for the first quarter of 2004, but is not expected to have an impact on PSNH's consolidated financial statements.
Revenue Recognition: PSNH retail revenues are based on rates approved by the NHPUC. These regulated rates are applied to customers' use of energy to calculate a bill. In general, rates can only be changed through formal proceedings with the NHPUC.
PSNH utilizes regulatory commission-approved tracking mechanisms to track the recovery of certain incurred costs. The tracking mechanisms allow for rates to be changed periodically, with overcollections refunded to customers or underrecollections collected from customers in future periods.
The determination of the energy sales to individual customers is based on the reading of meters, which occurs on a systematic basis throughout the month. Billed revenues are based on these meter readings. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated, and an estimated amount of unbilled revenues is recorded.
Wholesale transmission revenues are based on rates and formulas that are approved by the FERC. Most of PSNH's wholesale transmission revenues are collected through a combination of the New England Regional Network Service (RNS) tariff and PSNH's Local Network Service (LNS) tariff. The RNS tariff, which is administered by ISO-NE, recovers the revenue requirements associated with transmission facilities that are deemed by the FERC to be Pool Transmission Facilities. The LNS tariff which was accepted by the FERC on October 22, 2003, provides for the recovery of PSNH's total transmission revenue requirements, net of revenue credits received from various rate components, including revenues received under the RNS rates.
The settlement of wholesale non-trading derivative contracts for the sale of energy by PSNH that are not related to customers' needs are recorded in operating expenses.
Unbilled Revenues: Unbilled revenues represent an estimate of electricity delivered to customers that has not been billed. Unbilled revenues represent assets on the balance sheet that become accounts receivable in the following month as customers are billed.
The estimate of unbilled revenues is sensitive to numerous factors that can significantly impact the amount of revenues recorded. Estimating the impact of these factors is complex and requires management's judgment. The estimate of unbilled revenues is important to PSNH's consolidated financial statements as adjustments to that estimate could significantly impact operating revenues and earnings. Two potential methods for estimating unbilled revenues are the requirements and the cycle method.
PSNH estimates unbilled revenues monthly using the requirements method. The requirements method utilizes the total monthly volume of electricity delivered to the system and applies a delivery efficiency (DE) factor to reduce the total monthly volume by an estimate of delivery losses in order to calculate total estimated monthly sales to customers. The total estimated monthly sales amount less total monthly billed sales amount results in a monthly estimate of unbilled sales. Unbilled revenues are estimated by applying an average rate to the estimate of unbilled sales.
Differences between the actual DE factor and the estimated DE factor can have a significant impact on estimated unbilled revenue amounts.
In 2003, the unbilled sales estimates for PSNH were tested using the cycle method. The cycle method uses the billed sales from each meter reading cycle and an estimate of unbilled days in each month based on the meter reading schedule. The cycle method is historically more accurate than the requirements method when used in a mostly weather-neutral month. The cycle method resulted in adjustments to the estimate of unbilled revenues that had a positive after-tax earnings impact on PSNH of $3.3 million in 2003.
The testing of the requirements method with the cycle method will be done on at least an annual basis using a weather-neutral month.
Derivative Accounting: Effective January 1, 2001, PSNH adopted Statement of Financial Accounting Standards (SFAS) No. 133, as amended.
Many PSNH contracts for the purchase or sale of energy or energy-related products are derivatives. The application of derivative accounting under SFAS No. 133, as amended, is complex and requires management judgment in the following respects: identification of derivatives and embedded derivatives, election, and designation of the normal purchases and sales exception, and determining the fair value of derivatives. All of these judgments, depending upon their timing and effect, can have a significant impact on PSNH's consolidated balance sheet.
In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities," which amended existing derivative accounting guidance. This new statement incorporates interpretations that were included in previous Derivative Implementation Group guidance, clarifies certain conditions, and amends other existing pronouncements. It was effective for contracts entered into or modified after June 30, 2003. Management has determined that the adoption of SFAS No. 149 resulted in fair value accounting for certain PSNH contracts that are subject to unplanned netting and do not meet the definition of capacity contracts. These non-trading derivative contracts are recorded at fair value at December 31, 2003 as derivative assets and liabilities with offsetting amounts recorded as regulatory liabilities and assets because the contracts are part of providing regulated electric service.
Emerging Issues Task Force (EITF) Issue No. 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 EITF Issue No. 02-3," was derived from EITF Issue No. 02-3, which requires net reporting in the income statement of energy trading activities. Issue No. 03-11 addresses income statement classification of revenues related to derivatives that physically deliver and are not related to energy trading activities. Prior to Issue No. 03-11, there was no specific accounting guidance that addressed the classification in the income statement of PSNH's power supply contracts, some of which are non-trading derivatives.
On July 31, 2003, the EITF reached a consensus in Issue No. 03-11 that determining whether realized gains and losses on contracts that physically deliver and are not held for trading purposes should be reported on a net (sales and purchases both in expenses) or gross (sales in revenues and purchases in expenses) basis is a matter of judgment that depends on the relevant facts and circumstances. The EITF indicated that existing accounting guidance should be considered and provided no new guidance in Issue No. 03-11. In Issue No. 03-11, the EITF did not provide transition guidance, which management could have interpreted as becoming applicable on October 1, 2003 for revenues from that date forward. However, management applied its conclusion on net or gross reporting to all periods presented to enhance comparability.
Though previously reported on a gross basis, after reviewing the relevant facts and circumstances, PSNH reported the settlement of all short-term sales contracts that are part of procurement activities on a net basis in expenses. PSNH applied this new classification to revenues for all years presented in order to enhance comparability. These non-requirements sales that amounted to $48.9 million for the first nine months of 2003 and $99.6 million and $207.2 million for the years ended December 31, 2002 and 2001, respectively, were reflected as revenues in quarterly reporting but are now included in expenses.
PSNH holds financial transmission rights (FTR) contracts to mitigate the risk associated with the congestion price differences associated with LMP in New England. FTR contracts held by PSNH were recorded at a fair value of $0.1 million. Management believes the amount to be paid for the FTR contracts best represents their fair value. If new markets for these contracts develop, then there may be an impact on PSNH's consolidated financial statements in future periods.
Regulatory Accounting: The accounting policies of PSNH historically reflect the effects of the rate-making process in accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." The generation, transmission and distribution businesses of PSNH continue to be cost-of- service rate regulated, and management believes the application of SFAS No. 71 to those businesses continues to be appropriate. Management must reaffirm this conclusion at each balance sheet date. If, as a result of a change in circumstances, it is determined that any portion of the company no longer meets the criteria of regulatory accounting under SFAS No. 71, that portion of the company will have to discontinue regulatory accounting and write-off their regulatory assets and liabilities. Such a write-off could have a material impact on PSNH's consolidated financial statements.
The application of SFAS No. 71 results in recording regulatory assets and liabilities. Regulatory assets represent the deferral of incurred costs that are probable of future recovery in customer rates. In some cases, PSNH records regulatory assets before approval for recovery has been received from the NHPUC. Management must use judgment to conclude that costs deferred as regulatory assets are probable of future recovery. Management bases its conclusion on certain factors, including changes in the regulatory environment, recent rate orders issued by the NHPUC and the status of any potential new legislation. Regulatory liabilities represent revenues received from customers to fund expected costs that have not yet been incurred or probable future refunds to customers.
Management uses its best judgment when recording regulatory assets and liabilities; however, the NHPUC can reach different conclusions about the recovery of costs, and those conclusions could have a material impact on PSNH's consolidated financial statements. Management believes it is probable that PSNH will recover the regulatory assets that have been recorded.
Pension and Postretirement Benefits Other Than Pensions (PBOP): PSNH participates in a uniform noncontributory defined benefit retirement plan (Pension Plan) covering substantially all regular PSNH employees. PSNH also participates in a postretirement benefit plan (PBOP Plan) to provide certain health care benefits, primarily medical and dental, and life insurance benefits through a benefit plan to retired employees. For each of these plans, the development of the benefit obligation, fair value of plan assets, funded status and net periodic benefit credit or cost is based on several significant assumptions. If these assumptions were changed, the resulting change in benefit obligations, fair values of plan assets, funded status and net periodic benefit credits or costs could have a material impact on PSNH's consolidated financial statements.
Results: Pre-tax periodic pension expense/income for the Pension Plan, excluding settlements, curtailments and special termination benefits, totaled $6.8 million in expense, $0.6 million in expense and $3.9 million in income for the years ended December 31, 2003, 2002 and 2001, respectively. The pension expense/income amounts exclude one-time items recorded under SFAS No. 88, "Employers' Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits," associated with early termination programs. Net SFAS No. 88 items totaled $1.3 million in expense for the year ended December 31, 2001.
The pre-tax net PBOP Plan cost, excluding settlements, curtailments and special termination benefits, totaled $6.2 million, $5.3 million and $4.3 million for the years ended December 31, 2003, 2002 and 2001, respectively.
Long-Term Rate of Return Assumptions: In developing the expected long-term rate of return assumptions, PSNH evaluated input from actuaries, consultants and economists, as well as long-term inflation assumptions and PSNH's historical 20-year compounded return of approximately 11 percent. PSNH's expected long-term rate of return on assets is based on certain target asset allocation assumptions and expected long-term rates of return. The Pension Plan's and PBOP Plan's target asset allocation assumptions and expected long- term rates of return assumptions by asset category are as follows:
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At December 31,
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Pension Benefits Postretirement Benefits
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2003 2002 2003 2002
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Target Assumed Target Assumed Target Assumed Target Assumed
Asset Rate of Asset Rate of Asset Rate of Asset Rate of
Asset Category Allocation Return Allocation Return Allocation Return Allocation Return
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Equity securities:
United States 45.00% 9.25% 45.00% 9.75% 55.00% 9.25% 55.00% 9.75%
Non-United States 14.00% 9.25% 14.00% 9.75% 11.00% 9.25% - -
Emerging markets 3.00% 10.25% 3.00% 10.75% 2.00% 10.25% - -
Private 8.00% 14.25% 8.00% 14.75% - - - -
Debt Securities:
Fixed income 20.00% 5.50% 20.00% 6.25% 27.00% 5.50% 45.00% 6.25%
High yield fixed
income 5.00% 7.50% 5.00% 7.50% 5.00% 7.50% - -
Real estate 5.00% 7.50% 5.00% 7.50% - - - -
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The actual asset allocations at December 31, 2003 and 2002 approximated these target asset allocations. PSNH regularly reviews the actual asset allocations and periodically rebalances the investments to the targeted asset allocations when appropriate. For information regarding actual asset allocations, see Note 5, "Pension Benefits and Postretirement Benefits Other Than Pensions," to the consolidated financial statements.
PSNH reduced the long-term rate of return assumption 50 basis points from 9.25 percent to 8.75 percent in 2003 for the Pension Plan and PBOP Plan due to lower expected market returns. PSNH believes that 8.75 percent is a reasonable long-term rate of return on Pension Plan and PBOP Plan assets for 2003, and PSNH expects to use 8.75 percent in 2004. PSNH will continue to evaluate the actuarial assumptions, including the expected rate of return, at least annually, and will adjust the appropriate assumptions as necessary.
Actuarial Determination of Income and Expense: PSNH bases the actuarial determination of Pension Plan and PBOP Plan income/expense on a market- related valuation of assets, which reduces year-to-year volatility. This market-related valuation calculation recognizes investment gains or losses over a four-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the fair value of assets. Since the market-related valuation calculation recognizes gains or losses over a four-year period, the future value of the market-related assets will be impacted as previously deferred gains or losses are recognized. There will be no impact on the fair value of Pension Plan and PBOP Plan assets.
At December 31, 2003, the Pension Plan had cumulative unrecognized investment losses of $10.5 million, which will increase pension expense over the next four years by reducing the expected return on Pension Plan assets. At December 31, 2003, the Pension Plan also had cumulative unrecognized actuarial losses of $26.8 million, which will increase pension expense over the expected future working lifetime of active Pension Plan participants, or approximately 13 years. The combined total of unrecognized investment and actuarial losses at December 31, 2003 is $37.3 million. These losses impact the determination of pension expense and the actuarially determined prepaid pension amount recorded on the consolidated balance sheets but have no impact on expected Pension Plan funding.
At December 31, 2003, the PBOP Plan had cumulative unrecognized investment losses of $1.5 million, which will increase PBOP Plan cost over the next four years by reducing the expected return on plan assets. At December 31, 2003, the PBOP Plan also had cumulative unrecognized actuarial losses of $13.2 million, which will increase PBOP Plan expense over the expected future working lifetime of active PBOP Plan participants, or approximately 13 years. The combined total of unrecognized investment and actuarial losses at December 31, 2003 is $14.7 million. These losses impact the determination of PBOP Plan cost and the actuarially determined accrued PBOP Plan cost recorded on the consolidated balance sheets.
Discount Rate: The discount rate that is utilized in determining future pension and PBOP obligations is based on a basket of long-term bonds that receive one of the two highest ratings given by a recognized rating agency. To compensate for the Pension Plan's longer duration 25 basis points were added to the benchmark. The discount rate determined on this basis has decreased from 6.75 percent at December 31, 2002 to 6.25 percent at December 31, 2003.
Expected Pension Expense: Due to the effect of the unrecognized actuarial losses and based on an expected rate of return on Pension Plan assets of 8.75 percent, a discount rate of 6.25 percent and various other assumptions, PSNH estimates that expected contributions to and pension expense for the Pension Plan will be as follows (in millions):
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Expected
Year Contributions Pension Expense
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2004 $ - $10.6
2005 $ - $11.9
2006 $ - $11.9
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Future actual pension expense/income will depend on future investment performance, changes in future discount rates and various other factors related to the populations participating in the Pension Plan.
Sensitivity Analysis: The following represents the increase/(decrease) to the Pension Plan's reported cost and increases to the PBOP Plan's reported cost as a result of the change in the following assumptions by 50 basis points (in millions):
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At December 31,
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Pension Plan Postretirement Plan
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Assumption Change 2003 2002 2003 2002
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Lower long-term
rate of return $ 1.1 $ 1.1 $0.2 $0.2
Lower discount
rate $ 1.9 $ 1.7 $0.2 $0.2
Lower compensation
increase $(1.0) $(0.8) N/A N/A
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Plan Assets: The value of the Pension Plan assets has increased from $163.5 million at December 31, 2002 to $191.9 million at December 31, 2003. The investment performance returns, despite declining discount rates, have decreased the underfunded status of the Pension Plan on a projected benefit obligation (PBO) basis from $97.4 million at December 31, 2002 to $97.1 million at December 31, 2003. The PBO includes expectations of future employee compensation increases. The accumulated benefit obligation (ABO) of the Pension Plan was $51.7 million more than Pension Plan assets at December 31, 2003 and $54.9 million more than Pension Plan assets at December 31, 2002. The ABO is the obligation for employee service and compensation provided through December 31, 2003. If the ABO for the entire Pension Plan exceeds all Pension Plan assets at a future plan measurement date, NU will record an additional minimum liability of which PSNH will be allocated its proportionate share. PSNH has not made employer contributions since 1991.
The value of PBOP Plan assets has increased from $24.4 million at December 31, 2002 to $29.7 million at December 31, 2003. The investment performance returns, despite declining discount rates, have decreased the underfunded status of the PBOP Plan on an accumulated projected benefit obligation basis from $39.3 million at December 31, 2002 to $37.1 million at December 31, 2003. PSNH has made a contribution each year equal to the PBOP Plan's postretirement benefit cost, excluding curtailments, settlements and special termination benefits.
Health Care Cost: The health care cost trend assumption used to project increases in medical costs is 9 percent for 2003, decreasing one percentage point per year to an ultimate rate of 5 percent in 2007. The effect of increasing the health care cost trend by one percentage point would have increased 2003 service and interest cost components of the PBOP Plan cost by $0.1 million in 2003 and 2002.
Accounting for the Effect of Medicare Changes on PBOP: On December 8, 2003, the President signed into law a bill that expands Medicare, primarily by adding a prescription drug benefit and by adding a federal subsidy to qualifying plan sponsors of retiree health care benefit plans. Management believes that PSNH currently qualifies.
Specific authoritative accounting guidance on how to account for the effect the Medicare federal subsidy has on PSNH's PBOP Plan has not been issued by the FASB. FASB Staff Position (FSP) No. FAS 106-1, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003," required PSNH to make an election for 2003 financial reporting. The election was to either defer the impact of the subsidy until the FASB issues guidance or to reflect the impact of the subsidy on December 31, 2003 reported amounts. PSNH chose to reflect the impact on December 31, 2003 reported amounts.
Reflecting the impact of the Medicare change decreased the PBOP benefit obligation by approximately $4.4 million and increased actuarial gains by approximately $4.4 million with no impact on 2003 expenses, assets, or liabilities. The $4.4 million actuarial gain will be amortized as a reduction to PBOP expense over 13 years beginning in 2004. PBOP expense in 2004 will also reflect a lower interest cost due to the reduction in the December 31, 2003 benefit obligation. Management estimates that the reduction in PBOP expense in 2004 will be approximately $0.3 million.
When accounting guidance is issued by the FASB, it may require PSNH to change the accounting described above and change the information included in this annual report.
Income Taxes: Income tax expense is calculated each year in each of the jurisdictions in which PSNH operates. This process involves estimating PSNH's actual current tax exposures as well as assessing temporary differences resulting from differing treatment of items, such as timing of the deduction and expenses for tax and book accounting purposes. These differences result in deferred tax assets and liabilities, which are included in PSNH's consolidated balance sheets. Adjustments made to income taxes could significantly affect PSNH's consolidated financial statements. Management must also assess the likelihood that deferred tax assets will be recovered from future taxable income, and to the extent that recovery is not likely, a valuation allowance must be established. Significant management judgment is required in determining income tax expense and deferred tax assets and liabilities.
PSNH accounts for deferred taxes under SFAS No. 109, "Accounting for Income Taxes." For temporary differences recorded as deferred tax liabilities that will be recovered in rates in the future, PSNH has established a regulatory asset. The regulatory asset amounted to $44.2 million and $96.5 million at December 31, 2003 and 2002, respectively. Regulatory agencies in certain jurisdictions in which PSNH companies operate require the tax effect of specific temporary differences to be "flowed through" to utility customers. Flow through treatment means that deferred tax expense is not recorded on the consolidated statements of income. Instead, the tax effect of the temporary difference impacts both amounts for income tax expense currently included in customers' rates and the company's net income. Flow through treatment can result in effective income tax rates that are significantly different than expected income tax rates. Recording deferred taxes on flow through items is required by SFAS No. 109, and the offset to the deferred tax amounts is the regulatory asset referred to above. A reconciliation from expected tax expense at the statutory federal income tax rate to actual tax expense recorded is included in Note 12, "Income Tax Expense," to the consolidated financial statements.
The estimates that are made by management in order to record income tax expense, accrued taxes and deferred taxes are compared each year to the actual tax amounts filed on PSNH's income tax returns. The income tax returns were filed in the fall of 2003 for the 2002 tax year. In the fourth quarter, PSNH recorded differences between income tax expense, accrued taxes and deferred taxes on its consolidated financial statements and the amounts that were on its income tax returns. Recording these differences in income tax expense resulted in a positive impact of approximately $2.1 million on PSNH's 2003 earnings.
Depreciation: Depreciation expense is calculated based on an asset's useful life, and judgment is involved when estimating the useful lives of certain assets. A change in the estimated useful lives of these assets could have a material impact on PSNH's consolidated financial statements absent timely rate relief for PSNH's assets.
Accounting for Environmental Reserves: Environmental reserves are accrued using a probabilistic model approach when assessments indicate that it is probable that a liability has been incurred and an amount can be reasonably estimated. Adjustments made to environmental liabilities could have a significant effect on earnings. The probabilistic model approach estimates the liability based on the most likely action plan from a variety of available remediation options, ranging from no action to remedies ranging from establishing institutional controls to full site remediation and long- term monitoring. The probabilistic model approach estimates the liabilities associated with each possible action plan based on findings through various phases of site assessments. These estimates are based on currently available information from presently enacted state and federal environmental laws and regulations and several cost estimates from outside engineering and remediation contractors. These amounts also take into consideration prior experience in remediating contaminated sites and data released by the United States Environmental Protection Agency and other organizations.
These estimates are subjective in nature partly because there are usually several different remediation options from which to choose when working on a specific site. These estimates are subject to revisions in future periods based on actual costs or new information concerning either the level of contamination at the site or newly enacted laws and regulations. The amounts recorded as environmental liabilities on the consolidated balance sheets represent management's best estimate of the liability for environmental costs based on current site information from site assessments and remediation estimates. These liabilities are estimated on an undiscounted basis.
Under current rate-making policy, PSNH has a regulatory recovery mechanism in place for environmental costs. Accordingly, regulatory assets have been recorded for certain of PSNH's environmental liabilities. As of December 31, 2003 and 2002, $7.6 million and $4.9 million, respectively, have been recorded as regulatory assets on the accompanying consolidated balance sheets.
Asset Retirement Obligations: PSNH adopted SFAS No. 143, "Accounting for Asset Retirement Obligations" on January 1, 2003. SFAS No. 143 requires that legal obligations associated with the retirement of property, plant and equipment be recorded as a liability on the balance sheet at fair value when incurred and when a reasonable estimate of the fair value can be made. SFAS No. 143 defines an asset retirement obligation (ARO) as a legal obligation that is required to be settled due to an existing or enacted law, statute, ordinance or a written or oral promise to remove an asset. AROs may stem from environmental laws, state laws and regulations, easement agreements, building codes, contracts, franchise grants and agreements, oral promises made upon which third parties have relied, or the dismantlement, restoration, or reclamation of properties.
Upon adoption of SFAS No. 143, certain removal obligations were identified that management believes are AROs but either have not been incurred or are not material. These removal obligations arise in the ordinary course of business or have a low probability of occurring. The types of obligations primarily relate to transmission and distribution lines and poles, telecommunication towers, transmission cables and certain FERC or state regulatory agency re-licensing issues. There was no impact to PSNH's earnings upon adoption of SFAS No. 143; however, if there are changes in certain laws and regulations, orders, interpretations or contracts entered into by PSNH there may be future AROs that need to be recorded.
Under SFAS No. 71, regulated utilities, including PSNH, currently recover amounts in rates for future costs of removal of plant assets. Future removals of assets do not represent legal obligations and are not AROs. Historically, these amounts were included as a component of accumulated depreciation until spent. At December 31, 2003 and 2002, these amounts totaling $88 million and $67 million, respectively, were reclassified to regulatory liabilities on the accompanying consolidated balance sheets.
In June 2003, the FASB issued a proposed FSP, "Applicability of SFAS No. 143, 'Accounting for Asset Retirement Obligations', to Legislative Requirements on Property Owners to Remove and Dispose of Asbestos or Asbestos-Containing Materials." In the FSP, the FASB staff concludes that current legislation creates a legal obligation for the owner of a building to remove and dispose of asbestos-containing materials. In the FSP, the FASB staff also concludes that this legal obligation constitutes an ARO that should be recognized as a liability under SFAS No. 143. This FSP changes a FASB staff interpretation of SFAS No. 143 that an obligating event did not occur until a building containing asbestos was demolished. In November 2003, the FASB indicated that, based on the diverse views it received in comment letters on the proposed FSP, it was considering a proposal for a FASB agenda project to address this issue. If this FSP is adopted in its current form, then PSNH would be required to record an ARO. Management has not estimated this potential ARO at December 31, 2003.
Special Purpose Entities: During 2001 and 2002, to facilitate the issuance of rate reduction bonds intended to finance certain stranded costs, PSNH established two SPEs: PSNH Funding LLC and PSNH Funding LLC 2 (the funding companies). The funding companies were created as part of a state-sponsored securitization program. The funding companies are restricted from engaging in non-related activities and are required to operate in a manner intended to reduce the likelihood that they would be included in PSNH's bankruptcy estate if it ever became involved in a bankruptcy proceeding. The funding companies and the securitization amounts are consolidated in the accompanying consolidated financial statements.
For further information regarding the matters in this "Critical Accounting Policies and Estimates" section see Note 1, "Summary of Significant Accounting Policies," Note 5, "Pension Benefits and Postretirement Benefits Other Than Pensions," Note 12, "Income Tax Expense," and Note 7B, "Commitments and Contingencies - Environmental Matters," to the consolidated financial statements.
OTHER MATTERS
Commitments and Contingencies: For further information regarding other
commitments and contingencies, see Note 7, "Commitments and Contingencies,"
to the consolidated financial statements.
Contractual Obligations and Commercial Commitments: Information regarding PSNH's contractual obligations and commercial commitments at December 31, 2003 is summarized through 2008 and thereafter as follows:
------------------------------------------------------------------------------------------------------ (Millions of Dollars) 2004 2005 2006 2007 2008 Thereafter ------------------------------------------------------------------------------------------------------ Notes payable to banks (a) $ 10.0 $ - $ - $ - $ - $ - Long-term Debt(a) - - - - - 407.3 - Capital leases (b) (c) 0.5 0.5 0.3 0.2 0.2 - Operating leases (c) (d) 4.6 3.9 3.6 2.6 2.1 3.6 Long-term contractual arrangements (c) (d) 136.6 138.0 139.0 66.8 40.6 392.2 ------------------------------------------------------------------------------------------------------ Totals $151.7 $142.4 $142.9 $69.6 $42.9 $803.1 ------------------------------------------------------------------------------------------------------ |
(a) Included in PSNH's debt agreements are usual and customary positive, negative and financial covenants. Non-compliance with certain covenants, for example the timely payment of principal and interest, may constitute an event of default, which could cause an acceleration of principal in the absence of receipt by the company of a waiver or amendment. Such acceleration would change the obligations outlined in the table of contractual obligations and commercial commitments.
(b) The capital lease obligations include imputed interest of $0.7 million.
(c) PSNH has no provisions in its capital or operating lease agreements or agreements related to its long-term contractual arrangements that could trigger a change in terms and conditions, such as acceleration of payment obligations.
(d) Amounts are not included on PSNH's consolidated balance sheets.
Rate reduction bond amounts are non-recourse to PSNH, have no required payments over the next five years and are not included in this table. Additionally, this table does not include notes payable to affiliated companies totaling $48.9 million at December 31, 2003 and PSNH's expected contribution to the PBOP Plan in 2004 of $7 million. For further information regarding PSNH's contractual obligations and commercial commitments, see Note 3, "Short-Term Debt," Note 9, "Leases," Note 7D, "Commitments and Contingencies - Long-Term Contractual Arrangements," and Note 11, "Long-Term Debt," to the consolidated financial statements.
Forward Looking Statements: This discussion and analysis includes forward looking statements, which are statements of future expectations and not facts including, but not limited to, statements regarding future earnings, refinancings, regulatory proceedings, the use of proceeds from restructuring, and the recovery of operating costs. Words such as estimates, expects, anticipates, intends, plans, and similar expressions identify forward looking statements. Actual results or outcomes could differ materially as a result of further actions by state and federal regulatory bodies, competition and industry restructuring, changes in economic conditions, changes in weather patterns, changes in laws, developments in legal or public policy doctrines, technological developments, volatility in electric commodity markets, and other presently unknown or unforeseen factors.
Website: Additional financial information is available through NU's website at www.nu.com.
RESULTS OF OPERATIONS
The following table provides the variances in income statement line items for the consolidated statements of income included in this annual report for the past two years.
---------------------------------------------------------------------------------------------------
2003 over/(under) 2002 2002 over/(under) 2001
Income Statement Variances ---------------------- ------------------------
(Millions of Dollars) Amount Percent Amount Percent
---------------------------------------------------------------------------------------------------
Operating Revenues $ (59) (6)% $ (17) (2)%
Operating Expenses:
Fuel, purchased and net interchange power 112 39 (218) (43)
Other operation 16 13 3 2
Maintenance 1 1 8 14
Depreciation 2 6 1 3
Amortization of regulatory assets, net (158) (81) 158 (a)
Amortization of rate reduction bonds (3) (6) 16 59
Taxes other than income taxes (1) (2) (4) (11)
---------------------------------------------------------------------------------------------------
Total operating expenses (31) (4) (36) (4)
---------------------------------------------------------------------------------------------------
Operating Income (28) (18) 19 14
Interest expense, net (4) (8) (2) (4)
Other (loss)/income, net (4) (a) (38) (a)
---------------------------------------------------------------------------------------------------
Income before income tax expense (28) (27) (17) (14)
Income tax expense (11) (26) 2 4
---------------------------------------------------------------------------------------------------
Net Income $ (17) (27)% $ (19) (23)%
===================================================================================================
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(a) Percent greater than 100.
OPERATING REVENUES
Operating revenues decreased $59 million in 2003 compared with the same
period of 2002 primarily due to lower regulated wholesale revenues resulting
from the impact of less owned generation since the sale of Seabrook ($114
million), partially offset by higher retail revenues ($56 million). Retail
revenues were higher primarily due to higher retail sales volumes ($37
million) and higher TS revenues. Retail kWh sales increased 4.7 percent for
the year 2003.
Operating revenues decreased $17 million in 2002 primarily due to lower retail revenues. Retail revenues decreased $24 million primarily due to the May 2001 rate decrease. Retail kWh sales were essentially flat with a 0.1 percent decrease.
FUEL, PURCHASED AND NET INTERCHANGE POWER
Fuel, purchased and net interchange power expense increased $112 million in
2003 primarily due to the absence of the 2002 gain on the sale of utility
plant resulting from the sale of Seabrook recorded on NAEC's books, which was
transferred to PSNH through the Seabrook Power Contracts ($167 million),
partially offset by lower fuel expense resulting from lower regulated
wholesale transactions.
Fuel, purchased and net interchange power expense decreased $218 million in 2002 primarily due to the gain on the sale of utility plant resulting from the sale of Seabrook recorded on NAEC's books, which was transferred to PSNH through the Seabrook Power Contracts ($167 million) and lower purchased power from NAEC ($67 million).
OTHER OPERATION AND MAINTENANCE
Other operation and maintenance (O&M) expenses increased $17 million in 2003
primarily due to higher pension costs ($8 million) and higher conservation
and customer assistance programs expense ($8 million).
Other O&M expenses increased $11 million in 2002 primarily due to higher fossil/hydro production expense ($8 million) and higher transmission and distribution expense ($3 million).
DEPRECIATION
Depreciation increased $2 million in 2003 primarily due to additions to
distribution, generation, and general plant assets.
Depreciation increased $1 million in 2002 primarily due to the construction of the new corporate headquarters.
AMORTIZATION OF REGULATORY ASSETS, NET
Amortization of regulatory assets, net decreased $158 million in 2003
primarily due to the 2002 amortization of stranded costs upon the sale of
Seabrook ($167 million), partially offset by an increase in the recovery of
stranded costs ($4 million) resulting from the SCRC reconciliation of
stranded cost revenues against actual stranded costs.
Amortization of regulatory assets, net increased $158 million in 2002 primarily due to recovery of stranded costs associated with the sale of the Seabrook Station.
AMORTIZATION OF RATE REDUCTION BONDS
Amortization of rate reduction bonds decreased $3 million in 2003 due to the
repayment of principle and associated reduction of securitized regulatory
assets.
Amortization of rate reduction bonds increased $16 million in 2002 due to the issuance of rate reduction bonds in 2002 and April 2001.
TAXES OTHER THAN INCOME TAXES
Taxes other than income taxes decreased $1 million in 2003 primarily due to
lower property tax.
Taxes other than income taxes decreased $4 million in 2002 primarily due to the discontinuance of New Hampshire franchise taxes in 2001.
INTEREST EXPENSE, NET
Interest expense, net decreased $4 million in 2003 due to lower interest on
rate reduction bonds due to lower debt levels ($1 million) and lower interest
rates.
Interest expense, net decreased $2 million in 2002 primarily due to the December 2001 refinancing of long-term debt at lower rates.
OTHER (LOSS)/INCOME, NET
Other (loss)/income, net decreased $4 million in 2003 primarily due to
increased service fees associated with rate reduction bonds and lower gains
on the disposition of property in 2003.
Other (loss)/income, net decreased $38 million in 2002 as a result of PSNH's sale of its ownership in Millstone 3 in 2001 ($26 million), a gain on the disposition of property in 2001 ($4 million) and lower dividend income in 2002 ($2 million).
INCOME TAX EXPENSE
Income tax expense decreased $11 million in 2003 primarily as a result of
lower book taxable income as compared to 2002. For further information
regarding income tax expense, see Note 12, "Income Tax Expense," to the
consolidated financial statements.
Income tax expense increased $2 million in 2002 primarily as a result of reduced investment tax credit amortization, partially offset by the tax consequences of lower acquisition premium amortization.
Management is responsible for the preparation, integrity, and fair presentation of the accompanying consolidated financial statements of Public Service Company of New Hampshire and subsidiaries and other sections of this annual report. These financial statements, which were audited by Deloitte & Touche LLP, have been prepared in conformity with accounting principles generally accepted in the United States of America using estimates and judgments, where required, and giving consideration to materiality.
The company has endeavored to establish a control environment that encourages the maintenance of high standards of conduct in all of its business activities. Management is responsible for maintaining a system of internal control over financial reporting that is designed to provide reasonable assurance, at an appropriate cost-benefit relationship, to the company's management and Board of Trustees of Northeast Utilities regarding the preparation of reliable published financial statements. The system is supported by an organization of trained management personnel, policies and procedures, and a comprehensive program of internal audits. Through established programs, the company regularly communicates to its management employees their internal control responsibilities and obtains information regarding compliance with policies prohibiting conflicts of interest and policies segregating information between regulated and unregulated subsidiary companies. The company has standards of business conduct for all employees, as well as a code of ethics for senior financial officers.
The Audit Committee of the Board of Trustees of Northeast Utilities is composed entirely of independent trustees and includes two members that the Board of Trustees considers "audit committee financial experts." The Audit Committee meets regularly with management, the internal auditors and the independent auditors to review the activities of each and to discuss audit matters, financial reporting matters, and the system of internal controls over financial reporting. The Audit Committee also meets periodically with the internal auditors and the independent auditors without management present.
Because of inherent limitations in any system of internal controls, errors or irregularities may occur and not be detected. The company believes, however, that its system of internal controls over financial reporting and control environment provide reasonable assurance that its assets are safeguarded from loss or unauthorized use and that its financial records, which are the basis for the preparation of all financial statements, are reliable. Additionally, management believes that its disclosure controls and procedures are in place and operating effectively. Disclosure controls and procedures are designed to ensure that information included in reports such as this annual report is recorded, processed, summarized, and reported within the time periods required and that the information disclosed is accumulated and reviewed by management for discussion and approval.
We have audited the accompanying consolidated balance sheets of Public Service Company of New Hampshire and subsidiaries (a New Hampshire corporation and a wholly owned subsidiary of Northeast Utilities) (the "Company") as of December 31, 2003 and 2002, and the related consolidated statements of income, comprehensive income, common stockholder's equity, and cash flows for each of the three years in the period ended December 31, 2003. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Public Service Company of New Hampshire and subsidiaries as of December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 1C to the consolidated financial statements, in 2003, the Company adopted Emerging Issues Task Force Issue 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, and retroactively, restated the 2002 and 2001 consolidated financial statements.
/s/ DELOITTE & TOUCHE LLP
DELOITTE & TOUCHE LLP
Hartford, Connecticut
February 23, 2004
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PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
-----------------------------------------------------------------------------------------
At December 31, 2003 2002
-----------------------------------------------------------------------------------------
(Thousands of Dollars)
ASSETS
------
Current Assets:
Cash $ 2,737 $ 5,319
Special deposits 30,104 -
Receivables, net less provision for uncollectible
accounts of $1,590 in 2003 and $1,990 in 2002 67,121 68,204
Accounts receivable from affiliated companies 11,291 9,667
Unbilled revenues 39,220 32,004
Notes receivable from affiliated companies - 23,000
Fuel, materials and supplies, at average cost 54,533 49,182
Derivative assets 1,510 -
Prepayments and other 9,945 10,032
------------- -------------
216,461 197,408
------------- -------------
Property, Plant and Equipment:
Electric utility 1,517,513 1,431,774
Other 5,707 6,195
------------- -------------
1,523,220 1,437,969
Less: Accumulated depreciation 635,029 648,800
------------- -------------
888,191 789,169
Construction work in progress 37,401 50,547
------------- -------------
925,592 839,716
------------- -------------
Deferred Debits and Other Assets:
Regulatory assets 969,434 1,026,043
Other 60,324 92,280
------------- -------------
1,029,758 1,118,323
------------- -------------
Total Assets $ 2,171,811 $ 2,155,447
============= =============
|
The accompanying notes are an integral part of these consolidated financial statements.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
--------------------------------------------------------------------------------------------
At December 31, 2003 2002
--------------------------------------------------------------------------------------------
(Thousands of Dollars)
LIABILITIES AND CAPITALIZATION
------------------------------
Current Liabilities:
Notes payable to banks $ 10,000 $ -
Notes payable to affiliated companies 48,900 -
Accounts payable 48,408 54,588
Accounts payable to affiliated companies 13,911 4,008
Accrued taxes 2,543 65,317
Accrued interest 10,894 11,333
Unremitted rate reduction bond collections 11,051 25,555
Derivative liabilities 1,414 -
Other 16,689 12,674
-------------- -------------
163,810 173,475
-------------- -------------
Rate Reduction Bonds 472,222 510,841
-------------- -------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 338,930 359,910
Accumulated deferred investment tax credits 2,096 2,680
Deferred contractual obligations 64,237 56,165
Regulatory liabilities 272,081 254,064
Accrued pension 44,766 37,933
Other 26,124 31,264
-------------- -------------
748,234 742,016
-------------- -------------
Capitalization:
Long-Term Debt 407,285 407,285
-------------- -------------
Common Stockholder's Equity:
Common stock, $1 par value - authorized
100,000,000 shares; 301 shares outstanding
in 2003 and 2002 - -
Capital surplus, paid in 156,555 126,937
Retained earnings 223,822 194,998
Accumulated other comprehensive loss (117) (105)
-------------- -------------
Common Stockholder's Equity 380,260 321,830
-------------- -------------
Total Capitalization 787,545 729,115
-------------- -------------
Commitments and Contingencies (Note 7)
Total Liabilities and Capitalization $ 2,171,811 $ 2,155,447
============== =============
|
The accompanying notes are an integral part of these consolidated financial statements.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
-----------------------------------------------------------------------------------------------------------
For the Years Ended December 31, 2003 2002 2001
-----------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Operating Revenues $ 888,186 $ 947,178 $ 964,415
----------- ----------- ------------
Operating Expenses:
Operation -
Fuel, purchased and net interchange power 400,518 288,427 506,397
Other 142,550 126,506 123,533
Maintenance 64,872 64,146 56,276
Depreciation 43,322 40,941 39,741
Amortization of regulatory assets, net 37,861 196,246 38,629
Amortization of rate reduction bonds 40,040 42,714 26,816
Taxes other than income taxes 33,407 34,226 38,375
----------- ----------- ------------
Total operating expenses 762,570 793,206 829,767
----------- ----------- ------------
Operating Income 125,616 153,972 134,648
Interest Expense:
Interest on long-term debt 15,408 16,752 29,308
Interest on rate reduction bonds 29,081 30,499 20,721
Other interest 727 1,874 915
----------- ----------- ------------
Interest expense, net 45,216 49,125 50,944
----------- ----------- ------------
Other (Loss)/Income, Net (5,003) (1,671) 36,643
----------- ----------- ------------
Income Before Income Tax Expense 75,397 103,176 120,347
Income Tax Expense 29,773 40,279 38,571
----------- ----------- ------------
Net Income $ 45,624 $ 62,897 $ 81,776
=========== =========== ============
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Net Income $ 45,624 $ 62,897 $ 81,776
----------- ----------- ------------
Other comprehensive income/(loss), net of tax:
Unrealized gains/(losses) on securities 128 (620) (801)
Minimum supplemental executive retirement
pension liability adjustments (140) 109 -
----------- ----------- ------------
Other comprehensive loss, net of tax (12) (511) (801)
----------- ----------- ------------
Comprehensive Income $ 45,612 $ 62,386 $ 80,975
=========== =========== ============
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The accompanying notes are an integral part of these consolidated financial statements.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
--------------------------------------------------------------------------------------------------------------------
Accumulated
Common Stock Capital Other
---------------- Surplus, Retained Comprehensive Total
Shares Amount Paid In Earnings Income/(Loss) (a)
--------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars, except share information)
Balance at January 1, 2001 1,000 $ 1 $ 424,909 $123,177 $1,207 $549,294
Net income for 2001 81,776 81,776
Cash dividends on preferred stock (1,286) (1,286)
Cash dividends on common stock (27,000) (27,000)
Repurchase of common stock (612) (1) (259,999) (260,000)
Capital stock expenses, net 90 90
Allocation of benefits - ESOP (248) (248)
Other comprehensive loss (801) (801)
----- ---- --------- -------- ------ --------
Balance at December 31, 2001 388 - 165,000 176,419 406 341,825
Net income for 2002 62,897 62,897
Cash dividends on common stock (45,000) (45,000)
Repurchase of common stock (87) (37,000) (37,000)
Allocation of benefits - ESOP (1,063) 682 (381)
Other comprehensive loss (511) (511)
----- ---- --------- -------- ------ --------
Balance at December 31, 2002 301 - 126,937 194,998 (105) 321,830
Net income for 2003 45,624 45,624
Cash dividends on common stock (16,800) (16,800)
Allocation of benefits - ESOP (382) (382)
Capital contribution from NU parent 30,000 30,000
Other comprehensive loss (12) (12)
----- ---- --------- -------- ------ --------
Balance at December 31, 2003 301 $ - $ 156,555 $223,822 $ (117) $380,260
===== ==== ========= ======== ====== ========
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(a) The Federal Power Act, the Public Utility Holding Act of 1935 (the 1935 Act), and certain state statutes limit the payment of dividends by the company to its retained earnings balance.
The Utility Group credit agreement also limits dividend payments subject to the requirements that the company's total debt to total capitalization ratio does not exceed 65 percent.
At December 31, 2003, retained earnings available for payment of dividends is restricted to $84.0 million.
The accompanying notes are an integral part of these consolidated financial statements.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
---------------------------------------------------------------------------------------------------------------
For the Years Ended December 31, 2003 2002 2001
---------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Operating activities:
Net income $ 45,624 $ 62,897 $ 81,776
Adjustments to reconcile to net cash flows
provided by operating activities:
Depreciation 43,322 40,941 39,741
Deferred income taxes and investment tax credits, net (6,670) (79,866) 195,422
Amortization of regulatory assets, net 37,861 196,246 38,629
Amortization of rate reduction bonds 40,040 42,714 26,816
Amortization of recoverable energy costs 23,388 9,859 (21,234)
Regulatory recoveries 10,778 (34,315) (133,954)
Other sources of cash 23,723 23,708 113,626
Other uses of cash (52,769) (18,137) (42,060)
Changes in current assets and liabilities:
Receivables and unbilled revenues, net (7,757) 2,989 3,212
Fuel, materials and supplies (5,351) (7,135) (13,287)
Other current assets (excludes cash) 87 179 14,576
Accounts payable 3,723 7,583 (48,888)
Accrued taxes (62,774) 63,036 1,624
Other current liabilities (10,981) 14,253 15,716
---------- ---------- ----------
Net cash flows provided by operating activities 82,244 324,952 271,715
---------- ---------- ----------
Investing Activities:
Investments in plant (105,626) (108,729) (91,770)
NU system Money Pool borrowing/(lending) 71,900 (46,000) 23,000
Investments in nuclear decommissioning trusts - - (137)
Net proceeds from sale of utility plant - - 24,888
Buyout/buydown of IPP contracts (20,437) (5,152) (48,164)
CVEC acquisition special deposit (30,104) - -
Other investment activities 15,066 (8,269) (30,906)
---------- ---------- ----------
Net cash flows used in investing activities (69,201) (168,150) (123,089)
---------- ---------- ----------
Financing Activities:
Repurchase of common stock - (37,000) (260,000)
Issuance of long-term debt - - 287,485
Issuance of rate reduction bonds - 50,000 525,000
Retirement of rate reduction bonds (38,619) (46,540) (17,619)
Increase/(decrease) in short-term debt 10,000 (60,500) 60,500
Reacquisitions and retirements of long-term debt - - (287,485)
Reacquisitions and retirements of preferred stock - - (24,268)
Buydown of capital lease obligation - - (497,508)
Capital contribution from Northeast Utilities 30,000 - -
Cash dividends on preferred stock - - (1,286)
Cash dividends on common stock (16,800) (45,000) (27,000)
Other financing activities (206) (13,922) (21,448)
---------- ---------- ----------
Net cash flows used in financing activities (15,625) (152,962) (263,629)
---------- ---------- ----------
Net (decrease)/increase in cash (2,582) 3,840 (115,003)
Cash - beginning of year 5,319 1,479 116,482
---------- ---------- ----------
Cash - end of year $ 2,737 $ 5,319 $ 1,479
========== ========== ==========
Supplemental Cash Flow Information:
Cash paid during the year for:
Interest, net of amounts capitalized $ 45,639 $ 47,506 $ 47,369
========== ========== ==========
Income taxes $ 97,165 $ 56,458 $ 168,021
========== ========== ==========
|
The accompanying notes are an integral part of these consolidated financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A. ABOUT PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE Public Service Company of New Hampshire (PSNH or the company) is a wholly owned subsidiary of Northeast Utilities (NU). PSNH is registered with the Securities and Exchange Commission (SEC) under the Securities Exchange Act of 1934. NU is registered with the SEC as a holding company under the Public Utility Holding Company Act of 1935 (1935 Act), and NU, including PSNH, is subject to the provisions of the 1935 Act. Arrangements among PSNH, other NU companies, outside agencies, and other utilities covering interconnections, interchange of electric power and sales of utility property, are subject to regulation by the Federal Energy Regulatory Commission (FERC) and/or the SEC. PSNH is subject to further regulation for rates, accounting and other matters by the FERC and the New Hampshire Public Utilities Commission (NHPUC). PSNH, The Connecticut Light and Power Company (CL&P), and Western Massachusetts Electric Company (WMECO), furnish franchised retail electric service in New Hampshire, Connecticut and Massachusetts, respectively.
Several wholly owned subsidiaries of NU provide support services for NU's companies, including PSNH. Northeast Utilities Service Company (NUSCO) provides centralized accounting, administrative, engineering, financial, information technology, legal, operational, planning, purchasing, and other services to NU's companies.
B. PRESENTATION The consolidated financial statements of PSNH and of its subsidiaries, as applicable, include the accounts of all their respective subsidiaries. Intercompany transactions have been eliminated in consolidation.
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingencies at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Certain reclassifications of prior years' data have been made to conform with the current year's presentation. Reclassifications were made to cost of removal, regulatory asset and liability amounts and special deposits on the accompanying consolidated balance sheets and operating revenues and fuel, purchased and net interchange power on the accompanying consolidated statements of income. Reclassifications have also been made to the accompanying consolidated statements of cash flows.
C. NEW ACCOUNTING STANDARDS Derivative Accounting: Effective January 1, 2001, PSNH adopted Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended. In April 2003, the Financial Accounting Standards Board (FASB) issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities," which amends SFAS No. 133. This new statement incorporates interpretations that were included in previous Derivative Implementation Group guidance, clarifies certain conditions, and amends other existing pronouncements. It is effective for contracts entered into or modified after June 30, 2003. The adoption of SFAS No. 149 resulted in fair value accounting for certain PSNH contracts that are subject to unplanned netting and do not meet the definition of capacity contracts. These non-trading derivative contracts are recorded at fair value at December 31, 2003, as derivative assets and liabilities with offsetting amounts recorded as regulatory liabilities and assets because the contracts are part of providing regulated electric or gas service.
In August of 2003, the FASB ratified the consensus reached by its Emerging Issues Task Force (EITF) in July 2003 on EITF Issue No. 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." Prior to Issue No. 03-11, no specific guidance existed to address the classification in the income statement of derivative contracts that are not held for trading purposes. The consensus states that determining whether realized gains and losses on contracts that physically deliver and are not held for trading purposes should be reported on a net or gross basis is a matter of judgment that depends on the relevant facts and circumstances. PSNH has derivative sales contracts, and though these contracts may result in physical delivery, management has determined, based on the relevant facts and circumstances, that because these transactions are part of PSNH's procurement activities, inclusion in operating expenses better depicts these sales activities. At December 31, 2003, settlements of these derivative contracts that are not held for trading purposes, though previously reported on a gross basis, are reported on a net basis in expenses. Sales amounting to $48.9 million for the first nine months of 2003 were reflected as revenues in quarterly reporting but are now included in expenses.
In Issue No. 03-11, the EITF did not provide transition guidance, which management could have interpreted as becoming applicable on October 1, 2003 for revenues from that date forward. However, management applied its conclusion on net or gross reporting to all periods presented to enhance comparability. Operating revenues and fuel, purchased and net interchange power for the year ended December 31, 2003 reflect net reporting. The adoption of net reporting had no effect on net income.
The impact on previously reported 2002 and 2001 amounts is as follows:
---------------------------------------------------------------------
For the Years Ended December 31,
---------------------------------------------------------------------
(Millions of Dollars) 2002 2001
---------------------------------------------------------------------
Operating Revenues:
As previously reported $1,046.8 $1,171.6
Impact of reclassifications (99.6) (207.2)
---------------------------------------------------------------------
As currently reported $ 947.2 $ 964.4
---------------------------------------------------------------------
Fuel, Purchased and Net
Interchange Power:
As previously reported $ 388.0 $ 713.6
Impact of reclassifications (99.6) (207.2)
---------------------------------------------------------------------
As currently reported $ 288.4 $ 506.4
---------------------------------------------------------------------
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Employers' Disclosures about Pensions and Other Postretirement Benefits: In December 2003, the FASB issued SFAS No. 132 (Revised 2003), "Employers' Disclosures about Pensions and Other Postretirement Benefits," (SFAS No. 132R). This statement revises employers' disclosures about pension plans and other postretirement benefit plans, requires additional disclosures about the assets, obligations, cash flows, and the net periodic benefit cost of defined benefit pension plans and other defined benefit postretirement plans and requires companies to disclose various elements of pension and postretirement benefit costs in interim period financial statements. The revisions in SFAS No. 132R are effective for 2003, and PSNH included the disclosures required by SFAS No. 132R in this annual report. For the required disclosures, see Note 5, "Pension Benefits and Postretirement Benefits Other Than Pensions," to the consolidated financial statements.
Liabilities and Equity: In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity." SFAS No. 150 establishes standards on how to classify and measure certain financial instruments with characteristics of both liabilities and equity. SFAS No. 150 is effective for financial instruments entered into or modified after May 31, 2003, and was otherwise effective for PSNH for the third quarter of 2003. The adoption of SFAS No. 150 did not have an impact on PSNH's consolidated financial statements.
Consolidation of Variable Interest Entities: In December 2003, the FASB issued a revised version of FASB Interpretation No. (FIN) 46 "Consolidation of Variable Interest Entities," (FIN 46R). FIN 46R is effective for PSNH for the first quarter of 2004 but is not expected to have an impact on PSNH's consolidated financial statements.
D. GUARANTEES At December 31, 2003, NU had outstanding guarantees to PSNH of $4.4 million. PSNH has no guarantees outstanding at December 31, 2003.
E. REVENUES PSNH retail revenues are based on rates approved by the NHPUC. These regulated rates are applied to customers' use of energy to calculate a bill. In general, rates can only be changed through formal proceedings with the NHPUC.
NHPUC utilizes regulatory commission-approved tracking mechanisms to track the recovery of certain incurred costs. The tracking mechanisms allow for rates to be changed periodically, with overcollections refunded to customers or underrecollections collected from customers in future periods.
Unbilled revenues represent an estimate of electricity delivered to customers that has not been billed. Unbilled revenues represent assets on the balance sheet that become accounts receivable in the following month as customers are billed. Billed revenues are based on meter readings.
Unbilled revenues are estimated monthly using the requirements method. The requirements method utilizes the total monthly volume of electricity or gas delivered to the system and applies a delivery efficiency factor to reduce the total monthly volume by an estimate of delivery losses in order to calculate total estimated monthly sales to customers. The total estimated monthly sales amount less total monthly billed sales amount results in a monthly estimate of unbilled sales. Unbilled revenues are estimated by applying an average rate to the estimate of unbilled sales.
In 2003, the unbilled sales estimates for PSNH were tested using the cycle method. The cycle method uses the billed sales from each meter reading cycle and an estimate of unbilled days in each month based on the meter reading schedule. The cycle method is historically more accurate than the requirements method when used in a mostly weather-neutral month. The cycle method resulted in adjustments to the estimate of unbilled revenues that had a positive after-tax earnings impact on PSNH of $3.3 million in 2003.
Wholesale transmission revenues are based on rates and formulas that are approved by the FERC. Most of PSNH's wholesale transmission revenues are collected through a combination of the New England Regional Network Service (RNS) tariff and PSNH's Local Network Service (LNS) tariff. The RNS tariff, which is administered by the New England Independent System Operator, recovers the revenue requirements associated with transmission facilities that are deemed by the FERC to be Pool Transmission Facilities. The LNS tariff which was accepted by the FERC on October 22, 2003, provides for the recovery of PSNH's total transmission revenue requirements, net of revenue credits received from various rate components, including revenues received under the RNS rates.
F. ACCOUNTING FOR ENERGY CONTRACTS The accounting treatment for energy contracts entered into varies between contracts and depends on the intended use of the particular contract and on whether or not the contracts are derivatives.
Non-derivative contracts that are entered into for the normal purchase or sale of energy to customers that will result in physical delivery are recorded at the point of delivery under accrual accounting.
Derivative contracts that are entered into for the normal purchase and sale of energy and meet the normal purchase and sale exception to derivative accounting, as defined in SFAS No. 133 and amended by SFAS No. 149 (normal), are also recorded at the point of delivery under accrual accounting.
Both non-derivative contracts and derivative contracts that are normal are recorded in revenues when these contracts represent sales, and recorded in fuel, purchased and net interchange power when these contracts represent purchases, except for sales contracts that relate to procurement activities. These contracts are recorded in fuel, purchased and net interchange power when settled.
Derivative contracts that are not held for trading purposes and that do not qualify as normal purchases and sales or hedges are non-trading derivative contracts. These contracts are recorded on the consolidated balance sheets at fair value, and since management believes that these costs will continue to be recovered or refunded in rates, the changes in fair value are offset by regulatory assets and liabilities.
For further information regarding these contracts and their accounting, see Note 4, "Derivative Instruments and Risk Management Activities," to the consolidated financial statements.
G. REGULATORY ACCOUNTING The accounting policies of PSNH conform to accounting principles generally accepted in the United States of America applicable to rate-regulated enterprises and historically reflect the effects of the rate-making process in accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation."
The transmission, distribution and generation businesses of PSNH continue to be cost-of-service rate regulated. The state's electric utility industry restructuring laws have been modified to delay the sale of PSNH's fossil and hydroelectric generation assets until at least April of 2006. There has been no regulatory action to the contrary, and management currently has no plans to divest these generation assets. As the NHPUC has allowed and is expected to continue to allow rate recovery of a return on and recovery of these assets, as well as all operating expenses, PSNH meets the criteria for the application of SFAS No. 71. Stranded costs related to generation assets, to the extent not currently recovered in rates, are deferred as Part 3 stranded costs under the "Agreement to Settle PSNH Restructuring" (Restructuring Settlement). Part 3 stranded costs are nonsecuritized regulatory assets which must be recovered by a recovery end date determined in accordance with the Restructuring Settlement or be written off.
Management believes the application of SFAS No. 71 to the portions of the aforementioned businesses continues to be appropriate. Management also believes it is probable that PSNH will recover their investments in long- lived assets, including regulatory assets. In addition, all material net regulatory assets are earning an equity return, except for securitized regulatory assets, which are not supported by equity.
The components of regulatory assets are as follows:
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At December 31,
----------------------------------------------------------------
(Millions of Dollars) 2003 2002
----------------------------------------------------------------
Recoverable nuclear costs $ 33.3 $ 36.8
Securitized assets 465.3 505.4
Income taxes, net 44.2 96.5
Unrecovered contractual obligations 69.9 58.7
Recoverable energy costs 218.3 241.7
Other 138.4 87.0
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Totals $969.4 $1,026.1
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Recoverable Nuclear Costs: In March 2001, PSNH recorded a regulatory asset in conjunction with the sale of the Millstone nuclear units (Millstone) with an unamortized balance of $33.3 million and $36.8 million at December 31, 2003 and 2002, respectively, which is included in recoverable nuclear costs.
Securitized Assets: In April 2001, PSNH issued rate reduction certificates in the amount of $525 million. PSNH used the majority of this amount to buy down its power contract with North Atlantic Energy Corporation (NAEC). The remaining balance is $427 million and $460 million at December 31, 2003 and 2002, respectively.
In January 2002, PSNH issued an additional $50 million in rate reduction certificates and used the proceeds from this issuance to repay short-term debt that was incurred to buy out a purchased-power contract in December 2001. The remaining balance is $38 million and $46 million at December 31, 2003 and 2002, respectively.
Securitized assets are being recovered over the amortization period of their associated rate reduction bonds. All outstanding rate reduction bonds of PSNH are scheduled to fully amortize by May 1, 2013.
Income Taxes, Net: The tax effect of temporary differences (differences between the periods in which transactions affect income in the financial statements and the periods in which they affect the determination of taxable income) is accounted for in accordance with the rate-making treatment of the NHPUC and SFAS No. 109. Differences in income taxes between SFAS No. 109 and the rate-making treatment of the NHPUC are recorded as regulatory assets. For further information regarding income taxes, see Note 1H, "Summary of Significant Accounting Policies - Income Taxes," and Note 12, "Income Tax Expense," to the consolidated financial statements.
Unrecovered Contractual Obligations: PSNH, under the terms of contracts with the Yankee Companies, is responsible for their proportionate share of the remaining costs of the units, including decommissioning. These amounts are recorded as unrecovered contractual obligations and are recovered as stranded costs. During 2002, PSNH was notified by the Yankee Companies that the estimated cost of decommissioning their units had increased over prior estimates due to higher anticipated costs for spent fuel storage, security and liability and property insurance. In December 2002, PSNH recorded an additional $23.6 million in deferred contractual obligations and a corresponding increase in the unrecovered contractual obligations regulatory asset as a result of these increased costs.
In November 2003, the Connecticut Yankee Atomic Power Company (CYAPC) prepared an updated estimate of the cost of decommissioning its nuclear unit. PSNH's aggregate share of the estimated increased cost is $17.1 million. PSNH recorded an additional $17.1 million in deferred contractual obligations and a corresponding increase in the unrecovered contractual obligations regulatory asset as a result of these increased costs.
Recoverable Energy Costs: In conjunction with the implementation of restructuring under the Restructuring Settlement on May 1, 2001, PSNH's fuel and purchased-power adjustment clause (FPPAC) was discontinued. At December 31, 2003 and 2002, PSNH had $162.2 million and $179.6 million, respectively, of recoverable energy costs deferred under the FPPAC, including previous deferrals of purchases from IPPs. Under the Restructuring Settlement, the FPPAC deferrals are recovered as a Part 3 stranded cost through a stranded cost recovery charge (SCRC). Also included in PSNH's recoverable energy costs are costs associated with certain contractual purchases from IPPs that had previously been included in the FPPAC. These costs are treated as Part 3 stranded costs and amounted to $56.1 million and $62.1 million at December 31, 2003 and 2002, respectively.
PSNH's recoverable energy costs are Part 3 stranded costs which are nonsecuritized regulatory assets which must be recovered by a recovery end date to be determined in accordance with the Restructuring Settlement or which will be written off. Based on current projections, PSNH expects to fully recover all of its Part 3 stranded costs by the recovery end date.
Regulatory Liabilities: PSNH maintained $272.1 million and $254.1 million of regulatory liabilities at December 31, 2003 and 2002, respectively. These amounts are comprised of the following:
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At December 31,
----------------------------------------------------------------
(Millions of Dollars) 2003 2002
----------------------------------------------------------------
Cost of removal $ 88.0 $ 67.0
SCRC overcollections 160.4 166.2
Regulatory liabilities offsetting
derivative assets 1.5 -
Other regulatory liabilities 22.2 20.9
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Totals $272.1 $254.1
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Under SFAS No. 71, PSNH currently recovers amounts in rates for future costs of removal of plant assets. Historically, these amounts were included as a component of accumulated depreciation until spent. These amounts were reclassified to regulatory liabilities on the accompanying consolidated balance sheets.
The SCRC allows PSNH to recover its stranded costs.
The regulatory liabilities offsetting derivative assets relate to the fair value of purchase and sales contracts used for market discovery of future procurement activities that will benefit ratepayers in the future. PSNH also has financial transmission rights (FTR) contracts which are derivative assets offset by a regulatory liability.
H. INCOME TAXES The tax effect of temporary differences (differences between the periods in which transactions affect income in the financial statements and the periods in which they affect the determination of taxable income) is accounted for in accordance with the rate-making treatment of the applicable regulatory commissions and SFAS No. 109.
The tax effects of temporary differences that give rise to the net accumulated deferred tax obligation are as follows:
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At December 31,
----------------------------------------------------------------
(Millions of Dollars) 2003 2002
----------------------------------------------------------------
Deferred tax liabilities:
Accelerated depreciation and
other plant-related differences $117.6 $100.0
Regulatory amounts:
Securitized contract termination
costs and other 173.3 183.0
Deferrals of fuel and small
power producer costs 91.9 94.0
Income tax gross-up 17.8 38.0
Other 68.7 66.1
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Total deferred tax liabilities 469.3 481.1
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Deferred tax assets:
Regulatory deferrals 96.7 90.2
Employee benefits 21.0 18.7
Income tax gross-up 1.0 1.2
Other 11.7 11.1
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Total deferred tax assets 130.4 121.2
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Totals $338.9 $359.9
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NU and its subsidiaries, including PSNH, file a consolidated federal income tax return. Likewise NU and its subsidiaries, including PSNH, file state income tax returns, with some filing in more than one state. NU and its subsidiaries, including PSNH, are parties to a tax allocation agreement under which each taxable subsidiary pays a quarterly estimate (or settlement) of no more than it would have otherwise paid had it filed a stand-alone tax return. Generally these quarterly estimated payments are settled to actual payments within three months after filing the associated return. Subsidiaries generating tax losses are similarly paid for their losses when utilized.
In 2000, NU requested from the Internal Revenue Service (IRS) a Private Letter Ruling (PLR) regarding the treatment of unamortized investment tax credits (ITC) and excess deferred income taxes (EDIT) related to generation assets that have been sold. EDIT are temporary differences between book and taxable income that were recorded when the federal statutory tax rate was higher than it is now or when those differences were expected to be resolved. The PLR addresses whether or not EDIT and ITC can be returned to customers, which without a PLR management believes would represent a violation of current tax law. The IRS declared a moratorium on issuing PLRs until final regulations on the return of EDIT and ITC to regulated customers are issued by the Treasury Department. Proposed regulations were issued in March 2003, and a hearing took place in June 2003. The proposed new regulations would allow the return of EDIT and ITC to regulated customers without violating the tax law. Also, under the proposed regulations, a company could elect to apply the regulation retroactively. The Treasury Department is currently deliberating the comments received at the hearing. If final regulations consistent with the proposed regulations are issued, then there could be an impact on PSNH's financial statements.
I. DEPRECIATION The provision for depreciation on utility assets is calculated using the straight-line method based on the estimated remaining useful lives of depreciable plant-in-service, which range primarily from 14 years to 75 years, adjusted for salvage value and removal costs, as approved by the appropriate regulatory agency where applicable. Depreciation rates are applied to plant-in-service from the time it is placed in service. When plant is retired from service, the original cost of the plant, including costs of removal less salvage, is charged to the accumulated provision for depreciation. Cost of removal is now classified as a regulatory liability. The depreciation rates for the several classes of electric utility plant-in- service are equivalent to a composite rate of 3 percent in 2003, 2002 and 2001.
J. EQUITY INVESTMENTS AND JOINTLY OWNED ELECTRIC UTILITY PLANT Regional Nuclear Companies: At December 31, 2003, PSNH owns common stock in three regional nuclear companies (Yankee Companies). PSNH's ownership interests in the Yankee Companies at December 31, 2003, which are accounted for on the equity method are 5 percent of the CYAPC, 7 percent of the Yankee Atomic Electric Company (YAEC) and 5 percent of the Maine Yankee Atomic Power Company (MYAPC). Effective November 7, 2003, PSNH sold its collective 4.3 percent ownership interest in Vermont Yankee Nuclear Power Corporation (VYNPC). PSNH's total equity investment in the Yankee Companies at December 31, 2003 and 2002 is $4.6 million and $8 million respectively. Each of the remaining Yankee Companies owns a single nuclear generating plant which is being decommissioned.
K. ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION The allowance for funds used during construction (AFUDC) is a non-cash item that is included in the cost of utility plant and represents the cost of borrowed and equity funds used to finance construction. The portion of AFUDC attributable to borrowed funds is recorded as a reduction of other interest expense, and the cost of equity funds is recorded as other income on the consolidated statements of income:
-----------------------------------------------------------
For the Years Ended December 31,
-----------------------------------------------------------
(Millions of Dollars,
except percentages) 2003 2002 2001
-----------------------------------------------------------
Borrowed funds $0.6 $1.0 $0.9
Equity funds 0.6 0.6 1.7
-----------------------------------------------------------
Totals $1.2 $1.6 $2.6
-----------------------------------------------------------
Average AFUDC rates 3.9% 4.7% 8.8%
-----------------------------------------------------------
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L. ASSET RETIREMENT OBLIGATIONS In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." This statement requires that legal obligations associated with the retirement of property, plant and equipment be recognized as a liability at fair value when incurred and when a reasonable estimate of the fair value of the liability can be made. SFAS No. 143 was effective on January 1, 2003, for PSNH. Management has completed its review process for potential asset retirement obligations (ARO) and has not identified any material AROs that have been incurred. However, management identified certain removal obligations that arise in the ordinary course of business or have a low probability of occurring. These types of obligations primarily relate to transmission and distribution lines and poles, telecommunication towers, transmission cables and certain FERC or state regulatory agency re-licensing issues. These obligations are AROs that have not been incurred or are not material in nature.
A portion of PSNH's rates is intended to recover the cost of removal of certain utility assets. The amounts recovered do not represent AROs. At December 31, 2003 and 2002, cost of removal was approximately $88 million and $67 million, respectively.
M. MATERIALS AND SUPPLIES Materials and supplies include materials purchased primarily for construction, operation and maintenance (O&M) purposes. Materials and supplies are valued at the lower of average cost or market.
N. SPECIAL DEPOSITS Special deposits represents $30.1 million in escrow that PSNH funded to acquire Connecticut Valley Electric Company, Inc. on January 1, 2004.
O. OTHER (LOSS)/INCOME The pre-tax components of PSNH's other (loss)/income items are as follows:
---------------------------------------------------------------------
For the Years Ended December 31,
---------------------------------------------------------------------
(Millions of Dollars) 2003 2002 2001
---------------------------------------------------------------------
Gain related to Millstone sale $ - $ - $25.9
Investment income 0.1 1.2 2.3
Charitable donations (0.4) (0.4) (0.7)
Other (4.7) (2.5) 9.1
---------------------------------------------------------------------
Totals $(5.0) $(1.7) $36.6
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PSNH and NAEC had entered into two power contracts that previously obligated PSNH to purchase NAEC's 35.98 percent ownership of the capacity and output of Seabrook for the term of Seabrook's operating license. NAEC's cost of service included all of its Seabrook-related costs, including O&M expenses, fuel expense, income and property tax expense, depreciation expense, certain overhead and other costs, and a return on its allowed investment. With the implementation of the Settlement Agreement, PSNH and NAEC restructured the power contracts and bought down the value of the Seabrook plant asset, as defined within the Settlement Agreement, to $100 million. On November 1, 2002, NAEC consummated the sale of its investment in Seabrook and refunded the remaining proceeds from the sale to PSNH through the Seabrook Power Contracts. With the sale of NAEC's ownership interest in Seabrook, sales of capacity and output under the Seabrook Power Contracts ended.
Limits: The amount of short-term borrowings that may be incurred by PSNH is subject to periodic approval by either the SEC under the 1935 Act or by the NHPUC. On June 30, 2003, the SEC granted authorization allowing PSNH to incur total short-term borrowings up to a maximum of $100 million through June 30, 2006, with authorization for borrowings from the NU Money Pool (Pool) granted through June 30, 2004.
PSNH is authorized by the NHPUC to incur short-term borrowings up to a maximum of $100 million.
Credit Agreement: On November 10, 2003, PSNH, CL&P, WMECO and Yankee Gas entered into a 364-day unsecured revolving credit facility for $300 million. This facility replaces a similar credit facility that expired on November 11, 2003 and PSNH may draw up to $100 million under this facility. Unless extended, the credit facility will expire on November 8, 2004. At December 31, 2003 and 2002, there were $10 million and no borrowings, respectively, under these credit facilities.
Under the aforementioned credit agreement, PSNH may borrow at fixed or variable rates plus an applicable margin based upon certain debt ratings, as rated by the lower of Standard and Poor's or Moody's Investors Service. The weighted average interest rate on PSNH's notes payable to banks outstanding on December 31, 2003 was 2 percent.
Under the credit agreement, PSNH must comply with certain financial and non- financial covenants as are customarily included in such agreements, including but not limited to, consolidated debt ratios and interest coverage ratios. The most restrictive financial covenant is the interest coverage ratio. PSNH currently is and expects to remain in compliance with these covenants.
Pool: PSNH is a member of the Pool. The Pool provides a more efficient use of the cash resources of NU and reduces outside short-term borrowings. NUSCO administers the Pool as agent for the member companies. Short-term borrowing needs of the member companies are first met with available funds of other member companies, including funds borrowed by NU parent. NU parent may lend to the Pool but may not borrow. Funds may be withdrawn from or repaid to the Pool at any time without prior notice. Investing and borrowing subsidiaries receive or pay interest based on the average daily federal funds rate. Borrowings based on loans from NU parent, however, bear interest at NU parent's cost and must be repaid based upon the terms of NU parent's original borrowing. At December 31, 2003 and 2002, PSNH had borrowings of $48.9 million and lendings of $23 million to the Pool, respectively. The interest rate on borrowings from and lendings to the Pool at December 31, 2003 and 2002 was 1 percent and 1.2 percent, respectively.
A. DERIVATIVE INSTRUMENTS Effective January 1, 2001, PSNH adopted SFAS No. 133, as amended. Derivatives that do not meet the definition of a cash flow hedge and cannot be designated as being used for normal purchases or normal sales are also recorded at fair value with changes in fair value included in earnings unless recorded as a regulatory asset or liability. Derivative contracts that are entered into as a normal purchase or sale and will result in physical delivery, and are documented as such, are recorded under accrual accounting. For information regarding accounting changes related to derivative instruments, see Note 1C, "Summary of Significant Accounting Policies - New Accounting Standards," to the consolidated financial statements.
In 2003, there were changes to interpretations of as well as an amendment to SFAS No. 133, and the FASB continues to consider changes that could affect the way PSNH records and discloses derivative and hedging activities.
PSNH has energy contracts that are subject to unplanned netting and do not meet the definition of capacity contracts. These non-trading derivative contracts were recorded at fair value at December 31, 2003 as derivative assets of approximately $1.4 million and derivative liabilities with a fair value of approximately $1.4 million with offsetting regulatory assets and regulatory liabilities, respectively.
To mitigate the risk associated with certain supply contracts, PSNH purchased FTRs. FTRs are derivatives that cannot qualify for the normal purchases and sales exception. The fair value of these FTR non-trading derivatives at December 31, 2003 was an asset of $0.1 million. PSNH had no non-trading derivatives at December 31, 2002 that were required to be recorded at fair value.
B. RISK MANAGEMENT ACTIVITIES PSNH is subject to credit risk from certain long-term or high-volume supply contracts with energy marketing companies. Credit risks and market risks at PSNH are monitored regularly by a Risk Oversight Council operating outside of the business units that create or actively manage these risk exposures to ensure compliance with NU's stated risk management policies.
Pension Benefits: PSNH participates in a uniform noncontributory defined benefit retirement plan (Pension Plan) covering substantially all regular NU employees. Benefits are based on years of service and the employees' highest eligible compensation during 60 consecutive months of employment. Pre-tax pension expense/(income) was $6.8 million of expense in 2003, $0.6 million of expense in 2002, and $3.9 million of income in 2001. These amounts exclude pension settlements, curtailments and net special termination expense of $1.3 million in 2001. PSNH uses a December 31 measurement date for the Pension Plan. Pension expense/(income)attributable to earnings is as follows:
-------------------------------------------------------------------------
For the Years Ended December 31,
-------------------------------------------------------------------------
(Millions of Dollars) 2003 2002 2001
-------------------------------------------------------------------------
Pension expense/(income) before
settlements, curtailments
and special termination benefits $ 6.8 $ 0.6 $(3.9)
Net pension expense/(income)
capitalized as utility plant (2.0) (0.2) (1.4)
-------------------------------------------------------------------------
Net pension expense/(income)
before settlements, curtailments
and special termination
benefits 4.8 0.4 (2.5)
Settlements, curtailments and
special termination benefits
reflected in earnings - - 1.2
-------------------------------------------------------------------------
Total pension expense/(income)
included in earnings $ 4.8 $ 0.4 $(1.3)
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|
Pension Settlements, Curtailments and Special Termination Benefits: There were no settlements, curtailments or special termination benefits in 2002 and 2003.
In conjunction with the Voluntary Separation Program (VSP) that was announced in December 2000, PSNH recorded $0.5 million in settlement income and $0.3 million in curtailment income in 2001. The VSP was intended to reduce the generation-related support staff between March 1, 2001 and February 28, 2002, and was available to non-bargaining unit employees who, by February 1, 2002, were at least age 50, with a minimum of five years of credited service, and at December 15, 2000, were assigned to certain groups and in eligible job classifications.
One component of the VSP included special pension termination benefits equal to the greater of 5 years added to both age and credited service of eligible participants or two weeks of pay for each year of service subject to a minimum level of 12 weeks and a maximum of 52 weeks for eligible participants. The special pension termination benefits expense associated with the VSP totaled $2.1 million in 2001. The net total of the settlement and curtailment income and the special termination benefits expense was $1.3 million, of which $1.2 million of costs were included in operating expenses, $0.1 million was deferred as a regulatory liability and is expected to be returned to customers.
Postretirement Benefits Other Than Pensions (PBOP): PSNH also provides certain health care benefits, primarily medical and dental, and life insurance benefits through a benefit plan to retired employees (PBOP Plan). These benefits are available for employees retiring from PSNH who have met specified service requirements. For current employees and certain retirees, the total benefit is limited to two times the 1993 per retiree health care cost. These costs are charged to expense over the estimated work life of the employee. PSNH uses a December 31 measurement date for the PBOP Plan. PSNH annually funds postretirement costs through external trusts with amounts that have been rate-recovered and which also are tax deductible.
In 2002, the PBOP Plan was amended to change the claims experience basis, to increase minimum retiree contributions and to reduce the cap on the company's subsidy to the dental plan. These amendments resulted in a $4.6 million decrease in PSNH's benefit obligation under the PBOP Plan at December 31, 2002.
Impact of New Medicare Changes on PBOP: On December 8, 2003, the President signed into law a bill that expands Medicare, primarily by adding a prescription drug benefit starting in 2006 for Medicare-eligible retirees as well as a federal subsidy to plan sponsors of retiree health care benefit plans who provide a prescription drug benefit at least actuarially equivalent to the new Medicare benefit.
Based on the current PBOP Plan provisions, PSNH's actuaries believe that PSNH will qualify for this federal subsidy because the actuarial value of PSNH's PBOP Plan is estimated to be 60 percent greater than that of the standard Medicare benefit. PSNH will directly benefit from the federal subsidy for retirees who retired before 1993. For other retirees, management does not believe that PSNH will benefit from the subsidy because PSNH's cost support for these retirees is capped at a fixed dollar commitment.
The aggregate effect of recognizing the Medicare change is a decrease to the PBOP benefit obligation of $4.4 million. This amount includes the present value of the future government subsidy, which was estimated by discounting the expected payments using the actuarial assumptions used to determine the PBOP liability at December 31, 2003. Also included in the $4.4 million estimate is a decrease in the assumed participation in NU's retiree health plan from 95 percent to 85 percent for future retirees, which reflects the expectation that the Medicare prescription benefit will produce insurer- sponsored health plans that are more financially attractive to future retirees. The per capita claims cost estimate was not changed. Management reduced the PBOP benefit obligation as of December 31, 2003 by $4.4 million and recorded this amount as an actuarial gain within unrecognized net loss/(gain) in the tables that follow. The $4.4 million actuarial gain will be amortized beginning in 2004 as a reduction to PBOP expense over the future working lifetime of employees covered under the plan (approximately 13 years). PBOP expense in 2004 will also reflect a lower interest cost due to the reduction in the December 31, 2003 benefit obligation.
Specific authoritative guidance on accounting for the effect of the Medicare federal subsidy on PBOP plans and amounts is pending from the FASB. When issued, that guidance could require PSNH to change the accounting described above and change the information reported herein.
PBOP Settlements, Curtailments and Special Termination Benefits: There were no settlements, curtailments or special termination benefits in 2002 and 2003. In 2001, PSNH recorded PBOP special termination benefits expense totaling $0.2 million in connection with the VSP. This amount was recorded as a regulatory asset and collected through regulated utility rates in 2002.
The following table represents information on the plans' benefit obligation, fair value of plan assets, and the respective plans' funded status:
----------------------------------------------------------------------------------------------------------
At December 31,
----------------------------------------------------------------------------------------------------------
Pension Benefits Postretirement Benefits
----------------------------------------------------------------------------------------------------------
(Millions of Dollars) 2003 2002 2003 2002
----------------------------------------------------------------------------------------------------------
Change in benefit obligation
Benefit obligation at beginning of year $(260.9) $(227.9) $(63.7) $(65.4)
Service cost (6.4) (5.8) (1.1) (1.1)
Interest cost (17.3) (16.8) (4.5) (4.6)
Medicare impact - - 4.4 -
Plan amendment - (1.8) - 4.6
Transfers - (0.5) - -
Actuarial loss (17.3) (20.6) (8.5) (4.1)
Benefits paid - excluding lump sum payments 12.9 12.3 6.6 6.9
Benefits paid - lump sum payments - 0.2 - -
Curtailments and settlements - - - -
Special termination benefits - - - -
----------------------------------------------------------------------------------------------------------
Benefit obligation at end of year $(289.0) $(260.9) $(66.8) $(63.7)
----------------------------------------------------------------------------------------------------------
Change in plan assets
Fair value of plan assets at beginning of year $ 163.5 $ 196.6 $ 24.4 $ 28.4
Actual return on plan assets 41.3 (21.1) 5.7 (2.5)
Employer contribution - - 6.2 5.4
Plan asset transfer in - 0.5 - -
Benefits paid - excluding lump sum payments (12.9) (12.3) (6.6) (6.9)
Benefits paid - lump sum payments - (0.2) - -
----------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of year $ 191.9 $ 163.5 $ 29.7 $ 24.4
----------------------------------------------------------------------------------------------------------
Funded status at December 31 $ (97.1) $ (97.4) $(37.1) $(39.3)
Unrecognized transition (asset)/obligation 2.0 2.3 22.4 24.8
Unrecognized prior service cost 13.0 14.5 - -
Unrecognized net loss/(gain) 37.3 42.7 14.7 14.4
----------------------------------------------------------------------------------------------------------
Prepaid/(accrued) benefit cost $ (44.8) $ (37.9) $ - $ (0.1)
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The accumulated benefit obligation for the Pension Plan was $243.6 million and $218.4 million at December 31, 2003 and 2002, respectively. Plan assets for the entire Pension Plan on an NU consolidated basis are approximately $240 million more than the accumulated benefit obligation at December 31, 2003.
The following actuarial assumptions were used in calculating the plans' year end funded status:
-------------------------------------------------------------------------------
At December 31,
-------------------------------------------------------------------------------
Balance Sheets Pension Benefits Postretirement Benefits
-------------------------------------------------------------------------------
2003 2002 2003 2002
-------------------------------------------------------------------------------
Discount rate 6.25% 6.75% 6.25% 6.75%
Compensation/progression rate 3.75% 4.00% N/A N/A
Health care cost trend rate N/A N/A 9.00% 10.00%
-------------------------------------------------------------------------------
|
The components of net periodic (income)/expense are as follows:
-----------------------------------------------------------------------------------------------------------------------
For the Years Ended December 31,
-----------------------------------------------------------------------------------------------------------------------
Pension Benefits Postretirement Benefits
-----------------------------------------------------------------------------------------------------------------------
(Millions of Dollars) 2003 2002 2001 2003 2002 2001
-----------------------------------------------------------------------------------------------------------------------
Service cost $ 6.4 $ 5.8 $ 5.0 $ 1.1 $ 1.1 $ 1.1
Interest cost 17.3 16.8 15.8 4.5 4.6 4.3
Expected return on plan assets (18.2) (20.3) (20.9) (2.6) (2.9) (2.9)
Amortization of unrecognized net
transition (asset)/obligation 0.3 0.3 0.3 2.5 2.8 2.9
Amortization of prior service cost 1.5 1.4 1.3 - - -
Amortization of actuarial gain (0.5) (3.4) (5.4) - - -
Other amortization, net - - - 0.7 (0.3) (1.1)
-----------------------------------------------------------------------------------------------------------------------
Net periodic (income)/expense - before
settlements, curtailments and special
termination benefits 6.8 0.6 (3.9) 6.2 5.3 4.3
-----------------------------------------------------------------------------------------------------------------------
Settlement income - - (0.5) - - -
Curtailment income - - (0.3) - - -
Special termination benefits expense - - 2.1 - - 0.2
-----------------------------------------------------------------------------------------------------------------------
Total - settlements, curtailments and special
termination benefits - - 1.3 - - 0.2
----------------------------------------------------------------------------------------------------------------------
Total - net periodic (income)/expense $ 6.8 $ 0.6 $ (2.6) $ 6.2 $ 5.3 $ 4.5
-----------------------------------------------------------------------------------------------------------------------
|
For calculating pension and postretirement benefit income and expense amounts, the following assumptions were used:
-----------------------------------------------------------------------------------------
For the Years Ended December 31,
-----------------------------------------------------------------------------------------
Statements of Income Pension Benefits Postretirement Benefits
-----------------------------------------------------------------------------------------
2003 2002 2001 2003 2002 2001
-----------------------------------------------------------------------------------------
Discount rate 6.75% 7.25% 7.50% 6.75% 7.25% 7.50%
Expected long-term rate of return 8.75% 9.25% 9.50% 8.75% 9.25% 9.50%
Compensation/progression rate 4.00% 4.25% 4.50% N/A N/A N/A
-----------------------------------------------------------------------------------------
|
The following table represents the PBOP assumed health care cost trend rate for the next year and the assumed ultimate trend rate:
--------------------------------------------------------------------
Year Following December 31,
---------------------------------------------------------------------
2003 2002
---------------------------------------------------------------------
Health care cost trend rate
assumed for next year 8.00% 9.00%
Rate to which health care cost
trend rate is assumed to
decline (the ultimate trend rate) 5.00% 5.00%
Year that the rate reaches the
ultimate trend rate 2007 2007
---------------------------------------------------------------------
|
The annual per capita cost of covered health care benefits was assumed to decrease by one percentage point each year through 2007.
Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. The effect of changing the assumed health care cost trend rate by one percentage point in each year would have the following effects:
---------------------------------------------------------------------
One Percentage One Percentage
(Millions of Dollars) Point Increase Point Decrease
---------------------------------------------------------------------
Effect on total service and
interest cost components $ 0.1 $(0.1)
Effect on postretirement
benefit obligation $ 2.0 $(1.8)
---------------------------------------------------------------------
|
PSNH's investment strategy for its Pension Plan and PBOP Plan is to maximize the long-term rate of return on those plans' assets within an acceptable level of risk. The investment strategy establishes target allocations, which are regularly reviewed and periodically rebalanced. PSNH's expected long- term rates of return on Pension Plan assets and PBOP Plan assets are based on these target asset allocation assumptions and related expected long-term rates of return. In developing its expected long-term rate of return assumptions for the Pension Plan and the PBOP Plan, PSNH also evaluated input from actuaries, consultants and economists as well as long-term inflation assumptions and PSNH's historical 20-year compounded return of approximately 11 percent. The Pension Plan's and PBOP Plan's target asset allocation assumptions and expected long-term rate of return assumptions by asset category are as follows:
-----------------------------------------------------------------------------------------------------------------
At December 31,
-----------------------------------------------------------------------------------------------------------------
Pension Benefits Postretirement Benefits
-----------------------------------------------------------------------------------------------------------------
2003 2002 2003 2002
-----------------------------------------------------------------------------------------------------------------
Target Assumed Target Assumed Target Assumed Target Assumed
Asset Rate of Asset Rate of Asset Rate of Asset Rate of
Asset Category Allocation Return Allocation Return Allocation Return Allocation Return
-----------------------------------------------------------------------------------------------------------------
Equity securities:
United States 45.00% 9.25% 45.00% 9.75% 55.00% 9.25% 55.00% 9.75%
Non-United States 14.00% 9.25% 14.00% 9.75% 11.00% 9.25% - -
Emerging markets 3.00% 10.25% 3.00% 10.75% 2.00% 10.25% - -
Private 8.00% 14.25% 8.00% 14.75% - - - -
Debt Securities:
Fixed income 20.00% 5.50% 20.00% 6.25% 27.00% 5.50% 45.00% 6.25%
High yield fixed
income 5.00% 7.50% 5.00% 7.50% 5.00% 7.50% - -
Real estate 5.00% 7.50% 5.00% 7.50% - - - -
-----------------------------------------------------------------------------------------------------------------
|
The actual asset allocations at December 31, 2003 and 2002, approximated these target asset allocations. The plans' actual weighted-average asset allocations by asset category are as follows:
--------------------------------------------------------------------------
At December 31,
--------------------------------------------------------------------------
Postretirement
Pension Benefits Benefits
--------------------------------------------------------------------------
Asset Category 2003 2002 2003 2002
--------------------------------------------------------------------------
Equity securities:
United States 47.00% 46.00% 59.00% 55.00%
Non-United States 18.00% 17.00% 12.00% -
Emerging markets 3.00% 3.00% 1.00% -
Private 3.00% 3.00% - -
Debt Securities:
Fixed income 19.00% 21.00% 25.00% 45.00%
High yield fixed
income 5.00% 5.00% 3.00% -
Real estate 5.00% 5.00% - -
-------------------------------------------------------------------------
Total 100.00% 100.00% 100.00% 100.00%
--------------------------------------------------------------------------
|
Currently, PSNH's policy is to annually fund an amount at least equal to that which will satisfy the requirements of the Employee Retirement Income Security Act and Internal Revenue Code.
PSNH does not expect to make any contributions to the Pension Plan in 2004 and expects to make $7 million in contributions to the PBOP Plan in 2004.
Postretirement health plan assets for non-union employees are subject to federal income taxes.
Seabrook: On November 1, 2002, NAEC consummated the sale of its 35.98 percent combined ownership interest in Seabrook to a subsidiary of FPL Group, Inc. (FPL). CL&P, NAEC and certain other of the joint owners collectively sold 88.2 percent of Seabrook to FPL. NAEC received approximately $331 million of total cash proceeds from the sale of Seabrook. A portion of this cash was used to repay all $90 million of NAEC's outstanding debt and other short-term debt, to return a portion of NAEC's equity to NU and was used to pay approximately $93 million in taxes. The remaining proceeds received by NAEC were refunded to PSNH through the Seabrook Power Contracts. As part of the sale, FPL assumed responsibility for decommissioning Seabrook.
VYNPC: On July 31, 2002, VYNPC consummated the sale of its nuclear generating plant to a subsidiary of Entergy Corporation (Entergy) for approximately $180 million. As part of the sale, Entergy assumed responsibility for decommissioning VYNPC's nuclear generating unit. On November 7, 2003, PSNH sold its 4.3 percent ownership interest in VYNPC. PSNH will continue to buy approximately 4 percent of the plant's output through March 2012 at a range of fixed prices.
A. RESTRUCTURING AND RATE MATTERS SCRC Reconciliation Filing: On an annual basis, PSNH files with the NHPUC an SCRC reconciliation filing for the preceding calendar year. This filing includes the reconciliation of stranded cost revenues with stranded costs, and transition energy service (TS) revenues with TS costs. The NHPUC reviews the filing, including a prudence review of PSNH's generation operations.
The 2003 SCRC filing is expected to be filed on May 1, 2004. Management does not expect the review of the 2003 SCRC filing to have a material effect on PSNH's net income or financial position.
B. ENVIRONMENTAL MATTERS General: PSNH is subject to environmental laws and regulations intended to mitigate or remove the effect of past operations and improve or maintain the quality of the environment. These laws and regulations require the removal or the remedy of the effect on the environment of the disposal or release of certain specified hazardous substances at current and former operating sites. As such, PSNH has an active environmental auditing and training program and believes that it is substantially in compliance with all enacted laws and regulations.
Environmental reserves are accrued using a probabilistic model approach when assessments indicate that it is probable that a liability has been incurred and an amount can be reasonably estimated. The probabilistic model approach estimates the liability based on the most likely action plan from a variety of available remediation options, ranging from no action to several different remedies ranging from establishing institutional controls to full site remediation and monitoring.
These estimates are subjective in nature as they take into consideration several different remediation options at each specific site. The reliability and precision of these estimates can be affected by several factors including new information concerning either the level of contamination at the site, recently enacted laws and regulations or a change in cost estimates due to certain economic factors.
The amounts recorded as environmental liabilities on the consolidated balance sheets represent management's best estimate of the liability for environmental costs and takes into consideration site assessment and remediation costs. Based on currently available information for estimated site assessment and remediation costs at December 31, 2003 and 2002, PSNH had $9.8 million and $10.8 million, respectively, recorded as environmental reserves. A reconciliation of the total amount reserved at December 31, 2003 and 2002 is as follows:
--------------------------------------------------------------------
(Millions of Dollars) For the Years Ended December 31,
--------------------------------------------------------------------
2003 2002
--------------------------------------------------------------------
Balance at beginning of year $10.8 $11.4
Additions and adjustments 0.8 1.1
Payments (1.8) (1.7)
--------------------------------------------------------------------
Balance at end of year $ 9.8 $10.8
--------------------------------------------------------------------
|
These liabilities are estimated on an undiscounted basis and do not assume that any amounts are recoverable from insurance companies or other third parties. The environmental reserve includes sites at different stages of discovery and remediation and does not include any unasserted claims. At December 31, 2003, there are two sites for which there are unasserted claims; however, any related remediation costs are not probable or estimable at this time. PSNH's environmental liability also takes into account recurring costs of managing hazardous substances and pollutants, mandated expenditures to remediate previously contaminated sites and any other infrequent and non- recurring clean up costs.
PSNH currently has 15 sites included in the environmental reserve. Of those 15 sites, seven sites are in the remediation or long-term monitoring phase, three sites have had site assessments completed and the remaining five sites are in the preliminary stages of site assessment.
In addition, capital expenditures related to environmental matters are expected to total approximately $84 million in aggregate for the years 2004 through 2008. Of the $84 million, $70 million relates to the proposed conversion of a 50 megawatt oil and coal burning unit at Schiller Station to a wood burning unit. The remainder primarily relates to other environmental remediation programs including programs associated with PSNH's hydroelectric generation assets.
MGP Sites: Manufactured gas plant (MGP) sites comprise the largest portion of PSNH's environmental liability. MGPs are sites that manufactured gas from coal and produced certain byproducts that may pose risk to human health and the environment. At December 31, 2003 and 2002, $9.1 million and $8.7 million, respectively, represent amounts for the site assessment and remediation of MGPs. At December 31, 2003 and 2002, the two largest MGP sites comprise approximately 87 percent and 94 percent, respectively, of the total MGP environmental liability. PSNH currently has seven MGP sites included in its environmental liability and one contingent MGP site of which management is aware and for which costs are not probable or estimable at this time. Of the seven MGP sites, three are currently undergoing remediation with the remainder in the site assessment stage.
CERCLA Matters: The Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA) and its' amendments or state equivalents impose joint and several strict liabilities, regardless of fault, upon generators of hazardous substances resulting in removal and remediation costs and environmental damages. Liabilities under these laws can be material and in some instances may be imposed without regard to fault or for past acts that may have been lawful at the time they occurred. PSNH has two superfund sites under CERCLA for which it has been notified that it is a potentially responsible party (PRP). For sites where there are other PRPs and PSNH is not managing the site assessment and remediation, the liability accrued represents PSNH's estimate of what it will need to pay to settle its obligations with respect to the site.
It is possible that new information or future developments could require a reassessment of the potential exposure to related environmental matters. As this information becomes available management will continue to assess the potential exposure and adjust the reserves as necessary.
Rate Recovery: PSNH has a rate recovery mechanism for environmental costs.
C. NUCLEAR INSURANCE CONTINGENCIES In conjunction with the divestiture of Millstone in 2001 and Seabrook in 2002, PSNH terminated its nuclear insurance related to these plants, and PSNH has no further exposure for potential assessments related to Millstone and Seabrook. However, through its continuing association with Nuclear Electric Insurance Limited (NEIL) and CYAPC, NU is subject to potential retrospective assessments totaling $0.8 million under its respective NEIL insurance policies.
D. LONG-TERM CONTRACTUAL ARRANGEMENTS VYNPC: Previously, under the terms of its agreement, PSNH paid its ownership (or entitlement) shares of costs, which included depreciation, O&M expenses, taxes, the estimated cost of decommissioning, and a return on invested capital to VYNPC and recorded these costs as purchased-power expenses. On July 31, 2002, VYNPC consummated the sale of its nuclear generating unit to a subsidiary of Entergy for approximately $180 million. Under the terms of the sale, PSNH will continue to buy approximately 4 percent of the plant's output through March 2012 at a range of fixed prices. The total cost of purchases under contracts with VYNPC amounted to $7.5 million in 2003, $6.9 million in 2002 and $6.5 million in 2001.
Electricity Procurement Obligations: PSNH has entered into various arrangements for the purchase of electricity. The total cost of purchases under these arrangements amounted to $122.8 million in 2003, $121.2 million in 2002, and $144.4 million in 2001. These amounts are for independent power producer contracts and do not include PSNH's short-term power supply management.
Hydro-Quebec: Along with other New England utilities, PSNH has entered into an agreement to support transmission and terminal facilities to import electricity from the Hydro-Quebec system in Canada. PSNH is obligated to pay, over a 30-year period ending in 2020, its proportionate share of the annual O&M expenses and capital costs of those facilities.
Estimated Future Annual Costs: The estimated future annual costs of PSNH's significant long-term contractual arrangements are as follows:
------------------------------------------------------------------------------- (Millions of Dollars) 2004 2005 2006 2007 2008 Thereafter ------------------------------------------------------------------------------- VYNPC $ 7.4 $ 6.8 $ 7.1 $ 6.9 $ 7.0 $ 56.0 Electricity Procurement Contracts 121.3 123.6 124.8 53.6 27.6 240.2 Hydro-Quebec 7.9 7.6 7.1 6.3 6.0 96.0 ------------------------------------------------------------------------------- Totals $136.6 $138.0 $139.0 $66.8 $40.6 $392.2 ------------------------------------------------------------------------------- |
E. NUCLEAR DECOMMISSIONING AND PLANT CLOSURE COSTS In conjunction with the Millstone and VYNPC nuclear generation asset divestitures, the applicable liabilities and nuclear decommissioning trusts were transferred to the purchasers, and the purchasers agreed to assume responsibility for decommissioning their respective units.
PSNH still has significant decommissioning and plant closure cost obligations to the Yankee Companies that own the Yankee Atomic, Connecticut Yankee (CY) and Maine Yankee nuclear power plants. Each plant has been shut down and is undergoing decommissioning. The Yankee Companies collect decommissioning and closure costs through wholesale FERC-approved rates charged under power purchase agreements to PSNH. PSNH in turn passes these costs on to its customers through state regulatory commission-approved retail rates. A portion of the decommissioning and closure costs have already been collected, but a substantial portion related to the decommissioning of CY has not yet been filed at and approved for collection by the FERC.
During 2002, PSNH 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. PSNH's share of this increase is $24.9 million. Following FERC rate cases by the Yankee Companies, PSNH expects to recover the higher decommissioning costs from its retail customers.
In June 2003, CYAPC notified NU that it had terminated its contract with Bechtel Power Corporation (Bechtel) for the decommissioning of the CY nuclear power plant. CYAPC terminated the contract based on its determination that Bechtel's decommissioning work has been incomplete and untimely and that Bechtel refused to perform the remaining decommissioning work. Bechtel has filed a counterclaim against CYAPC asserting a number of claims and seeking a variety of remedies, including monetary and punitive damages and the rescission of the contract. Bechtel has amended its complaint to add claims for wrongful termination.
In November 2003, CYAPC prepared an updated estimate of the cost of decommissioning its nuclear unit. PSNH's aggregate share of the estimated increased cost primarily related to the termination of Bechtel, is $17.1 million.
CYAPC is seeking recovery of additional decommissioning costs and other damages from Bechtel and, if necessary, its surety. In pursuing this recovery through pending litigation, CYAPC is also exploring options to structure an appropriate rate application to be filed with the FERC, with any resulting adjustments being charged to the owners of the nuclear unit, including PSNH. The timing, amount and outcome of these filings cannot be predicted at this time.
PSNH 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 PSNH's customers, 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 FERC does not allow these costs to be recovered in wholesale rates, PSNH would expect the state regulatory commissions to disallow these costs in retail rates as well.
At December 31, 2003 and 2002, PSNH's remaining estimated obligations for decommissioning and closure costs for the shut down units owned by CYAPC, YAEC and MYAPC were $64.2 million and $56.2 million, respectively.
The following methods and assumptions were used to estimate the fair value of each of the following financial instruments:
Long-Term Debt and Rate Reduction Bonds: The fair value of PSNH's fixed-rate securities is based upon the quoted market price for those issues or similar issues. Adjustable rate securities are assumed to have a fair value equal to their carrying value. The carrying amounts of PSNH's financial instruments and the estimated fair values are as follows:
---------------------------------------------------------------------
At December 31, 2003
---------------------------------------------------------------------
(Millions of Dollars) Carrying Amount Fair Value
---------------------------------------------------------------------
Long-term debt -
Other long-term debt $407.3 $425.6
Rate reduction bonds 472.2 517.3
---------------------------------------------------------------------
---------------------------------------------------------------------
At December 31, 2002
---------------------------------------------------------------------
(Millions of Dollars) Carrying Amount Fair Value
---------------------------------------------------------------------
Long-term debt -
Other long-term debt $407.3 $421.6
Rate reduction bonds 510.8 565.4
---------------------------------------------------------------------
|
Other Financial Instruments: The carrying value of financial instruments included in current assets and current liabilities, including investments in securitizable assets, approximates their fair value.
PSNH has entered into lease agreements, some of which are capital leases, for the use of data processing and office equipment, vehicles, and office space. The provisions of these lease agreements generally provide for renewal options.
Capital lease rental payments charged to operating expense were $0.5 million in 2003, $0.4 million in 2002, and $0.7 million in 2001. Interest included in capital lease rental payments was $0.3 million in 2003, 2002, and 2001. Operating lease rental payments charged to expense were $1.8 million in 2003, $2.6 million in 2002, and $3.9 million in 2001.
Future minimum rental payments excluding executory costs, such as property taxes, state use taxes, insurance, and maintenance, under long-term noncancelable leases, at December 31, 2003 are as follows:
--------------------------------------------------------------------- (Millions of Dollars) Capital Operating Year Leases Leases --------------------------------------------------------------------- 2004 $0.5 $ 4.6 2005 0.5 3.9 2006 0.3 3.6 2007 0.2 2.6 2008 0.2 2.1 Thereafter - 3.6 --------------------------------------------------------------------- Future minimum lease payments $1.7 $20.4 Less amount representing interest 0.7 --------------------------------------------------------------------- Present value of future minimum lease payments $1.0 --------------------------------------------------------------------- |
The accumulated balance for each other comprehensive income/(loss) item is as follows:
-----------------------------------------------------------------------
Current
December 31, Period December 31,
(Millions of Dollars) 2002 Change 2003
-----------------------------------------------------------------------
Unrealized
gains/(losses)
on securities $ - $ 0.1 $ 0.1
Minimum supplemental
executive retirement
pension liability
adjustments (0.1) (0.1) (0.2)
-----------------------------------------------------------------------
Accumulated other
comprehensive
loss $(0.1) $ - $(0.1)
-----------------------------------------------------------------------
-----------------------------------------------------------------------
Current
December 31, Period December 31,
(Millions of Dollars) 2001 Change 2002
-----------------------------------------------------------------------
Unrealized
gains/(losses)
on securities $ 0.6 $(0.6) $ -
Minimum supplemental
executive retirement
pension liability
adjustments (0.2) 0.1 (0.1)
-----------------------------------------------------------------------
Accumulated other
comprehensive
income/(loss) $ 0.4 $(0.5) $(0.1)
-----------------------------------------------------------------------
|
The changes in the components of other comprehensive income/(loss) are reported net of the following income tax effects:
----------------------------------------------------------------------- (Millions of Dollars) 2003 2002 2001 ----------------------------------------------------------------------- Unrealized (losses)/gains on securities $(0.1) $0.3 $0.4 Minimum supplemental executive retirement pension liability adjustments - - - ----------------------------------------------------------------------- Accumulated other comprehensive (loss)/income $(0.1) $0.3 $0.4 ----------------------------------------------------------------------- |
Details of long-term debt outstanding are as follows:
-----------------------------------------------------------------------
At December 31, 2003 2002
-----------------------------------------------------------------------
(Millions of Dollars)
Pollution Control Revenue Bonds:
6.00% Tax-Exempt, Series D, due 2021 $ 75.0 $ 75.0
6.00% Tax-Exempt, Series E, due 2021 44.8 44.8
Adjustable Rate, Series A, due 2021 89.3 89.3
Adjustable Rate, Series B, due 2021 89.3 89.3
5.45% Tax-Exempt, Series C, due 2021 108.9 108.9
-----------------------------------------------------------------------
Long-term debt $407.3 $407.3
-----------------------------------------------------------------------
|
There are no cash sinking fund requirements or debt maturities for the years 2004 through 2008. There are annual renewal and replacement fund requirements equal to 2.25 percent of the average of net depreciable utility property owned by PSNH in 1992, plus cumulative gross property additions thereafter. PSNH expects to meet these future fund requirements by certifying property additions. Any deficiency would need to be satisfied by the deposit of cash or bonds.
Essentially, all utility plant of PSNH is subject to the liens of the company's first mortgage bond indenture.
PSNH entered into financing arrangements with the Business Finance Authority (BFA) of the state of New Hampshire, pursuant to which, the BFA issued five series of Pollution Control Revenue Bonds (PCRBs) as described above and loaned the proceeds to PSNH. PSNH's obligation to repay each series of PCRBs is secured by bond insurance and first mortgage bonds. Each such series of first mortgage bonds contains similar terms and provisions as the applicable series of PCRBs. For financial reporting purposes, these first mortgage bonds would not be considered outstanding unless PSNH failed to meet its obligations under the PCRBs.
The average effective interest rate on the variable-rate pollution control notes was 1 percent in 2003 and 1.4 percent in 2002.
The components of the federal and state income tax provisions were charged/(credited) to operations as follows:
---------------------------------------------------------------------
For the Years
Ended December 31, 2003 2002 2001
---------------------------------------------------------------------
(Millions of Dollars)
Current income taxes:
Federal $27.9 $101.1 $(143.5)
State 8.5 19.0 (13.4)
---------------------------------------------------------------------
Total current 36.4 120.1 (156.9)
---------------------------------------------------------------------
Deferred income taxes, net:
Federal (3.8) (65.0) 197.3
State (2.3) (5.5) 13.5
---------------------------------------------------------------------
Total deferred (6.1) (70.5) 210.8
---------------------------------------------------------------------
Investment tax credits, net (0.5) (9.3) (15.3)
---------------------------------------------------------------------
Total income tax expense $29.8 $ 40.3 $ 38.6
---------------------------------------------------------------------
|
Deferred income taxes are comprised of the tax effects of temporary differences as follows:
---------------------------------------------------------------------
For the Years
Ended December 31, 2003 2002 2001
---------------------------------------------------------------------
(Millions of Dollars)
Depreciation $12.2 $ 7.7 $ 1.9
Net regulatory deferral (8.2) (65.3) (5.4)
Regulatory disallowance - - 2.3
Contractual settlements - - 6.7
Contract termination costs,
net of amortization (9.7) (13.5) 196.6
Other (0.4) 0.6 8.7
---------------------------------------------------------------------
Deferred income taxes, net $(6.1) $(70.5) $210.8
---------------------------------------------------------------------
|
A reconciliation between income tax expense and the expected tax expense at the statutory rate is as follows:
---------------------------------------------------------------------
For the Years
Ended December 31, 2003 2002 2001
---------------------------------------------------------------------
(Millions of Dollars)
Expected federal income tax $26.3 $36.1 $42.1
Tax effect of differences:
Depreciation 1.1 1.9 0.5
Amortization of
regulatory assets 1.8 1.2 5.1
Investment tax credit
amortization (0.5) (9.3) (15.3)
State income taxes,
net of federal benefit 4.1 8.8 0.1
Other, net (3.0) 1.6 6.1
---------------------------------------------------------------------
Total income tax expense $29.8 $40.3 $38.6
---------------------------------------------------------------------
|
NU is organized between the Utility Group and NU Enterprises based on each segments' regulatory environment or lack thereof. PSNH is included in the utility group segment of NU and has no other reportable segments.
------------------------------------------------------------------------------- 2003 March 31, June 30, September 30, December 31, ------------------------------------------------------------------------------- Operating Revenues $230,768 $203,364 $235,972 $218,082 Operating Income $ 31,383 $ 29,668 $ 34,774 $ 29,791 Net Income $ 10,827 $ 11,054 $ 12,613 $ 11,130 ------------------------------------------------------------------------------- 2002 ------------------------------------------------------------------------------- Operating Revenues $228,028 $230,382 $272,189 $216,579 Operating Income $ 30,750 $ 37,004 $ 40,929 $ 45,289 Net Income $ 11,729 $ 15,231 $ 19,482 $ 16,455 ------------------------------------------------------------------------------- |
---------------------------------------------------------------------------------------------------------------------------- Selected Consolidated Financial Data (Unaudited) ---------------------------------------------------------------------------------------------------------------------------- (Thousands of Dollars) 2003 2002 2001 2000 1999 ---------------------------------------------------------------------------------------------------------------------------- Operating Revenues (b) $ 888,186 $ 947,178 $ 964,415 $1,291,280 $1,160,572 Net Income/(Loss) 45,624 62,897 81,776 (146,666) 84,209 Cash Dividends on Common Stock 16,800 45,000 27,000 50,000 - Gross Property, Plant and Equipment (c) 1,560,621 1,488,516 1,499,137 1,535,343 2,283,187 Total Assets (d) 2,171,811 2,155,447 2,094,514 2,082,296 2,622,433 Rate Reduction Bonds 472,222 510,841 507,381 - - Long-Term Debt (e) 407,285 407,285 407,285 407,285 516,485 Preferred Stock Not Subject to Mandatory Redemption - - - 24,268 50,000 Obligations Under Seabrook Power Contracts and Other Capital Leases (e) 986 1,192 110,275 629,230 726,153 ---------------------------------------------------------------------------------------------------------------------------- |
(a) Certain reclassifications of prior years' data have been made to conform with the current year's presentation. Operating revenue amounts have been reclassified from those reported in 2002 and from those reported in the first three quarters of 2003 on the reports on Form 10-Q because of the adoption of EITF Issue No. 03-11. Quarterly operating revenues as previously reported for 2003 and 2002 are as follows (thousands of dollars):
-------------------------------------------------
Operating Revenues
-------------------------------------------------
Quarter Ended 2003 2002
-------------------------------------------------
March 31 $256,895 $242,381
June 30 220,264 248,914
September 30 241,829 324,818
December 31 N/A 230,625
-------------------------------------------------
|
(b) Operating revenue amounts have been reclassified from those reported in
2002 and 2001 related to the adoption of EITF Issue No. 03-11.
(c) Amount includes construction work in progress.
(d) Total assets were not adjusted for cost of removal prior to 2002.
(e) Includes portions due within one year.
-----------------------------------------------------------------------------------------------------------------------------
Consolidated Statistics (Unaudited)
-----------------------------------------------------------------------------------------------------------------------------
2003 2002 2001 2000 1999
-----------------------------------------------------------------------------------------------------------------------------
Revenues: (Thousands)
Residential $351,622 $325,912 $323,642 $ 355,176 $ 356,970
Commercial 318,081 297,196 297,632 306,386 302,135
Industrial 159,560 150,582 175,575 195,058 188,622
Other Utilities 38,622 152,131 144,350 394,080 266,118
Streetlighting and Railroads 4,801 4,820 5,227 5,925 5,927
Non-franchised Sales - - - - 18,963
Miscellaneous 15,500 16,537 17,989 34,655 21,837
-----------------------------------------------------------------------------------------------------------------------------
Total $888,186 $947,178 $964,415 $1,291,280 $1,160,572
-----------------------------------------------------------------------------------------------------------------------------
Sales: (kWh - Millions)
Residential 2,944 2,765 2,592 2,474 2,447
Commercial 3,100 2,969 2,873 2,614 2,536
Industrial 1,684 1,646 1,926 2,026 1,952
Other Utilities 674 4,034 4,086 10,007 5,869
Streetlighting and Railroads 23 23 23 22 22
Non-franchised Sales - - - - 6
-----------------------------------------------------------------------------------------------------------------------------
Total 8,425 11,437 11,500 17,143 12,832
-----------------------------------------------------------------------------------------------------------------------------
Customers: (Average)
Residential 388,133 382,481 376,832 372,286 367,119
Commercial 63,324 61,775 59,538 58,279 57,203
Industrial 2,758 2,818 2,863 2,887 2,896
Other 554 540 517 485 476
-----------------------------------------------------------------------------------------------------------------------------
Total 454,769 447,614 439,750 433,937 427,694
-----------------------------------------------------------------------------------------------------------------------------
Average Annual Use Per
Residential Customer (kWh) 7,584 7,208 6,868 6,644 6,665
-----------------------------------------------------------------------------------------------------------------------------
Average Annual Bill Per
Residential Customer $906.29 $849.10 $859.87 $954.08 $972.42
-----------------------------------------------------------------------------------------------------------------------------
Average Revenue Per kWh:
Residential 11.95 cents 11.78 cents 12.52 cents 14.36 cents 14.59 cents
Commercial 10.26 10.01 10.36 11.72 11.91
Industrial 9.48 9.15 9.12 9.63 9.66
-----------------------------------------------------------------------------------------------------------------------------
Employees 1,282 1,243 1,241 1,227 1,258
=============================================================================================================================
|
EXHIBIT 13.4
2003 Annual Report
Western Massachusetts Electric Company and Subsidiary
Index
Contents Page -------- ---- Management's Discussion and Analysis of Financial Condition and Results of Operations............................ 1 Independent Auditors' Report and Report of Independent Public Accountants............................................. 12 Consolidated Balance Sheets...................................... 14-15 Consolidated Statements of Income................................ 16 Consolidated Statements of Comprehensive Income.................. 16 Consolidated Statements of Common Stockholder's Equity........... 17 Consolidated Statements of Cash Flows............................ 18 Notes to Consolidated Financial Statements....................... 19 Consolidated Quarterly Financial Data (Unaudited)................ 32 Selected Consolidated Financial Data (Unaudited)................. 32 Consolidated Statistics (Unaudited).............................. 32 Bondholder Information........................................... Back Cover |
MANAGEMENT'S DISCUSSION AND ANALYSIS
OVERVIEW
Western Massachusetts Electric Company (WMECO or the company), a wholly owned
subsidiary of Northeast Utilities (NU), earned $16.2 million in 2003 compared
to $37.7 million in 2002 and $15 million in 2001. The 2003 decline in
earnings related primarily to the recognition of $13 million of investment
tax credits in the second quarter of 2002 and to the positive financial
impact of an approval of a regulatory settlement in the fourth quarter of
2002.
NU's other subsidiaries include The Connecticut Light and Power Company (CL&P), Public Service Company of New Hampshire (PSNH), Yankee Energy System, Inc., North Atlantic Energy Corporation, Select Energy, Inc., Northeast Generation Company, Northeast Generation Services Company, and Select Energy Services, Inc.
During 2003, pre-tax pension income for WMECO declined $4.2 million, from a credit of $12.1 million in 2002 to a credit of $7.9 million in 2003. Of the $7.9 million and $12.1 million of pension credits recorded during 2003 and 2002, $4.8 million and $7.9 million, respectively, were recognized in the consolidated statements of income as reductions to operating expenses. The remaining $3.1 million in 2003 and $4.2 million in 2002 relate to employees working on capital projects and were reflected as reductions to capital expenditures. The pre-tax $3.1 million decrease in pension income that reduces operating expenses was reflected evenly throughout 2003, resulting in a decline of $0.5 million in net income per quarter during 2003.
WMECO's revenues for 2003 increased to $391.2 million from $369.5 million in 2002 due to increases in electric sales volumes and rates in 2003 as compared to 2002.
Partially as a result of an adjustment to estimated unbilled revenues resulting from a process to validate and update the assumptions used to estimate unbilled revenues, 2003 WMECO retail sales increased 2.6 percent compared to 2002. Absent that adjustment, WMECO retail sales increased 2 percent. The adjustment to WMECO's estimated unbilled revenues increased WMECO's net income by $0.3 million for 2003. For further information regarding the estimate of unbilled revenues, see "Critical Accounting Policies and Estimates - Unbilled Revenues," included in this Management's Discussion and Analysis.
FUTURE OUTLOOK
In 2004, WMECO is projecting to record pre-tax pension income of $4.2 million
as compared to pension income of $7.9 million in 2003. Pension income is
annually adjusted during the second quarter based on updated actuarial
valuations, and the 2004 estimate may change.
WMECO's 2004 earnings will also be impacted by the transmission rate case before the Federal Energy Regulatory Commission (FERC). Management expects this case to be decided in the second half of 2004.
LIQUIDITY
After four years of reducing its indebtedness, WMECO's total debt, excluding
rate reduction bonds, rose to $198.6 million at the end of 2003, compared
with $194.9 million at the end of 2002. At December 31, 2003, WMECO had $10
million in notes payable to banks, compared with $7 million of notes payable
to banks at December 31, 2002.
WMECO's net cash flows provided by operating activities totaled $57.2 million in 2003 as compared to $27.6 million in 2002 and $57.2 million in 2001. Cash flows provided by operating activities in 2003 increased due to an increase in prepaid pension, increase in amortization of regulatory assets and changes in working capital items, primarily receivables and unbilled revenues and accounts payable. Receivables and unbilled revenues and accounts payable changed due to the timing of receipts received on amounts due and payments on amounts outstanding. Amortization of regulatory assets increased due to the higher recovery of stranded costs. These increases were offset by a $21.5 million decrease in net income.
Cash flows provided by operating activities in 2002 decreased due to changes in working capital items, primarily receivables and unbilled revenues and accounts payable, partially offset by the increase in net income in 2002.
There was a comparable level of investing and financing activity in 2003 as compared to 2002, which included the sale of $55 million of 10-year senior unsecured notes by WMECO on September 30, 2003, at a coupon rate of 5.0 percent. WMECO used the proceeds from this debt issue to reduce its level of short-term borrowings from the NU Money Pool. Cash flows used for investments in plant totaled $30.4 million in 2003, $23.1 million in 2002 and $30.7 million in 2001. WMECO expects capital expenditures to reach $38 million in 2004. The level of common dividends was consistent and totaled $22 million in 2003, $16 million in 2002 and $22 million in 2001.
There was a lower level of investing and financing activities in 2002 as compared to 2001, primarily due to the retirement of long-term debt, issuance of rate reduction bonds and buyout of independent power producer contracts in 2001.
Aside from the rate reduction bonds outstanding, no WMECO debt issues mature during the eight-year period of 2004 through 2011.
In November 2003, WMECO renewed a $300 million credit line under terms similar to the previous arrangement that expired in November 2003. WMECO can borrow up to $100 million and had $10 million in borrowings outstanding on this credit line at December 31, 2003.
Rate reduction bonds are included on the consolidated balance sheets of WMECO, even though the debt is non-recourse to WMECO. At December 31, 2003, WMECO had a total of $133 million in rate reduction bonds outstanding, compared with $142.7 million outstanding at December 31, 2002. All outstanding rate reduction bonds of WMECO are scheduled to fully amortize by June 1, 2013. Interest on the bonds totaled $9 million in 2003, compared with $9.6 million in 2002 and $6.3 million in 2001, the year of issuance. Cash flows from the amortization of rate reduction bonds totaled $9.8 million in 2003, compared with $9.4 million in 2002 and $3.6 million in 2001. Over the next several years, retirement of rate reduction bonds will increase, and interest payments will steadily decrease, resulting in no material changes to debt service costs on the existing issues. WMECO fully recovers the amortization and interest payments from customers through stranded cost revenues each year, and the bonds have no impact on net income. Moreover, as the rate reduction bonds are non-recourse, the three rating agencies that rate the debt of WMECO do not reflect the revenues, expenses, or outstanding securities related to the rate reduction bonds in establishing the credit ratings of WMECO.
The retirement of rate reduction bonds does not equal the amortization of rate reduction bonds because the retirement represents principal payments, while the amortization represents amounts recovered from customers for future principal payments. The timing of recovery does not exactly match the expected principal payments.
BUSINESS DEVELOPMENT AND CAPITAL EXPENDITURES
WMECO's capital expenditures totaled $30.4 million in 2003, compared with
$23.1 million in 2002 and $30.7 million in 2001. WMECO's capital
expenditures are expected to total $38 million in 2004.
REGIONAL TRANSMISSION ORGANIZATION
The FERC has required all transmission owning utilities, including WMECO, to
voluntarily form regional transmission organizations (RTOs) or to state why
this process has not begun.
On October 31, 2003, New England Independent System Operator (ISO-NE), along with NU (including WMECO), and six other New England transmission companies filed a proposal with the FERC to create a RTO for New England. The RTO is intended to strengthen the independent and efficient management of the region's power system while ensuring that customers in New England continue to have the most reliable system possible to realize the benefits of a competitive wholesale energy market.
ISO-NE, as a RTO, will have a new independent governance structure and will also become the transmission provider for New England by exercising operational control over New England's transmission facilities pursuant to a detailed contractual arrangement with the New England transmission owners. Under this contractual arrangement, the RTO will have clear authority to direct the transmission owners to operate their facilities in a manner that preserves system reliability, including requiring transmission owners to expand existing transmission lines or build new ones when needed for reliability. Transmission owners will retain their rights over revenue requirements, rates and rate designs. The filing requests that the FERC approve the RTO arrangements for an effective date of March 1, 2004.
In a separate filing made on November 4, 2003, NU including WMECO, along with six other New England transmission owners requested, consistent with the FERC's pricing policy for RTOs and Order-2000-compliant independent system operators, that the FERC approve a single return on equity (ROE) for regional and local rates that would consist of a base ROE as well as incentive adders of 50 basis points for joining a RTO and 100 basis points for constructing new transmission facilities approved by the RTO. If the FERC approves the request, then the transmission owners would receive a 13.3 percent ROE for existing transmission facilities and a 14.3 percent ROE for new transmission facilities. The outcome of this request and its impact on WMECO cannot be determined at this time.
RESTRUCTURING AND RATE MATTERS
On August 26, 2003, NU's electric operating companies, including WMECO, filed
their first transmission rate case at the FERC since 1995. In the filing, NU
requested implementation of a formula rate that would allow recovery of
increasing transmission expenditures on a timelier basis and that the
changes, including a $23.7 million annual rate increase through 2004, take
effect on October 27, 2003. NU requested that the FERC maintain NU's
existing 11.75 percent ROE until a ROE for the New England RTO is
established by the FERC. On October 22, 2003, the FERC accepted this filing
implementing the proposed rates subject to refund effective on October 28,
2003. A final decision in the rate case is expected in 2004.
Increasing transmission rates are generally recovered from distribution companies through FERC-approved transmission rates. Electric distribution companies pass through higher transmission rates to retail customers as approved by the Massachusetts Department of Telecommunications and Energy (DTE). Currently, WMECO has a tracking mechanism to reset rates annually for transmission costs with overcollections refunded to customers and undercollections deferred and then collected from customers in later years.
Transition Cost Reconciliations: On March 31, 2003, WMECO filed its 2002 transition cost reconciliation with the DTE. This filing reconciled the recovery of generation-related stranded costs for calendar year 2002 and included the renegotiated purchased power contract related to the Vermont Yankee nuclear unit.
On July 15, 2003, the DTE issued a final order on WMECO's 2001 transition cost reconciliation, which addressed WMECO's cost tracking mechanisms. As part of that order, the DTE directed WMECO to revise its 2002 annual transition cost reconciliation filing. The revised filing was submitted to the DTE on September 22, 2003. Hearings have been held, and the timing of a final decision from the DTE is uncertain. Management does not expect the outcome of this docket to have a material adverse impact on WMECO's net income or financial position.
Standard Offer and Default Service: In December 2003, the DTE approved WMECO's standard offer service rate of $0.05607 per kWh for the period of January 1, 2004 through February 28, 2005. The DTE also approved a default service rate of $0.05829 for the period of January 1, 2004 through June 30, 2004 for residential customers and a rate of $0.0616 for the period January 1, 2004 through March 31, 2004 for commercial and industrial customers.
For information regarding commitments and contingencies related to restructuring and rate matters, see Note 6A, "Commitments and Contingencies - Restructuring and Rate Matters," to the consolidated financial statements.
NUCLEAR GENERATION ASSET DIVESTITURES
Millstone: On March 31, 2001, WMECO sold its ownership interest in the
Millstone nuclear units (Millstone).
Vermont Yankee: On July 31, 2002, Vermont Yankee Nuclear Power Corporation (VYNPC) consummated the sale of its nuclear generating unit. In November 2003, WMECO sold back to VYNPC its shares of stock for approximately $0.2 million. WMECO continues to purchase approximately 2.5 percent of the plant's output under a new contract.
Nuclear Decommissioning and Plant Closure Costs: Although the purchasers of WMECO's ownership shares of the Millstone and Vermont Yankee plants assumed the obligation of decommissioning those plants, WMECO still has significant decommissioning and plant closure cost obligations to the companies that own the Yankee Atomic, Connecticut Yankee (CY) and Maine Yankee plants (collectively Yankee Companies). Each plant has been shut down and is undergoing decommissioning. The Yankee Companies collect decommissioning and closure costs through wholesale FERC-approved rates charged under a power purchase agreement with WMECO. WMECO in turn passes these costs on to its customers through state regulatory commission-approved retail rates. A portion of the decommissioning and closure costs have already been collected, but a substantial portion related to the decommissioning of CY has not yet been filed at and approved for collection by the FERC. The cost estimate for CY that has not yet been approved for recovery by FERC at December 31, 2003 is $50.1 million.
WMECO cannot at this time predict the timing or outcome of the FERC proceeding required for the collection of these remaining decommissioning and closure costs or the Bechtel Power Corporation litigation referred to in Note 6F, "Commitments and Contingencies - Nuclear Decommissioning and Plant Closure Costs," to the consolidated financial statements. Although management believes that these costs will ultimately be recovered from WMECO's customers, 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 FERC does not allow these costs to be recovered in wholesale rates, WMECO would expect the state regulatory commissions to disallow these costs in retail rates as well.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States of America requires
management to make estimates, assumptions and at times difficult, subjective
or complex judgments. Changes in these estimates, assumptions and judgments,
in and of themselves, could materially impact the financial statements of
WMECO. Management communicates to and discusses with NU's Audit Committee
of the Board of Trustees all critical accounting policies and estimates. The
following are the accounting policies and estimates that management believes
are the most critical in nature.
Presentation: In accordance with current accounting pronouncements, WMECO's consolidated financial statements include all subsidiaries upon which control is maintained and all variable interest entities for which WMECO is the primary beneficiary, as defined. All intercompany transactions between these subsidiaries are eliminated as part of the consolidation process.
WMECO has less than 50 percent ownership interests in the Connecticut Yankee Atomic Power Company, Yankee Atomic Electric Company and Maine Yankee Atomic Power Company. WMECO does not control these companies and does not consolidate them in its financial statements. WMECO accounts for the investments in these companies using the equity method. Under the equity method, WMECO records its ownership share of the earnings or losses at these companies. Determining whether or not WMECO should apply the equity method of accounting for an investee company requires management judgment.
The required adoption date of Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 46, "Consolidation of Variable Interest Entities" was delayed from July 1, 2003 to December 31, 2003 for WMECO. However, WMECO elected to adopt FIN 46 at the original adoption date. The adoption of FIN 46 had no impact on WMECO. In December 2003, the FASB issued a revised version of FIN 46 (FIN 46R). FIN 46R is effective for WMECO for the first quarter of 2004, but is not expected to have an impact on WMECO's consolidated financial statements.
Revenue Recognition: WMECO retail revenues are based on rates approved by the DTE. These regulated rates are applied to customers' use of energy to calculate a bill. In general, rates can only be changed through formal proceedings with the DTE. WMECO utilizes regulatory commission-approved tracking mechanisms to track the recovery of certain incurred costs. The tracking mechanisms allow for rates to be changed periodically, with overcollections refunded to customers or underrecollections collected from customers in future periods.
The determination of the energy sales to individual customers is based on the reading of meters, which occurs on a systematic basis throughout the month. Billed revenues are based on these meter readings. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated, and an estimated amount of unbilled revenues is recorded.
Wholesale transmission revenues are based on rates and formulas that are approved by the FERC. Most of WMECO's wholesale transmission revenues are collected through a combination of the New England Regional Network Service (RNS) tariff and WMECO's Local Network Service (LNS) tariff. The RNS tariff, which is administered by ISO-NE, recovers the revenue requirements associated with transmission facilities that are deemed by the FERC to be Pool Transmission Facilities. The LNS tariff which was accepted by the FERC on October 22, 2003, provides for the recovery of WMECO's total transmission revenue requirements, net of revenue credits received from various rate components, including revenues received under the RNS rates.
Unbilled Revenues: Unbilled revenues represent an estimate of electricity delivered to customers that has not been billed. Unbilled revenues represent assets on the balance sheet that become accounts receivable in the following month as customers are billed.
The estimate of unbilled revenues is sensitive to numerous factors that can significantly impact the amount of revenues recorded. Estimating the impact of these factors is complex and requires management's judgment. The estimate of unbilled revenues is important to WMECO's consolidated financial statements as adjustments to that estimate could significantly impact operating revenues and earnings. Two potential methods for estimating unbilled revenues are the requirements and the cycle method.
WMECO estimates unbilled revenues monthly using the requirements method. The requirements method utilizes the total monthly volume of electricity delivered to the system and applies a delivery efficiency (DE) factor to reduce the total monthly volume by an estimate of delivery losses in order to calculate total estimated monthly sales to customers. The total estimated monthly sales amount less total monthly billed sales amount results in a monthly estimate of unbilled sales. Unbilled revenues are estimated by applying an average rate to the estimate of unbilled sales.
Differences between the actual DE factor and the estimated DE factor can have a significant impact on estimated unbilled revenue amounts.
In 2003, the unbilled sales estimates for WMECO were tested using the cycle method. The cycle method uses the billed sales from each meter reading cycle and an estimate of unbilled days in each month based on the meter reading schedule. The cycle method is historically more accurate than the requirements method when used in a mostly weather-neutral month. The cycle method resulted in adjustments to the estimate of unbilled revenues that had a positive after-tax earnings impact on WMECO of $0.3 million in 2003.
The testing of the requirements method with the cycle method will be done on at least an annual basis using a weather-neutral month.
Derivative Accounting: Effective January 1, 2001, WMECO adopted Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended.
Many WMECO contracts for the purchase or sale of energy or energy-related products are derivatives. The application of derivative accounting under SFAS No. 133, as amended, is complex and requires management judgment in the following respects: identification of derivatives and embedded derivatives, election, and designation of the normal purchases and sales exception, and determining the fair value of derivatives. All of these judgments, depending upon their timing and effect, could have a significant impact on WMECO's consolidated balance sheets.
In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities," which amended existing derivative accounting guidance. This new statement incorporates interpretations that were included in previous Derivative Implementation Group guidance, clarifies certain conditions, and amends other existing pronouncements. It was effective for contracts entered into or modified after June 30, 2003. Management has determined that the adoption of SFAS No. 149 had no impact on the accounting for WMECO contracts.
Regulatory Accounting: The accounting policies of WMECO historically reflect the effects of the rate-making process in accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation." The transmission and distribution businesses of WMECO continue to be cost-of- service rate regulated, and management believes the application of SFAS No. 71 to that portion of those businesses continues to be appropriate. Management must reaffirm this conclusion at each balance sheet date. If, as a result of a change in circumstances, it is determined that any portion of WMECO no longer meets the criteria of regulatory accounting under SFAS No. 71, that portion of the company will have to discontinue regulatory accounting and write-off their regulatory assets and liabilities. Such a write-off could have a material impact on WMECO's consolidated financial statements.
The application of SFAS No. 71 results in recording regulatory assets and liabilities. Regulatory assets represent the deferral of incurred costs that are probable of future recovery in customer rates. In some cases, WMECO records regulatory assets before approval for recovery has been received from the DTE. Management must use judgment to conclude that costs deferred as regulatory assets are probable of future recovery. Management bases its conclusion on certain factors, including changes in the regulatory environment, recent rate orders issued by the DTE and the status of any potential new legislation. Regulatory liabilities represent revenues received from customers to fund expected costs that have not yet been incurred or probable future refunds to customers. Management uses its best judgment when recording regulatory assets and liabilities; however, the DTE can reach different conclusions about the recovery of costs, and those conclusions could have a material impact on WMECO's consolidated financial statements. Management believes it is probable that WMECO will recover the regulatory assets that have been recorded.
Pension and Postretirement Benefits Other Than Pensions (PBOP): WMECO participates in a uniform noncontributory defined benefit retirement plan (Pension Plan) covering substantially all regular WMECO employees. WMECO also participates in a postretirement benefit plan (PBOP Plan) to provide certain health care benefits, primarily medical and dental, and life insurance benefits through a benefit plan to retired employees. For each of these plans, the development of the benefit obligation, fair value of plan assets, funded status and net periodic benefit credit or cost is based on several significant assumptions. If these assumptions were changed, the resulting change in benefit obligations, fair values of plan assets, funded status and net periodic benefit credits or costs could have a material impact on WMECO's consolidated financial statements.
Results: Pre-tax periodic pension income for the Pension Plan, excluding settlements, curtailments and special termination benefits, totaled $7.9 million, $12.1 million and $13.7 million for the years ended December 31, 2003, 2002 and 2001, respectively. The pension income amounts exclude one- time items recorded under SFAS No. 88, "Employers' Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits," associated with early termination programs and the sale of Millstone. Net SFAS No. 88 items totaled $1.2 million in income for the year ended December 31, 2002. This amount was recorded as a liability for refund to customers.
The pre-tax net PBOP Plan cost, excluding settlements, curtailments and special termination benefits, totaled $3.5 million, $3.4 million and $2.5 million for the years ended December 31, 2003, 2002 and 2001, respectively.
Long-Term Rate of Return Assumptions: In developing the expected long-term rate of return assumptions, WMECO evaluated input from actuaries, consultants and economists, as well as long-term inflation assumptions and WMECO's historical 20-year compounded return of approximately 11 percent. WMECO's expected long-term rate of return on assets is based on certain target asset allocation assumptions and expected long-term rates of return. The Pension Plan's and PBOP Plan's target asset allocation assumptions and expected long- term rates of return assumptions by asset category are as follows:
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At December 31,
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Pension Benefits Postretirement Benefits
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2003 2002 2003 2002
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Target Assumed Target Assumed Target Assumed Target Assumed
Asset Rate of Asset Rate of Asset Rate of Asset Rate of
Asset Category Allocation Return Allocation Return Allocation Return Allocation Return
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Equity securities:
United States 45.00% 9.25% 45.00% 9.75% 55.00% 9.25% 55.00% 9.75%
Non-United States 14.00% 9.25% 14.00% 9.75% 11.00% 9.25% - -
Emerging markets 3.00% 10.25% 3.00% 10.75% 2.00% 10.25% - -
Private 8.00% 14.25% 8.00% 14.75% - - - -
Debt Securities:
Fixed income 20.00% 5.50% 20.00% 6.25% 27.00% 5.50% 45.00% 6.25%
High yield fixed
income 5.00% 7.50% 5.00% 7.50% 5.00% 7.50% - -
Real estate 5.00% 7.50% 5.00% 7.50% - - - -
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The actual asset allocations at December 31, 2003 and 2002 approximated these target asset allocations. WMECO regularly reviews the actual asset allocations and periodically rebalances the investments to the targeted asset allocations when appropriate. For information regarding actual asset allocations, see Note 4, "Pension Benefits and Postretirement Benefits Other Than Pensions," to the consolidated financial statements.
WMECO reduced the long-term rate of return assumption 50 basis points from 9.25 percent to 8.75 percent in 2003 for the Pension Plan and PBOP Plan due to lower expected market returns. WMECO believes that 8.75 percent is a reasonable long-term rate of return on Pension Plan and PBOP Plan assets for 2003, and WMECO expects to use 8.75 percent in 2004. WMECO will continue to evaluate the actuarial assumptions, including the expected rate of return, at least annually, and will adjust the appropriate assumptions as necessary.
Actuarial Determination of Income and Expense: WMECO bases the actuarial determination of Pension Plan and PBOP Plan income/expense on a market- related valuation of assets, which reduces year-to-year volatility. This market-related valuation calculation recognizes investment gains or losses over a four-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the fair value of assets. Since the market-related valuation calculation recognizes gains or losses over a four-year period, the future value of the market-related assets will be impacted as previously deferred gains or losses are recognized. There will be no impact on the fair value of Pension Plan and PBOP Plan assets.
At December 31, 2003, the Pension Plan had cumulative unrecognized investment losses of $10.6 million, which will increase pension expense over the next four years by reducing the expected return on Pension Plan assets. At December 31, 2003, the Pension Plan also had cumulative unrecognized actuarial losses of $7.8 million, which will increase pension expense over the expected future working lifetime of active Pension Plan participants, or approximately 13 years. The combined total of unrecognized investment and actuarial losses at December 31, 2003 is $18.4 million. These losses impact the determination of pension expense and the actuarially determined prepaid pension amount recorded on the consolidated balance sheets but have no impact on expected Pension Plan funding.
At December 31, 2003, the PBOP Plan had cumulative unrecognized investment losses of $1 million, which will increase PBOP Plan cost over the next four years by reducing the expected return on plan assets. At December 31, 2003, the PBOP Plan also had cumulative unrecognized actuarial losses of $5.1 million, which will increase PBOP Plan expense over the expected future working lifetime of active PBOP Plan participants, or approximately 13 years. The combined total of unrecognized investment and actuarial losses at December 31, 2003 is $6.1 million. These losses impact the determination of PBOP Plan cost and the actuarially determined accrued PBOP Plan cost recorded on the consolidated balance sheets.
Discount Rate: The discount rate that is utilized in determining future pension and PBOP obligations is based on a basket of long-term bonds that receive one of the two highest ratings given by a recognized rating agency. To compensate for the Pension Plan's longer duration 25 basis points were added to the benchmark. The discount rate determined on this basis has decreased from 6.75 percent at December 31, 2002 to 6.25 percent at December 31, 2003.
Expected Pension Income: Due to the effect of the unrecognized actuarial losses and based on an expected rate of return on Pension Plan assets of 8.75 percent, a discount rate of 6.25 percent and various other assumptions, WMECO estimates that expected contributions to and pension income for the Pension Plan will be as follows (in millions):
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Expected
Year Contributions Pension Income
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2004 $ - $4.2
2005 $ - $1.9
2006 $ - $1.0
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Future actual pension income/expense will depend on future investment performance, changes in future discount rates and various other factors related to the populations participating in the Pension Plan.
Sensitivity Analysis: The following represents the increase/(decrease) to the Pension Plan's reported cost and to the PBOP Plan's reported cost as a result of the change in the following assumptions by 50 basis points (in millions):
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At December 31,
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Pension Plan Postretirement Plan
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Assumption Change 2003 2002 2003 2002
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Lower long-term
rate of return $ 1.1 $ 1.1 $ 0.1 $ 0.1
Lower discount
rate $ 0.9 $ 0.8 $ 0.1 $ 0.1
Lower compensation
increase $(0.4) $(0.3) N/A N/A
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Plan Assets: The value of the Pension Plan assets has increased from $162.4 million at December 31, 2002 to $195.3 million at December 31, 2003. The investment performance returns, despite declining discount rates, have increased the overfunded status of the Pension Plan on a projected benefit obligation (PBO) basis from $28.8 million at December 31, 2002 to $51.5 million at December 31, 2003. The PBO includes expectations of future employee compensation increases. The accumulated benefit obligation (ABO) of the Pension Plan was approximately $68.1 million less than Pension Plan assets at December 31, 2003 and approximately $46.1 million less than Pension Plan assets at December 31, 2002. The ABO is the obligation for employee service and compensation provided through December 31, 2003. If the ABO for the entire Pension Plan exceeds all Pension Plan assets at a future plan measurement date, NU will record an additional minimum liability of which WMECO will be allocated its proportionate share. WMECO has not made employer contributions since 1991.
The value of PBOP Plan assets has increased from $13.3 million at December 31, 2002 to $17.5 million at December 31, 2003. The investment performance returns, despite declining discount rates, have decreased the underfunded status of the PBOP Plan on an accumulated projected benefit obligation basis from $23.3 million at December 31, 2002 to $18.5 million at December 31, 2003. WMECO has made a contribution each year equal to the PBOP Plan's postretirement benefit cost, excluding curtailments, settlements and special termination benefits.
Health Care Cost: The health care cost trend assumption used to project increases in medical costs is 9 percent for 2003, decreasing one percentage point per year to an ultimate rate of 5 percent in 2007. The effect of increasing the health care cost trend by one percentage point would have increased 2003 service and interest cost components of the PBOP Plan cost by $0.1 million in 2003 and $0.1 million in 2002.
Accounting for the Effect of Medicare Changes on PBOP: On December 8, 2003, the President signed into law a bill that expands Medicare, primarily by adding a prescription drug benefit and by adding a federal subsidy to qualifying plan sponsors of retiree health care benefit plans. Management believes that WMECO currently qualifies.
Specific authoritative accounting guidance on how to account for the effect the Medicare federal subsidy has on WMECO's PBOP Plan has not been issued by the FASB. FASB Staff Position (FSP) No. FAS 106-1, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003," required WMECO to make an election for 2003 financial reporting. The election was to either defer the impact of the subsidy until the FASB issues guidance or to reflect the impact of the subsidy on December 31, 2003 reported amounts. WMECO chose to reflect the impact on December 31, 2003 reported amounts.
Reflecting the impact of the Medicare change decreased the PBOP benefit obligation by $2.3 million and increased actuarial gains by approximately $2.3 million with no impact on 2003 expenses, assets, or liabilities. The $2.3 million actuarial gain will be amortized as a reduction to PBOP expense over 13 years beginning in 2004. PBOP expense in 2004 will also reflect a lower interest cost due to the reduction in the December 31, 2003 benefit obligation. Management estimates that the reduction in PBOP expense in 2004 will be approximately $0.2 million.
When accounting guidance is issued by the FASB, it may require WMECO to change the accounting described above and change the information included in this annual report.
Income Taxes: Income tax expense is calculated each year in each of the jurisdictions in which WMECO operates. This process involves estimating WMECO's actual current tax exposures as well as assessing temporary differences resulting from differing treatment of items, such as timing of the deduction and expenses for tax and book accounting purposes. These differences result in deferred tax assets and liabilities, which are included in WMECO's consolidated balance sheets. Adjustments made to income taxes could significantly affect WMECO's consolidated financial statements. Management must also assess the likelihood that deferred tax assets will be recovered from future taxable income, and to the extent that recovery is not likely, a valuation allowance must be established. Significant management judgment is required in determining income tax expense and deferred tax assets and liabilities.
WMECO accounts for deferred taxes under SFAS No. 109, "Accounting for Income Taxes." For temporary differences recorded as deferred tax liabilities that will be recovered in rates in the future, WMECO has established a regulatory asset. The regulatory asset amounted to $60.1 million and $54.2 million at December 31, 2003 and 2002, respectively. Regulatory agencies in certain jurisdictions in which WMECO operates require the tax effect of specific temporary differences to be "flowed through" to utility customers. Flow through treatment means that deferred tax expense is not recorded on the consolidated statements of income. Instead, the tax effect of the temporary difference impacts both amounts for income tax expense currently included in customers' rates and the company's net income. Flow through treatment can result in effective income tax rates that are significantly different than expected income tax rates. Recording deferred taxes on flow through items is required by SFAS No. 109, and the offset to the deferred tax amounts is the regulatory asset referred to above. A reconciliation from expected tax expense at the statutory federal income tax rate to actual tax expense recorded is included in Note 11, "Income Tax Expense," to the consolidated financial statements.
The estimates that are made by management in order to record income tax expense, accrued taxes and deferred taxes are compared each year to the actual tax amounts filed on WMECO's income tax returns. The income tax returns were filed in the fall of 2003 for the 2002 tax year. In the fourth quarter, WMECO recorded differences between income tax expense, accrued taxes and deferred taxes on its consolidated financial statements and the amounts that were on its income tax returns. Recording these differences in income tax expense resulted in a negative impact of approximately $0.1 million on WMECO's 2003 earnings.
Depreciation: Depreciation expense is calculated based on an asset's useful life, and judgment is involved when estimating the useful lives of certain assets. A change in the estimated useful lives of these assets could have a material impact on WMECO's consolidated financial statements absent timely rate relief for WMECO's assets.
Accounting for Environmental Reserves: Environmental reserves are accrued using a probabilistic model approach when assessments indicate that it is probable that a liability has been incurred and an amount can be reasonably estimated. Adjustments made to environmental liabilities could have a significant effect on earnings. The probabilistic model approach estimates the liability based on the most likely action plan from a variety of available remediation options, ranging from no action to remedies ranging from establishing institutional controls to full site remediation and long- term monitoring. The probabilistic model approach estimates the liabilities associated with each possible action plan based on findings through various phases of site assessments. These estimates are based on currently available information from presently enacted state and federal environmental laws and regulations and several cost estimates from outside engineering and remediation contractors. These amounts also take into consideration prior experience in remediating contaminated sites and data released by the United States Environmental Protection Agency and other organizations.
These estimates are subjective in nature partly because there are usually several different remediation options from which to choose when working on a specific site. These estimates are subject to revisions in future periods based on actual costs or new information concerning either the level of contamination at the site or newly enacted laws and regulations. The amounts recorded as environmental liabilities on the consolidated balance sheets represent management's best estimate of the liability for environmental costs based on current site information from site assessments and remediation estimates. These liabilities are estimated on an undiscounted basis.
WMECO does not have a recovery mechanism for environmental costs, and changes in WMECO's environmental reserves impact WMECO's earnings.
Asset Retirement Obligations: WMECO adopted SFAS No. 143, "Accounting for Asset Retirement Obligations" on January 1, 2003. SFAS No. 143 requires that legal obligations associated with the retirement of property, plant and equipment be recorded as a liability on the balance sheet at fair value when incurred and when a reasonable estimate of the fair value can be made. SFAS No. 143 defines an asset retirement obligation (ARO) as a legal obligation that is required to be settled due to an existing or enacted law, statute, ordinance or a written or oral promise to remove an asset. AROs may stem from environmental laws, state laws and regulations, easement agreements, building codes, contracts, franchise grants and agreements, oral promises made upon which third parties have relied, or the dismantlement, restoration, or reclamation of properties.
Upon adoption of SFAS No. 143, certain removal obligations were identified that management believes are AROs but either have not been incurred or are not material. These removal obligations arise in the ordinary course of business or have a low probability of occurring. The types of obligations primarily relate to transmission and distribution lines and poles, telecommunication towers, transmission cables and certain FERC or state regulatory agency re-licensing issues. There was no impact to WMECO's earnings upon adoption of SFAS No. 143; however, if there are changes in certain laws and regulations, orders, interpretations or contracts entered into by WMECO there may be future AROs that need to be recorded.
Under SFAS No. 71, regulated utilities, including WMECO, currently recover amounts in rates for future costs of removal of plant assets. Future removals of assets do not represent legal obligations and are not AROs. Historically, these amounts were included as a component of accumulated depreciation until spent. At December 31, 2003 and 2002, these amounts totaling $25 million and $17 million, respectively, were reclassified to regulatory liabilities on the accompanying consolidated balance sheets.
In June 2003, the FASB issued a proposed FSP, "Applicability of SFAS No. 143, 'Accounting for Asset Retirement Obligations', to Legislative Requirements on Property Owners to Remove and Dispose of Asbestos or Asbestos-Containing Materials." In the FSP, the FASB staff concludes that current legislation creates a legal obligation for the owner of a building to remove and dispose of asbestos-containing materials. In the FSP, the FASB staff also concludes that this legal obligation constitutes an ARO that should be recognized as a liability under SFAS No. 143. This FSP changes a FASB staff interpretation of SFAS No. 143 that an obligating event did not occur until a building containing asbestos was demolished. In November 2003, the FASB indicated that, based on the diverse views it received in comment letters on the proposed FSP, it was considering a proposal for a FASB agenda project to address this issue. If this FSP is adopted in its current form, then WMECO would be required to record an ARO. Management has not estimated this potential ARO at December 31, 2003.
Special Purpose Entity: During 2001, to facilitate the issuance of rate reduction certificates intended to finance certain stranded costs, WMECO established WMECO Funding LLC. WMECO Funding LLC was created as part of a state-sponsored securitization program. WMECO Funding LLC is restricted from engaging in non-related activities and is required to operate in a manner intended to reduce the likelihood that it would be included in WMECO's bankruptcy estate if it ever became involved in a bankruptcy proceeding. WMECO Funding LLC and the securitization amounts are consolidated in the accompanying consolidated financial statements.
For further information regarding the matters in this "Critical Accounting Policies and Estimates" section see Note 1, "Summary of Significant Accounting Policies," Note 3, "Derivative Instruments and Risk Management Activities," Note 4, "Pension Benefits and Postretirement Benefits Other Than Pensions," Note 11, "Income Tax Expense," and Note 6B, "Commitments and Contingencies - Environmental Matters," to the consolidated financial statements.
OTHER MATTERS
Commitments and Contingencies: For further information regarding other
commitments and contingencies, see Note 6, "Commitments and Contingencies,"
to the consolidated financial statements.
Contractual Obligations and Commercial Commitments: Information regarding WMECO's contractual obligations and commercial commitments at December 31, 2003 is summarized through 2008 and thereafter as follows:
---------------------------------------------------------------------------------------------------- (Millions of Dollars) 2004 2005 2006 2007 2008 Thereafter ---------------------------------------------------------------------------------------------------- Notes payable to banks (a) $10.0 $ - $ - $ - $ - $ - Long-term debt (a) - - - - - 108.8 Operating leases (b)(c) 3.3 3.2 2.9 2.7 2.5 9.0 Long-term contractual arrangements (b)(c) 9.9 9.5 9.5 9.1 9.1 47.6 ---------------------------------------------------------------------------------------------------- Totals $23.2 $12.7 $12.4 $11.8 $11.6 $165.4 ---------------------------------------------------------------------------------------------------- |
(a) Included in WMECO's debt agreements are usual and customary positive, negative and financial covenants. Non-compliance with certain covenants, for example the timely payment of principal and interest, may constitute an event of default, which could cause an acceleration of principal in the absence of receipt by the company of a waiver or amendment. Such acceleration would change the obligations outlined in the table of contractual obligations and commercial commitments. Long-term debt excludes fees and interest due for spent nuclear fuel disposal costs and unamortized premium and discount, net.
(b) WMECO has no provisions in its operating lease agreements related to its long-term contractual arrangements that could trigger a change in terms and conditions, such as acceleration of payment obligations.
(c) Amounts are not included on WMECO's consolidated balance sheets.
Rate reduction bond amounts are non-recourse to WMECO, have no required payments over the next five years and are not included in this table. Additionally, this table does not include notes payable to affiliated companies totaling $31.4 million at December 31, 2003 and WMECO's expected contribution to the PBOP Plan in 2004 of $4 million. WMECO's standard offer service contracts and default service contracts are also not included in this table. For further information regarding WMECO's contractual obligations and commercial commitments, see Note 2, "Short-Term Debt," Note 8, "Leases," Note 6E, "Commitments and Contingencies - Long-Term Contractual Arrangements," and Note 10, "Long-Term Debt," to the consolidated financial statements.
Forward Looking Statements: This discussion and analysis includes forward looking statements, which are statements of future expectations and not facts including, but not limited to, statements regarding future earnings, refinancings, regulatory proceedings, the use of proceeds from restructuring, and the recovery of operating costs. Words such as estimates, expects, anticipates, intends, plans, and similar expressions identify forward looking statements. Actual results or outcomes could differ materially as a result of further actions by state and federal regulatory bodies, competition and industry restructuring, changes in economic conditions, changes in weather patterns, changes in laws, developments in legal or public policy doctrines, technological developments, volatility in electric commodity markets, and other presently unknown or unforeseen factors.
Website: Additional financial information is available through NU's website at www.nu.com.
RESULTS OF OPERATIONS
The following table provides the variances in income statement line items for the consolidated statements of income included in this annual report for the past two years.
---------------------------------------------------------------------------------------------------
2003 over/(under) 2002 2002 over/(under) 2001
Income Statement Variances ---------------------- ------------------------
(Millions of Dollars) Amount Percent Amount Percent
---------------------------------------------------------------------------------------------------
Operating Revenues $ 22 6% $(109) (23)%
Operating Expenses:
Fuel, purchased and net interchange power 18 10 (135) (43)
Other operation 10 20 (18) (26)
Maintenance 1 5 (5) (26)
Depreciation - - 1 4
Amortization of regulatory assets, net 11 37 (98) (76)
Amortization of rate reduction bonds - - 6 (a)
Taxes other than income taxes 1 11 (2) (18)
Gain on sale of utility plant - - 120 100
---------------------------------------------------------------------------------------------------
Total operating expenses 41 13 (131) (30)
---------------------------------------------------------------------------------------------------
Operating income (19) (32) 22 58
Interest expense, net (1) (4) (1) (6)
Other income/(loss), net 4 (a) - -
---------------------------------------------------------------------------------------------------
Income before income tax expense (14) (33) 23 (a)
Income tax expense 7 100 - -
---------------------------------------------------------------------------------------------------
Net income $(21) (57)% $ 23 (a)%
===================================================================================================
|
(a) Percent greater than 100.
OPERATING REVENUES
Operating revenues increased $22 million in 2003, primarily due to higher
retail revenues ($17 million) and higher wholesale revenues ($5 million).
Retail revenues were higher primarily due to higher retail sales volumes ($9
million) and an increase in the standard offer service rate resulting from a
competitive bid process required by the DTE ($10 million). Retail sales
increased by 2.6 percent. Wholesale revenues were higher primarily due to
higher wholesale sales.
Operating revenues decreased $109 million in 2002, primarily due to lower retail revenues ($71 million) and lower wholesale and other revenues ($38 million). Retail revenues were lower primarily due to a decrease in the standard offer service rate resulting from a competitive bid process required by the DTE ($109 million) partially offset by an increase in the transition charge rate ($32 million) and higher distribution revenues from higher retail sales ($11 million). Retail sales increased by 1.9 percent. The decrease in revenues related to the standard offer service rate is offset by a corresponding decrease in fuel, purchased and net interchange power expense. Wholesale revenues were lower primarily due to the inclusion in 2001 of revenue from the output of Millstone ($14 million) and the lower sales of energy and capacity due to the buydown and buyout of various cogenerator contracts ($12 million). The buydown and buyout of cogeneration contracts has a corresponding decrease in fuel, purchased and net interchange power expense.
FUEL, PURCHASED AND NET INTERCHANGE POWER
Fuel, purchased and net interchange power expense increased $18 million in
2003, primarily due to higher standard offer purchases ($10 million) as a
result of the retail sales increase and higher standard offer supply costs
due to the rebidding of the supply in 2003 and higher wholesale purchases of
energy and capacity.
Fuel, purchased and net interchange power expense decreased $135 million in 2002, primarily due to the lower supply price for standard offer service ($109 million), the buydown and buyout of various cogeneration contracts ($12 million) and lower nuclear fuel expense ($9 million).
OTHER OPERATION AND MAINTENANCE
Other operation and maintenance (O&M) expenses increased $11 million in 2003
due to lower pension income ($7 million) and higher transmission expense ($4
million).
Other O&M expenses decreased $23 million in 2002, primarily due to the lack of nuclear expenses in 2002 as a result of the sale of Millstone at the end of the first quarter in 2001 ($12 million) and lower administrative and general expenses ($9 million).
DEPRECIATION
Depreciation increased $1 million in 2002, primarily due to an increase in
utility plant balances.
AMORTIZATION OF REGULATORY ASSETS, NET
Amortization of regulatory assets, net increased $11 million in 2003
primarily due to the higher recovery of stranded costs.
Amortization of regulatory assets, net decreased $98 million in 2002 primarily due to the amortization in 2001 related to the sale of Millstone ($120 million) and lower amortization related to the recovery of the Millstone investment ($15 million), partially offset by higher amortization in 2002 related to the recovery of stranded costs ($37 million).
AMORTIZATION OF RATE REDUCTION BONDS
Amortization of rate reduction bonds increased $6 million in 2002 due to the
repayment of principal.
TAXES OTHER THAN INCOME TAXES
Taxes other than income taxes increased $1 million in 2003 primarily due to
the absence of the benefit of a Connecticut sales tax settlement recognized
in 2002.
Taxes other than income taxes decreased $2 million in 2002, primarily due to a decrease in local property taxes and the benefit of a Connecticut sales tax settlement.
GAIN ON SALE OF UTILITY PLANT
WMECO recorded a $120 million gain in 2001 on the sale of its ownership
interest in Millstone. A corresponding amount of amortization expense was
recorded.
INTEREST EXPENSE, NET
Interest expense, net decreased $1 million in 2003, primarily due to lower
interest on short-term debt from lower interest rates.
Interest expense, net decreased $1 million in 2002, primarily due to retirement of long-term debt in 2001.
OTHER INCOME/(LOSS), NET
Other income/(loss), net increased $4 million primarily due to the absence of
the 2002 stranded cost reconciliation adjustment ($3 million) and a gain on
disposition of property in 2003 ($2 million).
Other income/(loss), net was unchanged due to lower environmental costs recorded in 2002 ($3 million) offset by the DTE's order in 2002 in a stranded cost reconciliation adjustment resulting in a reduction to the gain from the sale of the fossil units ($3 million).
INCOME TAX EXPENSE
Income tax expense increased $7 million, primarily due to the recognition in
2002 of investment tax credits as a result of the 2002 DTE decision ($13
million), partially offset by lower taxable income. For further information
regarding income tax expense, see Note 11, "Income Tax Expense," to the
consolidated financial statements.
Income tax expense remained unchanged in 2002 as a result of higher book income offset by the recognition in 2002 of investment tax credits as a result of a regulatory decision ($13 million).
Management is responsible for the preparation, integrity, and fair presentation of the accompanying consolidated financial statements of Western Massachusetts Electric Company and subsidiary and other sections of this annual report. These financial statements, which were audited by Deloitte & Touche LLP in 2003 and 2002 and Arthur Andersen LLP in 2001, have been prepared in conformity with accounting principles generally accepted in the United States of America using estimates and judgments, where required, and giving consideration to materiality.
The company has endeavored to establish a control environment that encourages the maintenance of high standards of conduct in all of its business activities. Management is responsible for maintaining a system of internal control over financial reporting that is designed to provide reasonable assurance, at an appropriate cost-benefit relationship, to the company's management and Board of Trustees of Northeast Utilities regarding the preparation of reliable, published financial statements. The system is supported by an organization of trained management personnel, policies and procedures, and a comprehensive program of internal audits. Through established programs, the company regularly communicates to its management employees their internal control responsibilities and obtains information regarding compliance with policies prohibiting conflicts of interest and policies segregating information between regulated and unregulated subsidiary companies. The company has standards of business conduct for all employees, as well as a code of ethics for senior financial officers.
The Audit Committee of the Board of Trustees of Northeast Utilities is composed entirely of independent trustees and includes two members that the Board of Trustees considers "audit committee financial experts." The Audit Committee meets regularly with management, the internal auditors and the independent auditors to review the activities of each and to discuss audit matters, financial reporting matters, and the system of internal controls over financial reporting. The Audit Committee also meets periodically with the internal auditors and the independent auditors without management present.
Because of inherent limitations in any system of internal controls, errors or irregularities may occur and not be detected. The company believes, however, that its system of internal controls over financial reporting and control environment provide reasonable assurance that its assets are safeguarded from loss or unauthorized use and that its financial records, which are the basis for the preparation of all financial statements, are reliable. Additionally, management believes that its disclosure controls and procedures are in place and operating effectively. Disclosure controls and procedures are designed to ensure that information included in reports such as this annual report is recorded, processed, summarized, and reported within the time periods required and that the information disclosed is accumulated and reviewed by management for discussion and approval.
To the Board of Directors
of Western Massachusetts Electric Company:
We have audited the accompanying consolidated balance sheets of Western Massachusetts Electric Company and subsidiary (a Massachusetts corporation and a wholly owned subsidiary of Northeast Utilities) (the "Company") as of December 31, 2003 and 2002, and the related consolidated statements of income, comprehensive income, common stockholder's equity, and cash flows for the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. The consolidated financial statements of the Company as of December 31, 2001, and for the year then ended, were audited by other auditors who have ceased operations. Those auditors expressed an unqualified opinion on those financial statements in their report dated January 22, 2002.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the 2003 and 2002 consolidated financial statements present fairly, in all material respects, the financial position of Western Massachusetts Electric Company and subsidiary as of December 31, 2003 and 2002, and the results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.
/s/ DELOITTE & TOUCHE LLP
DELOITTE & TOUCHE LLP
Hartford, Connecticut
February 23, 2004
|
To the Board of Directors
of Western Massachusetts Electric Company:
We have audited the accompanying consolidated balance sheets of Western Massachusetts Electric Company (a Massachusetts corporation and a wholly owned subsidiary of Northeast Utilities) and subsidiary as of December 31, 2001 and 2000, and the related consolidated statements of income, comprehensive income, common stockholder's equity and cash flows for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Western Massachusetts Electric Company and subsidiary as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States.
/s/ ARTHUR ANDERSEN LLP
ARTHUR ANDERSEN LLP
Hartford, Connecticut
January 22, 2002
|
Readers of these consolidated financial statements should be aware that this report is a copy of a previously issued Arthur Andersen LLP report and that this report has not been reissued by Arthur Andersen LLP. Furthermore, this report has not been updated since January 22, 2002, and Arthur Andersen LLP completed its last post-audit review of December 31, 2001, consolidated financial information on May 13, 2002.
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
-----------------------------------------------------------------------------------------------
At December 31, 2003 2002
-----------------------------------------------------------------------------------------------
(Thousands of Dollars)
ASSETS
------
Current Assets:
Cash $ 1 $ 123
Receivables, less provision for uncollectible
accounts of $2,551 in 2003 and $1,958 in 2002 40,103 42,203
Accounts receivable from affiliated companies 20 6,354
Unbilled revenues 10,299 8,944
Materials and supplies, at average cost 1,584 1,821
Prepayments and other 1,139 1,470
---------------- ----------------
53,146 60,915
---------------- ----------------
Property, Plant and Equipment:
Electric utility 612,450 590,153
Less: Accumulated depreciation 177,803 178,804
---------------- ----------------
434,647 411,349
Construction work in progress 13,124 11,860
---------------- ----------------
447,771 423,209
---------------- ----------------
Deferred Debits and Other Assets:
Regulatory assets 268,180 283,702
Prepaid pension 75,386 67,516
Other 19,081 18,304
---------------- ----------------
362,647 369,522
---------------- ----------------
Total Assets $ 863,564 $ 853,646
================ ================
|
The accompanying notes are an integral part of these consolidated financial statements.
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
--------------------------------------------------------------------------------------------
At December 31, 2003 2002
--------------------------------------------------------------------------------------------
(Thousands of Dollars)
LIABILITIES AND CAPITALIZATION
------------------------------
Current Liabilities:
Notes payable to banks $ 10,000 $ 7,000
Notes payable to affiliated companies 31,400 85,900
Accounts payable 10,173 17,730
Accounts payable to affiliated companies 13,789 6,218
Accrued taxes 765 4,334
Accrued interest 2,544 2,059
Other 9,785 8,005
---------------- ----------------
78,456 131,246
---------------- ----------------
Rate Reduction Bonds 132,960 142,742
---------------- ----------------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 216,547 222,065
Accumulated deferred investment tax credits 3,326 3,662
Deferred contractual obligations 86,937 63,767
Regulatory liabilities 27,776 17,443
Other 8,357 12,770
---------------- ----------------
342,943 319,707
---------------- ----------------
Capitalization:
Long-Term Debt 157,202 101,991
---------------- ----------------
Common Stockholder's Equity:
Common stock, $25 par value - authorized
1,072,471 shares; 434,653 shares outstanding
in 2003 and 2002 10,866 10,866
Capital surplus, paid in 69,544 69,712
Retained earnings 71,677 77,476
Accumulated other comprehensive loss (84) (94)
---------------- ----------------
Common Stockholder's Equity 152,003 157,960
---------------- ----------------
Total Capitalization 309,205 259,951
---------------- ----------------
Commitments and Contingencies (Note 6)
Total Liabilities and Capitalization $ 863,564 $ 853,646
================ ================
|
The accompanying notes are an integral part of these consolidated financial statements.
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF INCOME
-------------------------------------------------------------------------------------------------------------------
For the Years Ended December 31, 2003 2002 2001
-------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Operating Revenues $ 391,178 $ 369,487 $ 478,869
-------------- -------------- --------------
Operating Expenses:
Operation -
Fuel, purchased and net interchange power 198,985 181,485 315,903
Other 59,020 49,039 66,458
Maintenance 15,289 14,499 19,635
Depreciation 14,104 14,381 13,818
Amortization of regulatory assets, net 41,695 30,327 128,321
Amortization of rate reduction bonds 9,847 9,385 3,555
Taxes other than income taxes 11,844 10,688 13,065
Gain on sale of utility plant - - (119,775)
-------------- -------------- --------------
Total operating expenses 350,784 309,804 440,980
-------------- -------------- --------------
Operating Income 40,394 59,683 37,889
Interest Expense:
Interest on long-term debt 3,860 2,942 4,940
Interest on rate reduction bonds 8,994 9,587 6,251
Other interest 965 1,857 4,120
-------------- -------------- --------------
Interest expense, net 13,819 14,386 15,311
-------------- -------------- --------------
Other Income/(Loss), Net 3,167 (850) (1,050)
-------------- -------------- --------------
Income Before Income Tax Expense 29,742 44,447 21,528
Income Tax Expense 13,530 6,765 6,560
-------------- -------------- --------------
Net Income $ 16,212 $ 37,682 $ 14,968
============== ============== ==============
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Net Income $ 16,212 $ 37,682 $ 14,968
-------------- -------------- --------------
Other comprehensive income/(loss), net of tax:
Unrealized gains/(losses) on securities 37 (110) (123)
Minimum supplemental executive retirement
pension liability adjustments (27) (43) -
-------------- -------------- --------------
Other comprehensive income/(loss), net of tax 10 (153) (123)
-------------- -------------- --------------
Comprehensive Income $ 16,222 $ 37,529 $ 14,845
============== ============== ==============
|
The accompanying notes are an integral part of these consolidated financial statements.
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
-----------------------------------------------------------------------------------------------------------------------
Accumulated
Common Stock Capital Other
---------------------- Surplus, Retained Comprehensive Total
Shares Amount Paid In Earnings Income/(Loss) (a)
-----------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars, except share information)
Balance at January 1, 2001 590,093 $ 14,752 $ 94,010 $ 62,952 $ 182 $ 171,896
Net income for 2001 14,968 14,968
Cash dividends on preferred stock (404) (404)
Cash dividends on common stock (22,000) (22,000)
Repurchase of common stock (80,397) (2,010) (12,990) (15,000)
Capital stock expenses, net 1,204 1,204
Allocation of benefits - ESOP (94) (94)
Other comprehensive loss (123) (123)
--------- ---------- ---------- ---------- --------- -----------
Balance at December 31, 2001 509,696 12,742 82,224 55,422 59 150,447
Net income for 2002 37,682 37,682
Cash dividends on common stock (16,009) (16,009)
Repurchase of common stock (75,043) (1,876) (12,123) (13,999)
Capital stock expenses, net 131 131
Allocation of benefits - ESOP (520) 381 (139)
Other comprehensive loss (153) (153)
--------- ---------- ---------- ---------- --------- -----------
Balance at December 31, 2002 434,653 10,866 69,712 77,476 (94) 157,960
Net income for 2003 16,212 16,212
Cash dividends on common stock (22,011) (22,011)
Allocation of benefits - ESOP (168) (168)
Other comprehensive income 10 10
--------- ---------- ---------- ---------- --------- -----------
Balance at December 31, 2003 434,653 $ 10,866 $ 69,544 $ 71,677 $ (84) $ 152,003
========= ========== ========== ========== ========= ===========
|
(a) The Federal Power Act, and the Public Utility Holding Act of 1935 (the 1935 Act) limit the payment of dividends by the company to its retained earnings balance.
The Utility Group credit agreement also limits dividend payments subject to the requirements that the company's total debt to total capitalization ratio does not exceed 65 percent.
At December 31, 2003, retained earnings available for payment of dividends is restricted to $46.3 million.
The accompanying notes are an integral part of these consolidated financial statements.
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
------------------------------------------------------------------------------------------------------------------------
For the Years Ended December 31, 2003 2002 2001
-------------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Operating Activities:
Net income $ 16,212 $ 37,682 $ 14,968
Adjustments to reconcile to net cash flows
provided by operating activities:
Depreciation 14,104 14,381 13,818
Deferred income taxes and investment tax credits, net (14,315) (26,952) 5,281
Amortization of regulatory assets, net 41,695 30,327 128,321
Amortization of rate reduction bonds 9,847 9,385 3,555
Amortization of recoverable energy costs 598 (529) 3,179
Gain on sale of utility plant - - (119,775)
Increase in prepaid pension (7,870) (13,290) (8,453)
Regulatory overrecoveries 6,265 24,984 112,025
Other sources of cash 8,672 19,870 64,065
Other uses of cash (24,355) (53,355) (177,340)
Changes in current assets and liabilities:
Receivables and unbilled revenues, net 7,079 1,199 15,017
Materials and supplies 237 (365) 149
Other current assets (excludes cash) 330 74 3,273
Accounts payable 14 (13,989) 4,043
Accrued taxes (3,569) 643 (4,780)
Other current liabilities 2,266 (2,425) (192)
---------- --------- ----------
Net cash flows provided by operating activities 57,210 27,640 57,154
---------- --------- ----------
Investing Activities:
Investments in plant (30,386) (23,148) (30,676)
NU system Money Pool (lending)/borrowing (54,500) 76,700 8,600
Investments in nuclear decommissioning trusts - - (23,037)
Net proceeds from the sale of utility plant - - 175,154
Buyout of IPP contract - - (80,000)
Other investment activities 1,377 937 817
---------- --------- ----------
Net cash flows (used in)/provided by investing activities (83,509) 54,489 50,858
---------- --------- ----------
Financing Activities:
Issuance of long-term debt 55,000 - -
Repurchase of common shares - (13,999) (15,000)
Issuance of rate reduction bonds - - 155,000
Retirement of rate reduction bonds (9,782) (9,575) (2,683)
Increase/(decrease) in short-term debt 3,000 (43,000) (60,000)
Reacquisitions and retirements of long-term debt - - (100,000)
Reacquisitions and retirements of preferred stock - - (36,500)
Retirement of capital lease obligation - - (34,200)
Cash dividends on preferred stock - - (404)
Cash dividends on common stock (22,011) (16,009) (22,000)
Other financing activities (30) (22) 7,389
---------- --------- ----------
Net cash flows provided by/(used in) financing activities 26,177 (82,605) (108,398)
---------- --------- ----------
Net decrease in cash (122) (476) (386)
Cash - beginning of year 123 599 985
---------- --------- ----------
Cash - end of year $ 1 $ 123 $ 599
========== ========= ==========
Supplemental Cash Flow Information:
Cash paid during the year for:
Interest, net of amounts capitalized $ 13,560 $ 14,934 $ 17,939
========== ========= ==========
Income taxes $ 31,807 $ 32,522 $ 6,314
========== ========= ==========
|
The accompanying notes are an integral part of these consolidated financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A. ABOUT WESTERN MASSACHUSETTS ELECTRIC COMPANY Western Massachusetts Electric Company (WMECO or the company) is a wholly owned subsidiary of Northeast Utilities (NU). WMECO is registered with the Securities and Exchange Commission (SEC) under the Securities Exchange Act of 1934. NU is registered with the SEC as a holding company under the Public Utility Holding Company Act of 1935 (1935 Act), and NU, including WMECO, is subject to the provisions of the 1935 Act. Arrangements among WMECO, other NU companies, outside agencies, and other utilities covering interconnections, interchange of electric power and sales of utility property, are subject to regulation by the Federal Energy Regulatory Commission (FERC) and/or the SEC. WMECO is subject to further regulation for rates, accounting and other matters by the FERC and the Massachusetts Department of Telecommunications and Energy (DTE). WMECO, The Connecticut Light and Power Company (CL&P) and Public Service Company of New Hampshire (PSNH), furnish franchised retail electric service in Massachusetts, Connecticut and New Hampshire, respectively.
Several wholly owned subsidiaries of NU provide support services for NU's companies, including WMECO. Northeast Utilities Service Company (NUSCO) provides centralized accounting, administrative, engineering, financial, information technology, legal, operational, planning, purchasing, and other services to NU's companies.
WMECO's purchases from Select Energy, Inc. (Select Energy), another NU subsidiary, for standard offer and default service and for other transactions with Select Energy represented approximately $143 million, $14 million and $4 million for the years ended December 31, 2003, 2002 and 2001, respectively.
B. PRESENTATION The consolidated financial statements of WMECO include the accounts of its subsidiary WMECO Funding LLC. Intercompany transactions have been eliminated in consolidation.
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingencies at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Certain reclassifications of prior years' data have been made to conform with the current year's presentation. Reclassifications were made to cost of removal and regulatory asset and liability amounts on the accompanying consolidated balance sheets. Reclassifications have also been made to the accompanying consolidated statements of cash flows.
C. NEW ACCOUNTING STANDARDS Derivative Accounting: Effective January 1, 2001, WMECO adopted Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities." In April 2003, the Financial Accounting Standards Board (FASB) issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities," which amends SFAS No. 133. This new statement incorporates interpretations that were included in previous Derivative Implementation Group guidance, clarifies certain conditions, and amends other existing pronouncements. It is effective for contracts entered into or modified after June 30, 2003. Management has determined that the adoption of SFAS No. 149 did not change WMECO's accounting for contracts, or the ability of WMECO to elect the normal purchases and sales exception.
Employers' Disclosures about Pensions and Other Postretirement Benefits: In December 2003, the FASB issued SFAS No. 132 (Revised 2003), "Employers' Disclosures about Pensions and Other Postretirement Benefits," (SFAS No. 132R). This statement revises employers' disclosures about pension plans and other postretirement benefit plans, requires additional disclosures about the assets, obligations, cash flows, and the net periodic benefit cost of defined benefit pension plans and other defined benefit postretirement plans and requires companies to disclose various elements of pension and postretirement benefit costs in interim period financial statements. The revisions in SFAS No. 132R are effective for 2003, and WMECO included the disclosures required by SFAS No. 132R in this annual report. For the required disclosures, see Note 4, "Pension Benefits and Postretirement Benefits Other Than Pensions," to the consolidated financial statements.
Liabilities and Equity: In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity." SFAS No. 150 establishes standards on how to classify and measure certain financial instruments with characteristics of both liabilities and equity. SFAS No. 150 is effective for financial instruments entered into or modified after May 31, 2003, and was otherwise effective for WMECO for the third quarter of 2003. As WMECO no longer has any preferred stock subject to mandatory redemption, the adoption of SFAS No. 150 did not have an impact on WMECO's consolidated financial statements.
Consolidation of Variable Interest Entities: In December 2003, the FASB issued a revised version of FASB Interpretation No. (FIN) 46 "Consolidation of Variable Interest Entities," (FIN 46R). FIN 46R is effective for WMECO for the first quarter of 2004 but is not expected to have an impact on WMECO's consolidated financial statements.
D. GUARANTEES At December 31, 2003, NU had outstanding guarantees to WMECO of $2.5 million. WMECO had no guarantees outstanding at December 31, 2003.
E. REVENUES WMECO retail revenues are based on rates approved by the DTE. These regulated rates are applied to customers' use of energy to calculate a bill. In general, rates can only be changed through formal proceedings with the DTE.
WMECO utilizes regulatory commission-approved tracking mechanisms to track the recovery of certain incurred costs. The tracking mechanisms allow for rates to be changed periodically, with overcollections refunded to customers or undercollections collected from customers in future periods.
Unbilled revenues represent an estimate of electricity delivered to customers that has not been billed. Unbilled revenues represent assets on the balance sheet that become accounts receivable in the following month as customers are billed. Billed revenues are based on meter readings.
Unbilled revenues are estimated monthly using the requirements method. The requirements method utilizes the total monthly volume of electricity delivered to the system and applies a delivery efficiency factor to reduce the total monthly volume by an estimate of delivery losses in order to calculate total estimated monthly sales to customers. The total estimated monthly sales amount less total monthly billed sales amount results in a monthly estimate of unbilled sales. Unbilled revenues are estimated by applying an average rate to the estimate of unbilled sales.
In 2003, the unbilled sales estimates for WMECO were tested using the cycle method. The cycle method uses the billed sales from each meter reading cycle and an estimate of unbilled days in each month based on the meter reading schedule. The cycle method is historically more accurate than the requirements method when used in a mostly weather-neutral month. The cycle method resulted in adjustments to the estimate of unbilled revenues that had a positive after-tax earnings impact on WMECO of $0.3 million in 2003.
Wholesale transmission revenues are based on rates and formulas that are approved by the FERC. Most of WMECO's wholesale transmission revenues are collected through a combination of the New England Regional Network Service (RNS) tariff and WMECO's Local Network Service (LNS) tariff. The RNS tariff, which is administered by the New England Independent System Operator, recovers the revenue requirements associated with transmission facilities that are deemed by the FERC to be Pool Transmission Facilities. The LNS tariff which was accepted by the FERC on October 22, 2003, provides for the recovery of WMECO's total transmission revenue requirements, net of revenue credits received from various rate components, including revenues received under the RNS rates.
F. ACCOUNTING FOR ENERGY CONTRACTS The accounting treatment for energy contracts entered into varies between contracts and depends on the intended use of the particular contract and on whether or not the contracts are derivatives.
Non-derivative contracts that are entered into for the normal purchase or sale of energy to customers that will result in physical delivery are recorded at the point of delivery under accrual accounting.
Derivative contracts that are entered into for the normal purchase and sale of energy and meet the normal purchase and sale exception to derivative accounting, as defined in SFAS No. 133 and amended by SFAS No. 149 (normal), are also recorded at the point of delivery under accrual accounting.
Both non-derivative contracts and derivative contracts that are normal are recorded in revenues when these contracts represent sales, and recorded in fuel, purchased and net interchange power when these contracts represent purchases, except for sales contracts that relate to procurement activities. These contracts are recorded in fuel, purchased and net interchange power when settled.
For further information regarding these contracts and their accounting, see Note 3, "Derivative Instruments and Risk Management Activities," to the consolidated financial statements.
G. REGULATORY ACCOUNTING The accounting policies of WMECO conform to accounting principles generally accepted in the United States of America applicable to rate-regulated enterprises and historically reflect the effects of the rate-making process in accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation."
The transmission and distribution of WMECO continue to be cost-of-service rate regulated. Management believes the application of SFAS No. 71 to that portion of those businesses continues to be appropriate. Management also believes it is probable that WMECO will recover its investments in long-lived assets, including regulatory assets. In addition, all material net regulatory assets are earning an equity return, except for securitized regulatory assets, which are not supported by equity.
The components of regulatory assets are as follows:
---------------------------------------------------------------------
At December 31,
---------------------------------------------------------------------
(Millions of Dollars) 2003 2002
---------------------------------------------------------------------
Recoverable nuclear costs $ 32.7 $ 38.0
Securitized assets 132.1 141.9
Income taxes, net 60.1 54.2
Unrecovered contractual obligations 86.9 63.8
Recoverable energy costs 3.7 4.3
Rate cap deferral (57.1) (28.1)
Other 9.8 9.6
---------------------------------------------------------------------
Totals $268.2 $283.7
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Recoverable Nuclear Costs: In March 2001, WMECO sold its ownership interest in the Millstone nuclear units (Millstone). The gain on this sale of $119.8 million was used to offset recoverable nuclear costs, resulting in a total unamortized balance of $6.1 million and $7.1 million at December 31, 2003 and 2002, respectively. Also included in recoverable nuclear costs for 2003 and 2002 are $26.6 million and $30.9 million, respectively, primarily related to Millstone 1 recoverable nuclear costs associated with the recoverable portion of the undepreciated plant and related assets at the time Millstone 1 was shut down.
Securitized Assets: In May 2001, WMECO issued $155 million in rate reduction certificates and used $80 million of those proceeds to buy out an independent power producer contract. The remaining balance is $132.1 million and $141.9 million at December 31, 2003 and 2002, respectively.
Securitized assets are being recovered over the amortization period of their associated rate reduction bonds. All outstanding rate reduction bonds of WMECO are scheduled to fully amortize by June 1, 2013.
Income Taxes, Net: The tax effect of temporary differences (differences between the periods in which transactions affect income in the financial statements and the periods in which they affect the determination of taxable income) is accounted for in accordance with the rate-making treatment of the DTE and SFAS No. 109. Differences in income taxes between SFAS No. 109 and the rate-making treatment of the DTE are recorded as regulatory assets. For further information regarding income taxes, see Note 1H, "Summary of Significant Accounting Policies - Income Taxes," and Note 11, "Income Tax Expense," to the consolidated financial statements.
Unrecovered Contractual Obligations: WMECO, under the terms of contracts with three regional nuclear companies (Yankee Companies), is responsible for its proportionate share of the remaining costs of the units, including decommissioning. These amounts are recorded as unrecovered contractual obligations. A portion of these obligations were securitized in 2001 and are included in securitized regulatory assets. During 2002, WMECO was notified by the Yankee Companies that the estimated cost of decommissioning their units had increased over prior estimates due to higher anticipated costs for spent fuel storage, security and liability and property insurance. In December 2002, WMECO recorded an additional $32.4 million in deferred contractual obligations and a corresponding increase in the unrecovered contractual obligations regulatory asset as a result of these increased costs.
In November 2003, the Connecticut Yankee Atomic Power Company (CYAPC) prepared an updated estimate of the cost of decommissioning its nuclear unit. WMECO's aggregate share of the estimated increased cost is $32.5 million. WMECO recorded an additional $32.5 million in deferred contractual obligations and a corresponding increase in the unrecovered contractual obligations regulatory asset as a result of these increased costs.
Recoverable Energy Costs: Under the Energy Policy Act of 1992 (Energy Act), WMECO was assessed for its proportionate share of the costs of decontaminating and decommissioning uranium enrichment plants owned by the United States Department of Energy (DOE) (D&D Assessment). The Energy Act requires that regulators treat D&D Assessments as a reasonable and necessary current cost of fuel, to be fully recovered in rates like any other fuel cost. WMECO no longer owns nuclear generation but continues to recover these costs through rates. At December 31, 2003 and 2002, WMECO's total D&D Assessment deferrals were $3.7 million and $4.3 million, respectively, and have been recorded as recoverable energy costs.
The majority of the recoverable energy costs are recovered in rates currently from WMECO's customers.
Rate Cap Deferral: The rate cap deferral allows WMECO to recover stranded costs. These amounts represent the cumulative excess of transition cost revenues over transition cost expenses.
Regulatory Liabilities: WMECO maintained $27.8 million and $17.4 million of regulatory liabilities at December 31, 2003 and 2002, respectively. These amounts are comprised of the following:
----------------------------------------------------------------
At December 31,
----------------------------------------------------------------
(Millions of Dollars) 2003 2002
----------------------------------------------------------------
Cost of removal $25.0 $17.0
Other regulatory liabilities 2.8 0.4
----------------------------------------------------------------
Totals $27.8 $17.4
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Under SFAS No. 71, WMECO currently recovers amounts in rates for future costs of removal of plant assets. Historically, these amounts were included as a component of accumulated depreciation until spent. These amounts were reclassified to regulatory liabilities on the accompanying consolidated balance sheets.
H. INCOME TAXES The tax effect of temporary differences (differences between the periods in which transactions affect income in the financial statements and the periods in which they affect the determination of taxable income) is accounted for in accordance with the rate-making treatment of the applicable regulatory commissions and SFAS No. 109.
The tax effects of temporary differences that give rise to the net accumulated deferred tax obligation are as follows:
--------------------------------------------------------------------------
At December 31,
--------------------------------------------------------------------------
(Millions of Dollars) 2003 2002
--------------------------------------------------------------------------
Deferred tax liabilities:
Accelerated depreciation and
other plant-related differences $ 87.6 $ 76.2
Regulatory amounts:
Securitized contract termination
costs and other 22.7 27.0
Income tax gross-up 24.3 24.3
Employee benefits 30.3 27.3
Other 78.9 95.2
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Total deferred tax liabilities 243.8 250.0
--------------------------------------------------------------------------
Deferred tax assets:
Regulatory deferrals 17.3 13.3
Employee benefits 1.5 1.4
Income tax gross-up 0.2 3.2
Other 8.3 10.0
--------------------------------------------------------------------------
Total deferred tax assets 27.3 27.9
--------------------------------------------------------------------------
Totals $216.5 $222.1
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NU and its subsidiaries, including WMECO, file a consolidated federal income tax return. Likewise NU and its subsidiaries, including WMECO, file state income tax returns, with some filing in more than one state. NU and its subsidiaries, including WMECO, are parties to a tax allocation agreement under which each taxable subsidiary pays a quarterly estimate (or settlement) of no more than it would have otherwise paid had it filed a stand-alone tax return. Generally these quarterly estimated payments are settled to actual payments within three months after filing the associated return. Subsidiaries generating tax losses are similarly paid for their losses when utilized.
In 2000, NU requested from the Internal Revenue Service (IRS) a Private Letter Ruling (PLR) regarding the treatment of unamortized investment tax credits (ITC) and excess deferred income taxes (EDIT) related to generation assets that have been sold. EDIT are temporary differences between book and taxable income that were recorded when the federal statutory tax rate was higher than it is now or when those differences were expected to be resolved. The PLR addresses whether or not EDIT and ITC can be returned to customers, which without a PLR management believes would represent a violation of current tax law. The IRS declared a moratorium on issuing PLRs until final regulations on the return of EDIT and ITC to regulated customers are issued by the Treasury Department. Proposed regulations were issued in March 2003, and a hearing took place in June 2003. The proposed new regulations would allow the return of EDIT and ITC to regulated customers without violating the tax law. Also, under the proposed regulations, a company could elect to apply the regulation retroactively. The Treasury Department is currently deliberating the comments received at the hearing. If final regulations consistent with the proposed regulations are issued, then there could be an impact on WMECO's financial statements.
I. DEPRECIATION The provision for depreciation is calculated using the straight-line method based on estimated remaining useful lives of depreciable utility plant-in- service, which range primarily from 15 years to 60 years, adjusted for salvage value and removal costs, as approved by the appropriate regulatory agency where applicable. Depreciation rates are applied to the average plant- in-service from the time they are placed in service. When plant is retired from service, the original cost of the plant, including costs of removal less salvage, is charged to the accumulated provision for depreciation. Cost of removal is now classified as a regulatory liability. The depreciation rates for the several classes of electric plant-in-service are equivalent to a composite rate of 2.4 percent in 2003 and 2.3 percent in 2002 and 2001.
J. EQUITY INVESTMENTS AND JOINTLY OWNED ELECTRIC UTILITY PLANT Regional Nuclear Companies: At December 31, 2003, WMECO owns common stock in three regional nuclear companies (Yankee Companies). WMECO's ownership interests in the Yankee Companies at December 31, 2003 and 2002, which are accounted for on the equity method are 9.5 percent of CYAPC, 7 percent of the Yankee Atomic Electric Company (YAEC) and 3 percent of the Maine Yankee Atomic Power Company (MYAPC). Effective November 7, 2003, WMECO sold its 2.6 percent ownership interest in Vermont Yankee Nuclear Power Corporation (VYNPC). WMECO's total equity investment in the Yankee Companies at December 31, 2003 and 2002, is $5.9 million and $8.6 million, respectively. Each of the remaining Yankee Companies owns a single nuclear generating plant which is being decommissioned.
K. Allowance for Funds Used During Construction The allowance for funds used during construction (AFUDC) is a non-cash item that is included in the cost of WMECO plant and represents the cost of borrowed and equity funds used to finance construction. The portion of AFUDC attributable to borrowed funds is recorded as a reduction of other interest expense, and the cost of equity funds is recorded as other income on the consolidated statements of income:
(Millions of Dollars, except percentages) 2003 2002 2001 ----------------------------------------------------------- Borrowed funds $0.1 $0.3 $0.4 Equity funds - - - ----------------------------------------------------------- Totals $0.1 $0.3 $0.4 ----------------------------------------------------------- Average AFUDC rates 1.7% 3.0% 6.0% ----------------------------------------------------------- |
L. ASSET RETIREMENT OBLIGATIONS In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." This statement requires that legal obligations associated with the retirement of property, plant and equipment be recognized as a liability at fair value when incurred and when a reasonable estimate of the fair value of the liability can be made. SFAS No. 143 was effective on January 1, 2003, for WMECO. Management has completed its review process for potential asset retirement obligations (ARO) and not identified any material AROs that have been incurred. However, management identified certain removal obligations that arise in the ordinary course of business or have a low probability of occurring. These types of obligations primarily relate to transmission and distribution lines and poles, telecommunication towers, transmission cables and certain FERC or state regulatory agency re-licensing issues. These obligations are AROs that have not been incurred or are not material in nature.
A portion of WMECO's rates is intended to recover the cost of removal of certain utility assets. The amounts recovered do not represent AROs. At December 31, 2003 and 2002, cost of removal was approximately $25 million and $17 million, respectively.
M. MATERIALS AND SUPPLIES Materials and supplies include materials purchased primarily for construction, operation and maintenance (O&M) purposes. Materials and supplies are valued at the lower of average cost or market.
N. OTHER INCOME/(LOSS) The pre-tax components of WMECO's other income/(loss) items are as follows:
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For the Years Ended December 31,
----------------------------------------------------------------
(Millions of Dollars) 2003 2002 2001
----------------------------------------------------------------
Investment income $ 1.8 $ 1.6 $ 0.9
Charitable donations (0.3) (0.3) (0.4)
Other, net 1.7 (2.2) (1.6)
----------------------------------------------------------------
Totals $ 3.2 $(0.9) $(1.1)
----------------------------------------------------------------
|
Limits: The amount of short-term borrowings that may be incurred by WMECO is subject to periodic approval by the SEC under the 1935 Act or the DTE. On June 30, 2003, the SEC granted authorization allowing WMECO to incur total short-term borrowings up to a maximum of $200 million through June 30, 2006, with authorization for borrowings from the NU Money Pool (Pool) granted through June 30, 2004.
Credit Agreement: On November 10, 2003, WMECO, CL&P, PSNH, and Yankee Gas entered into a 364-day unsecured revolving credit facility for $300 million. This facility replaces a similar credit facility that expired on November 11, 2003 and WMECO may draw up to $100 million under this facility. Unless extended, the credit facility will expire on November 8, 2004. At December 31, 2003 and 2002, there were $10 million and $7 million, respectively, in borrowings under these credit facilities.
Under the aforementioned credit agreement, WMECO may borrow at fixed or variable rates plus an applicable margin based upon certain debt ratings, as rated by the lower of Standard and Poor's or Moody's Investors Service. The weighted average interest rates on WMECO's notes payable to banks outstanding on December 31, 2003 and 2002 were 1.9 percent and 4.3 percent, respectively.
Under the credit agreement, WMECO must comply with certain financial and non- financial covenants as are customarily included in such agreements, including but not limited to, consolidated debt ratios and interest coverage ratios. The most restrictive financial covenant is the interest coverage ratio. WMECO currently is and expects to remain in compliance with these covenants.
Pool: WMECO is a member of the Pool. The Pool provides a more efficient use of the cash resources of NU and reduces outside short-term borrowings. NUSCO administers the Pool as agent for the member companies. Short-term borrowing needs of the member companies are first met with available funds of other member companies, including funds borrowed by NU parent. NU parent may lend to the Pool but may not borrow. Funds may be withdrawn from or repaid to the Pool at any time without prior notice. Investing and borrowing subsidiaries receive or pay interest based on the average daily federal funds rate. Borrowings based on loans from NU parent, however, bear interest at NU parent's cost and must be repaid based upon the terms of NU parent's original borrowing. At December 31, 2003 and 2002, WMECO had borrowings of $31.4 million and $85.9 million from the Pool, respectively. The interest rate on borrowings from the Pool at December 31, 2003 and 2002 was 1 percent and 1.2 percent, respectively.
A. DERIVATIVE INSTRUMENTS Effective January 1, 2001, WMECO adopted SFAS No. 133, as amended. Derivatives that do not meet the definition of a cash flow hedge and cannot be designated as being used for normal purchases or normal sales are also recorded at fair value with changes in fair value included in earnings unless recorded as a regulatory asset or liability. Derivative contracts that are entered into as a normal purchase or sale and will result in physical delivery, and are documented as such, are recorded under accrual accounting. For information regarding accounting changes related to derivative instruments, see Note 1C, "Summary of Significant Accounting Policies - New Accounting Standards," to the consolidated financial statements. WMECO had no derivative contracts at December 31, 2003 or 2002 that required fair value accounting.
B. RISK MANAGEMENT ACTIVITIES WMECO is subject to credit risk from certain long-term or high-volume supply contracts with energy marketing companies. Credit risks and market risks at WMECO are monitored regularly by a Risk Oversight Council operating outside of the business units that create or actively manage these risk exposures to ensure compliance with NU's stated risk management policies.
Pension Benefits: WMECO participates in a uniform noncontributory defined benefit retirement plan (Pension Plan) covering substantially all regular NU employees. Benefits are based on years of service and the employees' highest eligible compensation during 60 consecutive months of employment. Pre-tax pension income was $7.9 million in 2003, $12.1 million in 2002, and $13.7 million in 2001. These amounts exclude pension settlements, curtailments and net special termination expenses of $1.2 million in income in 2002 and $0.3 million in expense in 2001. WMECO uses a December 31 measurement date for the Pension Plan. Pension income attributable to earnings is as follows:
-------------------------------------------------------------------------------
For the Years Ended December 31,
-------------------------------------------------------------------------------
(Millions of Dollars) 2003 2002 2001
-------------------------------------------------------------------------------
Pension income before
settlements, curtailments
and special termination benefits $(7.9) $(12.1) $(13.7)
Net pension income
capitalized as utility plant 3.1 4.2 4.6
-------------------------------------------------------------------------------
Net pension income before
settlements, curtailments
and special termination
benefits (4.8) (7.9) (9.1)
Settlements, curtailments and
special termination benefits
reflected in earnings - - 0.7
-------------------------------------------------------------------------------
Total pension income
included in earnings $(4.8) $ (7.9) $ (8.4)
-------------------------------------------------------------------------------
|
Pension Settlements, Curtailments and Special Termination Benefits: There were no settlements, curtailments or special termination benefits in 2003.
In conjunction with the divestiture of its generation assets, WMECO recorded $1.2 million in curtailment income in 2002, all of which was recorded as a regulatory liability and did not impact earnings.
In conjunction with the Voluntary Separation Program (VSP) that was announced in December 2000, WMECO recorded $0.2 million in settlement income in 2001. The VSP was intended to reduce the generation-related support staff between March 1, 2001 and February 28, 2002, and was available to non-bargaining unit employees who, by February 1, 2002, were at least age 50, with a minimum of five years of credited service, and at December 15, 2000, were assigned to certain groups and in eligible job classifications.
One component of the VSP included special pension termination benefits equal to the greater of 5 years added to both age and credited service of eligible participants or two weeks of pay for each year of service subject to a minimum level of 12 weeks and a maximum of 52 weeks for eligible participants. The special pension termination benefits expense associated with the VSP totaled $0.5 million in 2001. The net total of the settlement and curtailment income and the special termination benefits expense was $0.3 million, of which $0.7 million of costs were included in operating expenses, $0.4 million was deferred as a regulatory liability and is expected to be returned to customers.
Postretirement Benefits Other Than Pensions (PBOP): WMECO also provides certain health care benefits, primarily medical and dental, and life insurance benefits through a benefit plan to retired employees (PBOP Plan). These benefits are available for employees retiring from WMECO who have met specified service requirements. For current employees and certain retirees, the total benefit is limited to two times the 1993 per retiree health care cost. These costs are charged to expense over the estimated work life of the employee. WMECO uses a December 31 measurement date for the PBOP Plan. WMECO annually funds postretirement costs through external trusts with amounts that have been rate-recovered and which also are tax deductible.
In 2002, the PBOP Plan was amended to change the claims experience basis, to increase minimum retiree contributions and to reduce the cap on the company's subsidy to the dental plan. These amendments resulted in a $2.1 million decrease in WMECO's benefit obligation under the PBOP Plan at December 31, 2002.
Impact of New Medicare Changes on PBOP: On December 8, 2003, the President signed into law a bill that expands Medicare, primarily by adding a prescription drug benefit starting in 2006 for Medicare-eligible retirees as well as a federal subsidy to plan sponsors of retiree health care benefit plans who provide a prescription drug benefit at least actuarially equivalent to the new Medicare benefit.
Based on the current PBOP Plan provisions, WMECO's actuaries believe that WMECO will qualify for this federal subsidy because the actuarial value of WMECO's PBOP Plan is estimated to be 60 percent greater than that of the standard Medicare benefit. WMECO will directly benefit from the federal subsidy for retirees who retired before 1991. For other retirees, management does not believe that WMECO will benefit from the subsidy because WMECO's cost support for these retirees is capped at a fixed dollar commitment.
The aggregate effect of recognizing the Medicare change is a decrease to the PBOP benefit obligation of $2.3 million. This amount includes the present value of the future government subsidy, which was estimated by discounting the expected payments using the actuarial assumptions used to determine the PBOP liability at December 31, 2003. Also included in the $2.3 million estimate is a decrease in the assumed participation in NU's retiree health plan from 95 percent to 85 percent for future retirees, which reflects the expectation that the Medicare prescription benefit will produce insurer- sponsored health plans that are more financially attractive to future retirees. The per capita claims cost estimate was not changed. Management reduced the PBOP benefit obligation as of December 31, 2003 by $2.3 million and recorded this amount as an actuarial gain within unrecognized net loss/(gain) in the tables that follow. The $2.3 million actuarial gain will be amortized beginning in 2004 as a reduction to PBOP expense over the future working lifetime of employees covered under the plan (approximately 13 years). PBOP expense in 2004 will also reflect a lower interest cost due to the reduction in the December 31, 2003 benefit obligation.
Specific authoritative guidance on accounting for the effect of the Medicare federal subsidy on PBOP plans and amounts is pending from the FASB. When issued, that guidance could require WMECO to change the accounting described above and change the information reported herein.
PBOP Settlements, Curtailments and Special Termination Benefits: There were no settlements, curtailments or special termination benefits in 2003. In 2001, WMECO recorded PBOP special termination benefits expense of $0.1 million in connection with the VSP. This amount was recorded as a regulatory asset and collected through rates in 2002.
The following table represents information on the plans' benefit obligation, fair value of plan assets, and the respective plans' funded status:
----------------------------------------------------------------------------------------------------------
At December 31,
----------------------------------------------------------------------------------------------------------
Pension Benefits Postretirement Benefits
----------------------------------------------------------------------------------------------------------
(Millions of Dollars) 2003 2002 2003 2002
----------------------------------------------------------------------------------------------------------
Change in benefit obligation
Benefit obligation at beginning of year $(133.6) $(121.3) $(36.6) $(35.5)
Service cost (2.5) (2.2) (0.4) (0.4)
Interest cost (8.7) (8.7) (2.4) (2.6)
Medicare impact - - 2.3 -
Plan amendment - (1.1) - 2.1
Transfers 0.5 (0.2) - -
Actuarial loss (7.6) (8.2) (1.5) (3.8)
Benefits paid - excluding lump sum payments 8.1 8.1 2.7 3.6
----------------------------------------------------------------------------------------------------------
Benefit obligation at end of year $(143.8) $(133.6) $(35.9) $(36.6)
----------------------------------------------------------------------------------------------------------
Change in plan assets
Fair value of plan assets at beginning of year $ 162.4 $ 191.2 $ 13.3 $ 14.7
Actual return on plan assets 41.5 (20.9) 3.4 (1.2)
Employer contribution - - 3.4 3.4
Transfers (0.5) 0.2 - -
Benefits paid - excluding lump sum payments (8.1) (8.1) (2.7) (3.6)
----------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of year $ 195.3 $ 162.4 $ 17.4 $ 13.3
----------------------------------------------------------------------------------------------------------
Funded status at December 31 $ 51.5 $ 28.8 $(18.5) $(23.3)
Unrecognized transition (asset)/obligation (0.2) (0.5) 12.4 13.8
Unrecognized prior service cost 5.7 6.4 - -
Unrecognized net loss 18.4 32.8 6.1 10.0
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Prepaid benefit cost $ 75.4 $ 67.5 $ - $ 0.5
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The accumulated benefit obligation for the Pension Plan was $127.2 million and $116.3 million at December 31, 2003 and 2002, respectively.
The following actuarial assumptions were used in calculating the plans' year end funded status:
-------------------------------------------------------------------------------
At December 31,
-------------------------------------------------------------------------------
Balance Sheets Pension Benefits Postretirement Benefits
-------------------------------------------------------------------------------
2003 2002 2003 2002
-------------------------------------------------------------------------------
Discount rate 6.25% 6.75% 6.25% 6.75%
Compensation/progression rate 3.75% 4.00% N/A N/A
Health care cost trend rate N/A N/A 9.00% 10.00%
-------------------------------------------------------------------------------
|
The components of net periodic (income)/expense are as follows:
-----------------------------------------------------------------------------------------------------------------
For the Years Ended December 31,
-----------------------------------------------------------------------------------------------------------------
Pension Benefits Postretirement Benefits
-----------------------------------------------------------------------------------------------------------------
(Millions of Dollars) 2003 2002 2001 2003 2002 2001
-----------------------------------------------------------------------------------------------------------------
Service cost $ 2.5 $ 2.2 $ 1.9 $ 0.4 $ 0.4 $ 0.4
Interest cost 8.7 8.7 8.5 2.4 2.6 2.3
Expected return on plan assets (18.2) (19.9) (20.0) (1.3) (1.3) (1.4)
Amortization of unrecognized net
transition (asset)/obligation (0.2) (0.2) (0.2) 1.4 1.5 1.6
Amortization of prior service cost 0.7 0.7 0.6 - - -
Amortization of actuarial gain (1.4) (3.6) (4.5) - - -
Other amortization, net - - - 0.6 0.2 (0.4)
-----------------------------------------------------------------------------------------------------------------
Net periodic (income)/expense - before
settlements, curtailments and special
termination benefits (7.9) (12.1) (13.7) 3.5 3.4 2.5
-----------------------------------------------------------------------------------------------------------------
Settlement income - - (0.2) - - -
Curtailment income - (1.2) - - - -
Special termination benefits expense - - 0.5 - - 0.1
-----------------------------------------------------------------------------------------------------------------
Total - settlements, curtailments and special
termination benefits - (1.2) 0.3 - - 0.1
-----------------------------------------------------------------------------------------------------------------
Total - net periodic (income)/expense $ (7.9) $(13.3) $(13.4) $ 3.5 $ 3.4 $ 2.6
-----------------------------------------------------------------------------------------------------------------
|
For calculating pension and postretirement benefit income and expense amounts, the following assumptions were used:
-----------------------------------------------------------------------------------------
For the Years Ended December 31,
-----------------------------------------------------------------------------------------
Statements of Income Pension Benefits Postretirement Benefits
-----------------------------------------------------------------------------------------
2003 2002 2001 2003 2002 2001
-----------------------------------------------------------------------------------------
Discount rate 6.75% 7.25% 7.50% 6.75% 7.25% 7.50%
Expected long-term rate of return 8.75% 9.25% 9.50% 8.75% 9.25% 9.50%
Compensation/progression rate 4.00% 4.25% 4.50% N/A N/A N/A
-----------------------------------------------------------------------------------------
|
The following table represents the PBOP assumed health care cost trend rate for the next year and the assumed ultimate trend rate:
---------------------------------------------------------------
Year Following December 31,
---------------------------------------------------------------
2003 2002
---------------------------------------------------------------
Health care cost trend rate
assumed for next year 8.00% 9.00%
Rate to which health care cost
trend rate is assumed to
decline (the ultimate trend rate) 5.00% 5.00%
Year that the rate reaches the
ultimate trend rate 2007 2007
---------------------------------------------------------------
|
The annual per capita cost of covered health care benefits was assumed to decrease by one percentage point each year through 2007.
Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. The effect of changing the assumed health care cost trend rate by one percentage point in each year would have the following effects:
--------------------------------------------------------------------
One Percentage One Percentage
(Millions of Dollars) Point Increase Point Decrease
--------------------------------------------------------------------
Effect on total service and
interest cost components $0.1 $(0.7)
Effect on postretirement
benefit obligation $1.1 $(1.0)
--------------------------------------------------------------------
|
WMECO's investment strategy for its Pension Plan and PBOP Plan is to maximize the long-term rate of return on those plans' assets within an acceptable level of risk. The investment strategy establishes target allocations, which are regularly reviewed and periodically rebalanced. WMECO's expected long- term rates of return on Pension Plan assets and PBOP Plan assets are based on these target asset allocation assumptions and related expected long-term rates of return.
In developing its expected long-term rate of return assumptions for the Pension Plan and the PBOP Plan, WMECO also evaluated input from actuaries, consultants and economists as well as long-term inflation assumptions and WMECO's historical 20-year compounded return of approximately 11 percent. The Pension Plan's and PBOP Plan's target asset allocation assumptions and expected long-term rate of return assumptions by asset category are as follows:
-----------------------------------------------------------------------------------------------------------------
At December 31,
-----------------------------------------------------------------------------------------------------------------
Pension Benefits Postretirement Benefits
-----------------------------------------------------------------------------------------------------------------
2003 2002 2003 2002
-----------------------------------------------------------------------------------------------------------------
Target Assumed Target Assumed Target Assumed Target Assumed
Asset Rate of Asset Rate of Asset Rate of Asset Rate of
Asset Category Allocation Return Allocation Return Allocation Return Allocation Return
-----------------------------------------------------------------------------------------------------------------
Equity securities:
United States 45.00% 9.25% 45.00% 9.75% 55.00% 9.25% 55.00% 9.75%
Non-United States 14.00% 9.25% 14.00% 9.75% 11.00% 9.25% - -
Emerging markets 3.00% 10.25% 3.00% 10.75% 2.00% 10.25% - -
Private 8.00% 14.25% 8.00% 14.75% - - - -
Debt Securities:
Fixed income 20.00% 5.50% 20.00% 6.25% 27.00% 5.50% 45.00% 6.25%
High yield fixed
income 5.00% 7.50% 5.00% 7.50% 5.00% 7.50% - -
Real estate 5.00% 7.50% 5.00% 7.50% - - - -
-----------------------------------------------------------------------------------------------------------------
|
The actual asset allocations at December 31, 2003 and 2002, approximated these target asset allocations. The plans' actual weighted-average asset allocations by asset category are as follows:
--------------------------------------------------------------------------
At December 31,
--------------------------------------------------------------------------
Postretirement
Pension Benefits Benefits
--------------------------------------------------------------------------
Asset Category 2003 2002 2003 2002
--------------------------------------------------------------------------
Equity securities:
United States 47.00% 46.00% 59.00% 55.00%
Non-United States 18.00% 17.00% 12.00% -
Emerging markets 3.00% 3.00% 1.00% -
Private 3.00% 3.00% - -
Debt Securities:
Fixed income 19.00% 21.00% 25.00% 45.00%
High yield fixed
income 5.00% 5.00% 3.00% -
Real estate 5.00% 5.00% - -
-------------------------------------------------------------------------
Total 100.00% 100.00% 100.00% 100.00%
--------------------------------------------------------------------------
|
Currently, WMECO's policy is to annually fund an amount at least equal to that which will satisfy the requirements of the Employee Retirement Income Security Act and Internal Revenue Code.
WMECO does not expect to make any contributions to the Pension Plan in 2004 and expects to make $4 million in contributions to the PBOP Plan in 2004.
Postretirement plan assets for non-union employees are subject to federal income taxes.
VYNPC: On July 31, 2002, VYNPC consummated the sale of its nuclear generating plant to a subsidiary of Entergy Corporation (Entergy) for approximately $180 million. As part of the sale, Entergy assumed responsibility for decommissioning VYNPC's nuclear generating unit. On November 7, 2003, WMECO sold its 2.6 percent ownership interest in VYNPC. WMECO will continue to buy approximately 2.5 percent of the plant's output through March 2012 at a range of fixed prices.
A. RESTRUCTURING AND RATE MATTERS Transition Cost Reconciliations: On March 31, 2003, WMECO filed its 2002 transition cost reconciliation with the DTE. This filing reconciled the recovery of generation-related stranded costs for calendar year 2002 and included the renegotiated purchased power contract related to the Vermont Yankee nuclear unit.
On July 15, 2003, the DTE issued a final order on WMECO's 2001 transition cost reconciliation, which addressed WMECO's cost tracking mechanisms. As part of that order, the DTE directed WMECO to revise its 2002 annual transition cost reconciliation filing. The revised filing was submitted to the DTE on September 22, 2003. Hearings have been held, and the timing of a final decision from the DTE is uncertain. Management does not expect the outcome of this docket to have a material adverse impact on WMECO's net income or financial position.
B. ENVIRONMENTAL MATTERS General: WMECO is subject to environmental laws and regulations intended to mitigate or remove the effect of past operations and improve or maintain the quality of the environment. These laws and regulations require the removal or the remedy of the effect on the environment of the disposal or release of certain specified hazardous substances at current and former operating sites. As such, WMECO has an active environmental auditing and training program and believes that it is substantially in compliance with all enacted laws and regulations.
Environmental reserves are accrued using a probabilistic model approach when assessments indicate that it is probable that a liability has been incurred and an amount can be reasonably estimated. The probabilistic model approach estimates the liability based on the most likely action plan from a variety of available remediation options, ranging from no action to several different remedies ranging from establishing institutional controls to full site remediation and monitoring.
These estimates are subjective in nature as they take into consideration several different remediation options at each specific site. The reliability and precision of these estimates can be affected by several factors including new information concerning either the level of contamination at the site, recently enacted laws and regulations or a change in cost estimates due to certain economic factors.
The amounts recorded as environmental liabilities on the consolidated balance sheets represent management's best estimate of the liability for environmental costs and takes into consideration site assessment and remediation costs. Based on currently available information for estimated site assessment and remediation costs at December 31, 2003 and 2002, WMECO had $0.7 million and $0.8 million, respectively, recorded as environmental reserves. A reconciliation of the total amount reserved at December 31, 2003 and 2002 is as follows:
--------------------------------------------------------------------
(Millions of Dollars) For the Years Ended December 31,
--------------------------------------------------------------------
2003 2002
--------------------------------------------------------------------
Balance at beginning of year $ 0.8 $ 5.2
Additions and adjustments 0.3 0.2
Payments (0.4) (4.6)
--------------------------------------------------------------------
Balance at end of year $ 0.7 $ 0.8
--------------------------------------------------------------------
|
These liabilities are estimated on an undiscounted basis and do not assume that any amounts are recoverable from insurance companies or other third parties. The environmental reserve includes sites at different stages of discovery and remediation and does not include any unasserted claims. At December 31, 2003, there is one site for which there are unasserted claims; however, any related remediation costs are not probable or estimable at this time. WMECO's environmental liability also takes into account recurring costs of managing hazardous substances and pollutants, mandated expenditures to remediate previously contaminated sites and any other infrequent and non- recurring clean up costs.
WMECO currently has nine sites included in the environmental reserve. Of those nine sites, five sites are in the remediation or long-term monitoring phase and four sites have had site assessments completed.
In addition, capital expenditures related to environmental matters are expected to total approximately $1 million in aggregate for the years 2004 through 2008. These expenditures relate to environmental remediation programs.
MGP Sites: Manufactured gas plant (MGP) sites are sites that manufactured gas from coal and produced certain byproducts that may pose risk to human health and the environment. At December 31, 2003 and 2002, $0.1 million and $0.4 million, respectively, represent amounts for the site assessment and remediation of MGPs. WMECO currently has three MGP sites included in its environmental liability. Of the three MGP sites, one is currently undergoing remediation efforts with the other two MGP sites in the site assessment stage.
CERCLA Matters: The Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA) and its' amendments or state equivalents impose joint and several strict liabilities, regardless of fault, upon generators of hazardous substances resulting in removal and remediation costs and environmental damages. Liabilities under these laws can be material and in some instances may be imposed without regard to fault or for past acts that may have been lawful at the time they occurred. WMECO has one superfund site under CERCLA for which it has been notified that it is a potentially responsible party (PRP). For sites where there are other PRPs and WMECO is not managing the site assessment and remediation, the liability accrued represents WMECO's estimate of what it will need to pay to settle its obligations with respect to the site.
It is possible that new information or future developments could require a reassessment of the potential exposure to related environmental matters. As this information becomes available management will continue to assess the potential exposure and adjust the reserves as necessary.
WMECO does not have a regulatory recovery mechanism to recover environmental costs from its customers, and changes in WMECO's environmental reserves impact WMECO's earnings.
C. SPENT NUCLEAR FUEL DISPOSAL COSTS Under the Nuclear Waste Policy Act of 1982, WMECO must pay the DOE for the disposal of spent nuclear fuel and high-level radioactive waste. The DOE is responsible for the selection and development of repositories for, and the disposal of, spent nuclear fuel and high-level radioactive waste. For nuclear fuel used to generate electricity prior to April 7, 1983 (Prior Period Fuel), an accrual has been recorded for the full liability, and payment must be made prior to the first delivery of spent fuel to the DOE. Until such payment is made, the outstanding balance will continue to accrue interest at the 3-month treasury bill yield rate. At December 31, 2003 and 2002, fees due to the DOE for the disposal of Prior Period Fuel were $48.7 million and $48.2 million, respectively, including interest costs of $33.1 million and $32.6 million, respectively.
Fees for nuclear fuel burned on or after April 7, 1983, were billed currently to customers and were paid to the DOE on a quarterly basis. At December 31, 2003, WMECO's ownership share of Millstone has been sold, and WMECO is no longer responsible for fees relating to fuel burned at this facility since their sale.
D. NUCLEAR INSURANCE CONTINGENCIES In conjunction with the divestiture of Millstone in 2001, NU and WMECO terminated their nuclear insurance related to Millstone, and WMECO has no further exposure for potential assessments related to Millstone. However, through its continuing association with Nuclear Electric Insurance Limited (NEIL) and CYAPC, NU is subject to potential retrospective assessments totaling $0.8 million under its respective NEIL insurance policies.
E. LONG-TERM CONTRACTUAL ARRANGEMENTS VYNPC: Previously, under the terms of its agreement, WMECO paid its ownership (or entitlement) shares of costs, which included depreciation, O&M expenses, taxes, the estimated cost of decommissioning, and a return on invested capital to VYNPC and recorded these costs as purchased-power expenses. On July 31, 2002, VYNPC consummated the sale of its nuclear generating unit to a subsidiary of Entergy for approximately $180 million. Under the terms of the sale, WMECO will continue to buy approximately 2.5 percent of the plant's output through March 2012 at a range of fixed prices. The total cost of purchases under contracts with VYNPC amounted to $4.6 million in 2003, $4.3 million in 2002 and $4.1 million in 2001.
Electricity Procurement Contracts: WMECO has entered into an arrangement for the purchase of electricity. The total cost of purchases under this arrangement amounted to $2.8 million in 2003, $2.5 million in 2002 and $14.5 million in 2001. These amounts relate to IPP contracts and do not include contractual commitments related to WMECO's standard offer and default service.
Hydro-Quebec: Along with other New England utilities, WMECO has entered into an agreement to support transmission and terminal facilities to import electricity from the Hydro-Quebec system in Canada. WMECO is obligated to pay, over a 30-year period ending in 2020, its proportionate share of the annual O&M expenses and capital costs of those facilities.
Estimated Future Annual Costs: The estimated future annual costs of WMECO's significant long-term contractual arrangements are as follows:
------------------------------------------------------------------------------- (Millions of Dollars) 2004 2005 2006 2007 2008 Thereafter ------------------------------------------------------------------------------- VYNPC $4.6 $4.3 $4.5 $4.3 $4.4 $15.2 Electricity Procurement Contracts 2.4 2.4 2.4 2.4 2.4 4.8 Hydro-Quebec 2.9 2.8 2.6 2.4 2.3 27.6 ------------------------------------------------------------------------------- Totals $9.9 $9.5 $9.5 $9.1 $9.1 $47.6 ------------------------------------------------------------------------------- |
F. NUCLEAR DECOMMISSIONING AND PLANT CLOSURE COSTS In conjunction with the Millstone and VYNPC nuclear generation asset divestitures, the applicable liabilities and nuclear decommissioning trusts were transferred to the purchasers, and the purchasers agreed to assume responsibility for decommissioning their respective units.
WMECO still has significant decommissioning and plant closure cost obligations to the Yankee Companies that own the Yankee Atomic, Connecticut Yankee (CY) and Maine Yankee nuclear power plants. Each plant has been shut down and is undergoing decommissioning. The Yankee Companies collect decommissioning and closure costs through wholesale FERC-approved rates charged under power purchase agreements to WMECO. WMECO in turn passes these costs on to its customers through state regulatory commission-approved retail rates. A portion of the decommissioning and closure costs have already been collected, but a substantial portion related to the decommissioning of CY has not yet been filed at and approved for collection by the FERC.
During 2002, WMECO 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. WMECO's share of this increase is $33.3 million. Following FERC rate cases by the Yankee Companies, WMECO expects to recover the higher decommissioning costs from its retail customers.
In June 2003, CYAPC notified NU that it had terminated its contract with Bechtel Power Corporation (Bechtel) for the decommissioning of the CY nuclear power plant. CYAPC terminated the contract based on its determination that Bechtel's decommissioning work has been incomplete and untimely and that Bechtel refused to perform the remaining decommissioning work. Bechtel has filed a counterclaim against CYAPC asserting a number of claims and seeking a variety of remedies, including monetary and punitive damages and the rescission of the contract. Bechtel has amended its complaint to add claims for wrongful termination.
In November 2003, CYAPC prepared an updated estimate of the cost of decommissioning its nuclear unit. WMECO's aggregate share of the estimated increased cost primarily related to the termination of Bechtel, is $32.5 million.
CYAPC is seeking recovery of additional decommissioning costs and other damages from Bechtel and, if necessary, its surety. In pursuing this recovery through pending litigation, CYAPC is also exploring options to structure an appropriate rate application to be filed with the FERC, with any resulting adjustments being charged to the owners of the nuclear unit, including WMECO. The timing, amount and outcome of these filings cannot be predicted at this time.
WMECO 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 WMECO's customers, 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 FERC does not allow these costs to be recovered in wholesale rates, WMECO would expect the state regulatory commissions to disallow these costs in retail rates as well.
At December 31, 2003 and 2002, WMECO's remaining estimated obligations for decommissioning and closure costs for the shut down units owned by CYAPC, YAEC and MYAPC were $86.9 million and $63.8 million, respectively.
The following methods and assumptions were used to estimate the fair value of each of the following financial instruments:
Long-Term Debt and Rate Reduction Bonds: The fair value of WMECO's fixed- rate securities is based upon the quoted market price for those issues or similar issues. Adjustable rate securities are assumed to have a fair value equal to their carrying value. The carrying amounts of WMECO's financial instruments and the estimated fair values are as follows:
---------------------------------------------------------------------
At December 31, 2003
---------------------------------------------------------------------
(Millions of Dollars) Carrying Amount Fair Value
---------------------------------------------------------------------
Long-term debt -
Other long-term debt $157.5 $159.9
Rate reduction bonds 133.0 145.9
---------------------------------------------------------------------
---------------------------------------------------------------------
At December 31, 2002
---------------------------------------------------------------------
(Millions of Dollars) Carrying Amount Fair Value
---------------------------------------------------------------------
Long-term debt -
Other long-term debt $102.0 $104.3
Rate reduction bonds 142.7 159.2
---------------------------------------------------------------------
|
Other long-term debt includes $48.7 million and $48.2 million of fees and interest due for spent nuclear fuel disposal costs at December 31, 2003 and 2002, respectively.
Other Financial Instruments: The carrying value of financial instruments included in current assets and current liabilities, approximates their fair value.
WMECO has entered into lease agreements for the use of data processing and office equipment, vehicles, and office space. The provisions of these lease agreements generally provide for renewal options.
Capital lease rental payments charged to operating expense were zero in 2003 and 2002, and $1.9 million in 2001. Interest included in capital lease rental payments was zero in 2003 and 2002, and $0.7 million in 2001. Operating lease rental payments charged to expense were $2.5 million in 2003, $2.3 million in 2002, and $2.5 million in 2001.
Future minimum rental payments excluding executory costs, such as property taxes, state use taxes, insurance, and maintenance, under long-term noncancelable operating leases, at December 31, 2003 are as follows:
----------------------------------------------------------- (Millions of Dollars) Operating Year Leases ----------------------------------------------------------- 2004 $ 3.3 2005 3.2 2006 2.9 2007 2.7 2008 2.5 Thereafter 9.0 ----------------------------------------------------------- Future minimum lease payments $23.6 ----------------------------------------------------------- |
The accumulated balance for each other comprehensive income/(loss) item is as follows:
---------------------------------------------------------------------------
Current
December 31, Period December 31,
(Millions of Dollars) 2002 Change 2003
---------------------------------------------------------------------------
Unrealized
gains/(losses)
on securities $ - $ - $ -
Minimum supplemental
executive retirement
pension liability
adjustments (0.1) - (0.1)
---------------------------------------------------------------------------
Accumulated other
comprehensive
loss $(0.1) $ - $(0.1)
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Current
December 31, Period December 31,
(Millions of Dollars) 2001 Change 2002
---------------------------------------------------------------------------
Unrealized
gains/(losses)
on securities $0.1 $(0.1) $ -
Minimum supplemental
executive retirement
pension liability
adjustments - (0.1) (0.1)
---------------------------------------------------------------------------
Accumulated other
comprehensive
income/(loss) $0.1 $(0.2) $(0.1)
---------------------------------------------------------------------------
|
The changes in the components of other comprehensive income/(loss) are reported net of the following income tax effects:
--------------------------------------------------------------------------- (Millions of Dollars) 2003 2002 2001 --------------------------------------------------------------------------- Unrealized gains on securities $ - $0.1 $0.1 Minimum supplemental executive retirement pension liability adjustments - - - --------------------------------------------------------------------------- Accumulated other comprehensive income $ - $0.1 $0.1 --------------------------------------------------------------------------- |
Details of long-term debt outstanding are as follows:
---------------------------------------------------------------------------
At December 31, 2003 2002
---------------------------------------------------------------------------
(Millions of Dollars)
Pollution Control Notes:
Tax Exempt 1993 Series A,
5.85% due 2028 $ 53.8 $ 53.8
Other:
Taxable Senior Series A,
5.00% due 2013 55.0 -
---------------------------------------------------------------------------
Total Pollution Control Notes
and Other 108.8 53.8
---------------------------------------------------------------------------
Fees and interest due for spent
nuclear fuel disposal costs 48.7 48.2
---------------------------------------------------------------------------
Total pollution control notes and fees
and interest for spent nuclear fuel
disposal costs 157.5 102.0
---------------------------------------------------------------------------
Less amounts due within one year - -
Unamortized premium and
discount, net (0.3) -
---------------------------------------------------------------------------
Long-term debt $157.2 $102.0
---------------------------------------------------------------------------
|
The components of the federal and state income tax provisions were charged/(credited) to operations as follows:
----------------------------------------------------------------
For the Years Ended
December 31, 2003 2002 2001
----------------------------------------------------------------
(Millions of Dollars)
Current income taxes:
Federal $23.4 $27.9 $ 0.3
State 4.4 5.8 1.0
---------------------------------------------------------------
Total current 27.8 33.7 1.3
----------------------------------------------------------------
Deferred income taxes, net:
Federal (12.0) (13.5) 5.3
State (2.0) 0.1 0.6
----------------------------------------------------------------
Total deferred (14.0) (13.4) 5.9
----------------------------------------------------------------
Investment tax credits, net (0.3) (13.5) (0.6)
----------------------------------------------------------------
Total income tax expense $13.5 $ 6.8 $ 6.6
----------------------------------------------------------------
|
Deferred income taxes are comprised of the tax effects of temporary differences as follows:
----------------------------------------------------------------
For the Years Ended
December 31, 2003 2002 2001
----------------------------------------------------------------
(Millions of Dollars)
Depreciation $ 1.7 $ 1.5 $ (0.6)
Net regulatory deferral (13.7) (6.0) 4.1
Sale of generation assets - (2.0) (30.5)
Pension accruals 1.5 2.6 1.0
Contract termination costs,
net of amortization (4.4) (3.6) 30.6
Other 0.9 (5.9) 1.3
----------------------------------------------------------------
Deferred income taxes, net $(14.0) $(13.4) $ 5.9
----------------------------------------------------------------
|
A reconciliation between income tax expense and the expected tax expense at the statutory rate is as follows:
----------------------------------------------------------------
For the Years Ended
December 31, 2003 2002 2001
----------------------------------------------------------------
(Millions of Dollars)
Expected federal income tax $10.4 $ 15.5 $ 7.5
Tax effect of differences:
Depreciation 0.6 0.5 1.9
Amortization of
regulatory assets 1.0 - -
Investment tax credit
amortization (0.3) (13.5) (0.6)
State income taxes,
net of federal benefit 1.6 3.8 1.0
Other, net 0.2 0.5 (3.2)
-----------------------------------------------------------------
Total income tax expense $13.5 $ 6.8 $ 6.6
-----------------------------------------------------------------
|
NU is organized between the Utility Group and NU Enterprises based on each segments' regulatory environment or lack thereof. WMECO is included in the Utility Group segment of NU and has no other reportable segments.
------------------------------------------------------------------------------- 2003 March 31, June 30, September 30, December 31, ------------------------------------------------------------------------------- Operating Revenues $104,786 $89,665 $103,365 $93,362 Operating Income $ 14,694 $ 7,561 $ 11,592 $ 6,547 Net Income $ 6,068 $ 2,586 $ 5,195 $ 2,363 ------------------------------------------------------------------------------- 2002 ------------------------------------------------------------------------------- Operating Revenues $ 96,005 $87,191 $ 95,684 $90,607 Operating Income $ 15,695 $10,678 $ 12,524 $20,786 Net Income $ 6,890 $15,322 $ 4,730 $10,740 ------------------------------------------------------------------------------- |
---------------------------------------------------------------------------------------------------------------------------- Selected Consolidated Financial Data (Unaudited) ---------------------------------------------------------------------------------------------------------------------------- (Thousands of Dollars) 2003 2002 2001 2000 1999 ---------------------------------------------------------------------------------------------------------------------------- Operating Revenues $391,178 $369,487 $478,869 $ 513,678 $ 414,231 Net Income 16,212 37,682 14,968 35,268 2,887 Cash Dividends on Common Stock 22,011 16,009 22,000 12,002 - Gross Property, Plant and Equipment (b) 625,574 602,013 583,183 1,153,514 1,216,015 Total Assets (c) 863,564 853,646 852,662 1,047,818 1,253,604 Rate Reduction Bonds 132,960 142,742 152,317 - - Long-Term Debt (d) 157,202 101,991 101,170 199,425 290,279 Preferred Stock Not Subject to Mandatory Redemption - - - 20,000 20,000 Preferred Stock Subject to Mandatory Redemption (d) - - - 16,500 18,000 Obligations Under Capital Leases (d) 57 87 110 26,921 29,972 ----------------------------------------------------------------------------------------------------------------------------- |
-----------------------------------------------------------------------------------------------------------------------------
Consolidated Statistics (Unaudited)
-----------------------------------------------------------------------------------------------------------------------------
2003 2002 2001 2000 1999
-----------------------------------------------------------------------------------------------------------------------------
Revenues: (Thousands)
Residential $165,871 $158,060 $174,899 $148,735 $146,728
Commercial 133,122 127,030 157,722 135,703 131,655
Industrial 63,990 60,782 83,752 79,886 75,220
Other Utilities 14,347 9,354 38,893 123,874 34,626
Streetlighting and Railroads 4,817 5,071 5,306 5,106 4,831
Miscellaneous 9,031 9,190 18,297 20,374 21,171
-----------------------------------------------------------------------------------------------------------------------------
Total $391,178 $369,487 $478,869 $513,678 $414,231
-----------------------------------------------------------------------------------------------------------------------------
Sales: (kWh - Millions)
Residential 1,521 1,459 1,389 1,382 1,394
Commercial 1,567 1,523 1,495 1,465 1,468
Industrial 909 912 940 1,010 999
Other Utilities 255 180 864 3,396 769
Streetlighting and Railroads 26 28 24 25 24
-----------------------------------------------------------------------------------------------------------------------------
Total 4,278 4,102 4,712 7,278 4,654
-----------------------------------------------------------------------------------------------------------------------------
Customers: (Average)
Residential 185,202 183,662 182,688 181,316 180,807
Commercial 18,838 18,516 15,996 15,593 15,745
Industrial 897 910 808 801 807
Other 693 672 674 662 653
-----------------------------------------------------------------------------------------------------------------------------
Total 205,630 203,760 200,166 198,372 198,012
-----------------------------------------------------------------------------------------------------------------------------
Average Annual Use Per
Residential Customer (kWh) 8,214 7,921 7,476 7,371 7,423
-----------------------------------------------------------------------------------------------------------------------------
Average Annual Bill Per
Residential Customer $895.33 $857.84 $941.23 $793.12 $780.90
-----------------------------------------------------------------------------------------------------------------------------
Average Revenue Per kWh:
Residential 10.90 cents 10.83 cents 12.59 cents 10.76 cents 10.52 cents
Commercial 8.50 8.34 10.55 9.26 8.97
Industrial 7.04 6.66 8.91 7.91 7.53
-----------------------------------------------------------------------------------------------------------------------------
Employees 408 400 405 406 482
=============================================================================================================================
|
(a) Certain reclassifications of prior years' data have been made to conform
with the current year's presentation.
(b) Amount includes construction work in progress.
(c) Total assets were not adjusted for cost of removal prior to 2002.
(d) Includes portions due within one year.
Exhibit 10.9
Execution Copy
1996 AMENDATORY AGREEMENT
This Agreement, dated as of the 4th day of December, 1996, is entered into
by and between Connecticut Yankee Atomic Power Company ("Connecticut Yankee" or
"Seller") and The Connecticut Light and Power Company ("Purchaser").
For good and valuable consideration, the receipt of which is hereby
acknowledged, it is agreed as follows:
Connecticut Yankee was organized in 1962 to provide for the supply of
power to its sponsoring utility companies, including the Purchaser
(collectively the "Purchasers"). It constructed a nuclear electric generating
unit, having a net capability of approximately 582 megawatts electric (the
"Unit") at a site in Haddam Neck, Connecticut. Connecticut Yankee was issued
a full-term, Facility Operating License for the Unit by the Nuclear Regulatory
Commission (which, together with any successor agencies, is hereafter called
the "NRC"), which license is now stated to expire on June 29, 2007. The Unit
has been in commercial operation since January 1, 1968.
The Unit was conceived to supply economic power on a cost of service
formula basis to the Purchasers. Connecticut Yankee and the Purchaser are
arties to a Power Contract dated as of July 1, 1964 ("Initial Power Contract").
Pursuant to the Initial Power Contract and other similar contracts
(collectively, the "Initial Power Contracts") between Connecticut Yankee and
the other Purchasers, Connecticut Yankee contracted to supply to the Purchasers
all of the capacity and electric energy available from the Unit for a term of
thirty (30) years following January 1, 1968.
Connecticut Yankee an the Purchaser are also parties to an
Additional Power Contract, dated as of April 30, 1984 ("Additional Power
Contract"). The Additional Power Contract and other similar contracts
(collectively, the "Additional Power Contracts") between Connecticut Yankee
and the other Purchasers, Connecticut Yankee contracted to supply to the
Purchasers all of the capacity and electric energy available from the Unit
for a term of thirty (30) years following January 1, 1968.
Connecticut Yankee and the Purchaser are also parties to an
Additional Power Contract, dated as of April 30, 1984 ("Additional Power
Contract"). The Additional Power Contract and other similar contracts
(collectively, the "Additional Power Contracts") between Connecticut Yankee
and the other Purchasers provide for an operative term stated to commence
on January 1, 1998 (when the Initial Power Contracts terminate) and extending
until a date (the "End of Term Date") which is 30 days after the later of the
date on which the last of the financial obligations of Connecticut Yankee has
been extinguished or the date on which Connecticut Yankee is finally relieved
of any obligations under the last of the licenses (operating or possessory)
which it holds, or hereafter receives, from the NRC with respect to the Unit.
The Additional Power Contracts also provide, in the event of their earlier
cancellation, for the survival of the decommissioning cost obligation and for
the applicable provisions thereof to remain in effect to permit final billings
of costs incurred prior to such cancellation.
Pursuant to the Power Contract and the Additional Power Contract, the
Purchaser is entitled and obligated to take its entitlement percentage of the
capacity and net electrical output of the Unit during the service life of the
Unit and is obligated to pay therefore monthly its entitlement percentage of
Connecticut Yankee's cost of service, including decommissioning costs, whether
or not the Unit is operated.
Connecticut Yankee and the Purchaser are also parties to a 1987
Supplementary Power Contract, dated as of April 1, 1987 ("1987 Supplementary
Power Contract"). The 1987 Supplementary Power Contract and other similar
contracts (collectively, the "1987 Supplementary Power Contracts") between
Connecticut Yankee and the other Purchasers restate and supersede earlier
Supplementary Power Contracts and Agreements Amending Supplementary Power
Contracts between Connecticut Yankee and the Purchasers. Pursuant to the
1987 Supplementary Power Contracts, the Purchasers make monthly certain
supplementary payments to Connecticut Yankee during the terms of the Initial
Power Contracts and Additional Power Contracts.
On December 4, 1996, the board of directors of Connecticut Yankee,
after conducting a thorough review of the economics of continued
operation of the Unit for the remainder of the economics of continued
operation of the Unit for the remainder of the term of the Facility
Operating License for the Unit in light of other alternatives available
to Connecticut Yankee and the Purchasers, determined that the Unit
should be permanently shut down effective December 4, 1996. The
Purchaser concurs in that decision.
As a consequence of the shutdown decision, Connecticut Yankee and
the Purchaser propose at this time to amend the 1987 Supplementary Power
Contract and Additional Power Contract in various respects in order to
clarify and confirm provisions for the recovery under said contracts of
the full costs previously incurred by Connecticut Yankee in providing
power from the Unit during its useful life and of all costs of
decommissioning the Unit, including the costs of maintaining the Unit
in a safe condition following the shutdown and prior to its
decontamination and dismantlement.
Connecticut Yankee and each of the other Purchasers are entering
into agreements which are identical to this Agreement except for
necessary changes in the names of the parties.
protect the Unit, to maintain in effect certain insurance and to prepare for
and implement the decommissioning of the Unit in accordance with applicable
aws and regulations. Consistent with public safety, Connecticut Yankee shall
use its best efforts to accomplish the shutdown of the Unit, the protection
and any necessary maintenance of the Unit after shutdown and the
decommissioning of the Unit in a cost-effective manner and shall use its best
efforts to ensure that any required storage and disposal of the nuclear fuel
remaining in the reactor at shutdown and all spent nuclear fuel or other
radioactive materials resulting from operating of the Unit are accomplished
consistent with public health and safety considerations and at the lowest
practicable cost. The Purchaser reconfirms its obligations under its Initial
Power Contract, Additional Power Contract and 1987 Supplementary Power Contract
to pay its entitlement percentage of Connecticut Yankee's costs as deferred
payment in connection with the capacity and net electrical output of the Unit
previously delivered by Connecticut Yankee and agrees that the decision to
shut down the Unit described in Section 1 hereof does not give rise to any
cancellation right under Section 9 of the Initial Power Contract or Section 10
of the Additional Power Contract.
Except as expressly modified by this Agreement, the provisions of the
Additional Power Contract and the 1987 Supplementary Power Contract remain in
full force and effect, recognizing that the mutually accepted decision to shut
down the Unit renders moot those provisions which by their terms relate solely
to continuing operation of the Unit.
A. Section 2 of the Additional Power Contract is hereby amended by
deleting the first two paragraphs thereof and by inserting in lieu thereof
the following.
This contract shall become effective upon receipt by the Purchaser of notice that Connecticut Yankee has entered into Additional Power Contracts, as contemplated by Section 1 above, with each of the other Purchasers. The operative term of this contract shall commence on such date as may be authorized by the FERC as may be authorized by the FERC and shall terminate on the date (the "End of Term Date") which is the later to occur of (i) 30 days after the date on which the last of the financial obligations of Connecticut Yankee which constitute elements of the payment calculated pursuant to Section 7 of this contract has been extinguished by Connecticut Yankee, or (ii) 30 days after the date on which Connecticut Yankee is finally relieved of all obligations under the last of any licenses (operating and/or possessory) which it now holds from, or which may hereafter be issued to it by, the NRC with respect to the Unit under applicable provisions of the Atomic Energy Act of 1954, as amended from time to time (the "Act").
B. The second paragraph of Section 4 of the Additional Power Contract is
amended by deleting the phrase "Second Supplementary Power Contracts" wherever
it appears and inserting in lieu thereof the phrase "1987 Supplementary Power
Contracts".
C. The first paragraph of Section 7 of the Additional Power Contract is
amended to read as follows:
With respect to each month commencing on or after the commencement of the operative term of this contract, whether or not this contract continues fully or partially in effect, the Purchaser will pay Connecticut Yankee as deferred payment for the capacity and output of the Unit provided to the Purchaser by Connecticut Yankee prior to the permanent shutdown of the Unit on December 4, 1996, to the extent not otherwise paid in accordance with the Power Contract, but without duplication:
D. The eighth paragraph of Section 7 of the Additional Power Contract is
amended by changing the period at the end to a comma and inserting:
, but including for purposes of this contract:
(i) with respect to each month until the commencement of
decommissioning of the Unit, the Purchaser's entitlement
percentage of all expenses related to the storage or disposal
of nuclear fuel or other radioactive materials, and all expenses
related to protection and maintenance of the Unit during such
period, including to the extent applicable all of the various
sorts of expenses included in the definition of "Decommissioning
Expenses", to the extent incurred during the period prior to the
commencement of decommissioning;
(ii) with respect to each month until expenses associated with
disposal of pre-April 7, 1983 spent nuclear fuel have been fully
covered by amounts which have been collected from Purchasers
and paid to a segregated fund as contemplated by Section 8 of
the 1987 Supplementary Power Contract, dated as of April 1,
1987, between Connecticut Yankee and the Purchaser, as amended
(the "1987 Contract"), the Purchaser's entitlement percentage
of previously uncollected expenses associated with disposal of
such prior spent nuclear fuel, as determined in accordance with
Section 10 of the 1987 Contract; and
(iii) with respect to each month until End of License Term, the
Purchaser's entitlement percentage of monthly amortization of
(a) the amount of any unamortized deferred expenses, as
permitted from time to time by the Federal Energy Regulatory
Commission or its successor agency, plus (b) the remaining
unamortized amount of Connecticut Yankee's investment in plant,
nuclear fuel and materials and supplies and other assets.
Such amortization shall be accrued at a rate sufficient to
amortize fully such unamortized deferred expenses and
Connecticut Yankee's investments in plant, nuclear fuel and
materials and supplies or other assets over a period
extending to June 29, 2007, provided, that if during any
calendar month ending on or before December 31, 2000 either of
the following events shall occur: (a) Connecticut Yankee
shall become insolvent or (b) Connecticut Yankee shall be
unable, from available cash or other sources, to meet when
due during such month its obligations to pay principal,
interest, premium (if any) or other less with respect to any
of its indebtedness of money borrowed, then Connecticut Yankee
may adjust upward the accrual for amortization of the
unrecovered investment for such month to an amount
not exceeding the applicable maximum level specified in
Appendix A hereto, provided that concurrently therewith the net
Unit investment shall be reduced by an amount equal to the
amount of such adjustment.
As used herein, "End of License Term" means June 29, 2007 or such
later date as may be fixed, by amendment to the NRC Facility Operating License
for the Unit, as the end of the term of the Facility Operating License.
E. The definitions in Section 7 of the Additional Power Contract
and in Section 3 of the 1987 Supplementary Power Contract of "Total
Decommissioning Costs" and "Decommissioning Expenses" are hereby amended
to read as follows:
"Total Decommissioning Costs" for any month shall mean the sum of (x)
an amount equal to all accruals in such month to any reserve, as from
time to time established by Connecticut Yankee and approved by its
board of directors, to provide for the ultimate payment of the
Decommissioning Expenses of the Unit, plus (y), during the
Decommissioning Period, the Decommissioning Expenses for the month,
to the extent such Decommissioning Expenses are not paid with funds
from such reserve, plus (z) Decommissioning Tax Liability for such
month. It is understood (i) that funds received pursuant to clause
(x) may be held by Connecticut Yankee or by an independent trust or
other separate fund, as determined by said board of directors, (ii)
that, upon compliance with applicable regulatory requirements, the
amount, custody and/or timing of such accruals may from time to time
during the term hereof be modified by said board of directors
in its discretion or to comply with applicable statutory or
regulatory requirements or to reflect changes in the amount, custody
or timing of anticipated Decommissioning Expenses, and (iii) that the
use of the term "to decommission" herein encompasses compliance
with all requirements of the NRC for permanent cessation of operation
of a nuclear facility and any other activities reasonably related
thereto, including provision for the interim storage of spent nuclear
fuel.
"Decommissioning Expenses" shall include all expenses of decommissioning the Unit, and all expenses relating to ownership and protection of the Unit during the Decommissioning Period, and shall also include the following:
(1) All costs and expenses of any NRC-approved method of removing
the Unit from service, including without limitation:
dismantling, mothballing and entombment of the Unit; removing
nuclear fuel and other radioactive material to temporary and/or
permanent storage sites; construction, operation, maintenance
and dismantling of a spent fuel storage facility;
decontaminating, restoring and supervising the site; and any
costs and expenses incurred in connection with proceedings
before governmental authorities relating to any authorization
to decommission the Unit or remove the Unit from service;
(2) All costs of labor and services, whether directly or indirectly incurred, including without limitation, services of foremen, inspectors, supervisors, surveyors, engineers, security personnel, counsel and accountants, performed or rendered in connection with the decommissioning of the Unit and the removal of the Unit from service, and all costs of materials, supplies, machinery, construction equipment and apparatus acquired or used (including rental charges for machinery, equipment or apparatus hired) for or in connection with the decommissioning of the Unit and the removal of the Unit from service, and all administrative costs, including services of counsel and financial advisers of any applicable independent trust or other separate fund; it being understood that any amount, exclusive of proceeds of insurance, realized by Connecticut Yankee as salvage on any machinery, construction equipment and apparatus, the cost of which was charged to Decommissioning Expense, shall be treated as a reduction of the amounts otherwise chargeable on account of the costs of decommissioning of the Unit; and
(3) All overhead costs applicable to the Unit during the Decommissioning Period, or accrued during such period, including without limiting the generality of the foregoing, taxes (other than taxes on or in respect of income), charges, license fees, excise and assessments, casualties, health care costs, pension benefits and other employee benefits, surety bond premiums and insurance premiums.
F. Section 7 of the Additional Power Contract and Section 3 of the 1987
Supplementary Power Contract are each hereby amended by adding the following
new paragraph after the definition of "Decommissioning Tax Liability":
"Decommissioning Period" shall mean the period commencing with the notification by Connecticut Yankee to the NRC of a decision of the board of directors of Connecticut Yankee to cease permanently the operation of the Unit for the purpose of producing electric energy and ending with the date when Connecticut Yankee has completed the decommissioning of the Unit and the restoration of the site and has been relieved of all its obligations under the last of any licenses issued to it by the NRC.
G. The first sentence of Section 8 of the Additional Power
Contract is hereby amended to read as follows:
Connecticut Yankee will bill the Purchaser, no later than ten (10) days after the end of any month, for all amounts payable by the Purchaser with respect to such particular month pursuant to Section 7 hereof.
H. Section 8 of the Additional Power Contract and Section
4 of the 1987 Supplementary Power Contract are each amended to
delete the name "The Connecticut Bank and Trust Company, National
Association" and substitute "Fleet National Bank".
I. Section 5 of the 1987 Supplementary Power Contract is
amended to read as follows:
J. Section 10 of the Additional Power Contract is amended
to read as follows:
(i) the Unit is damaged to the extent of being completely or substantially completely destroyed, or
(ii) the Unit is taken by exercise of the right of eminent domain or a similar right or power,
then and in any such case, the Purchaser may cancel the provisions of this contract, except that in all cases other than those described in clause (ii) above, the Purchaser shall be obligated to continue to make the payments of Total Decommissioning Costs and the other payments required by Section 7 and the provisions of that Section and the related provisions of this contract shall remain in full force and effect until the End of Term Date, it being recognized that the costs which Purchaser is required to pay pursuant to Section 7 represent deferred payments in connection with power heretofore delivered by Connecticut Yankee hereunder. Such cancellation shall be effected by written notice given by the Purchaser to Connecticut Yankee. In the event of such cancellation, all continuing obligations of the parties hereunder as to subsequently incurred costs of Connecticut Yankee other than the obligations of the Purchaser to continue to make the payments required by Section 7 shall cease forthwith. Notwithstanding the foregoing, the applicable provisions of this contract shall continue in effect after the cancellation hereof to the extent necessary to permit final billings and adjustments hereunder with respect to obligations incurred through the date of cancellation and the collection thereof. Any dispute as to the Purchaser's right to cancel this contract pursuant to the foregoing provisions shall be referred to arbitration in accordance with the provisions of Section 13.
Notwithstanding anything in this contract elsewhere contained, the Purchaser may cancel this contract or be relieved of its obligations to make payments hereunder only as provided in the next preceding paragraph of this Section 10. Further, if for reasons beyond Connecticut Yankee's reasonable control, deliveries are not made as contemplated by this contract, Connecticut Yankee shall have no liability to the Purchaser on account of such non-delivery.
K. Section 2 of the 1987 Supplementary Power Agreement is amended to change the date in the definitions of "operating expenses" and "M" from May 26, 2004" to "June 29, 2007".
notice that Connecticut Yankee has entered into 1996 Amendatory Agreements,
as contemplated by Section 1 hereof, with each of the other Purchasers.
accordance with and controlled by the laws of the State of Connecticut.
other communication from one party to the other relating to this Agreement,
or the rights, obligations or performance of the parties hereunder, shall be
in writing and shall be effective upon delivery to the other party. Any such
communication shall be considered as duly delivered when mailed to the
respective post office address of the other party shown following the
signatures of such other party hereto, or such other post office address as
may be designated by written notice given in the manner as provided in this
Section.
This Agreement is the corporate act and obligation of the parties hereto.
This Agreement may be executed in any number of counterparts and each
executed counterpart shall have the same force and effect as an original
instrument and as if all the parties to all of the counterparts had signed the
same instrument. Any signature page of this Agreement may be detached from any
counterpart without impairing the legal effect of any signatures thereon, and
may be attached to another counterpart of this Agreement identical in form
hereto but having attached to it one or more signature pages.
IN WITNESS WHEREOF, the parties have executed this Amendatory Agreement
by their respective duly authorized officers as of the day and year first
named above.
CONNECTICUT YANKEE ATOMIC POWER
COMPANY
By _______________________________________
Its
Address:
THE CONNECTICUT LIGHT AND POWER
COMPANY
By ______________________________________
Its
Address:
Appendix A to 1996 Amendatory Agreement
If the event occurs during the twelve
months ending: Maximum Amortization Accrual:
December 31, 1997 $100,000,000.00
December 31, 1998 $ 80,000,000.00
December 31, 1999 $ 40,000,000.00
December 31, 2000 $ 20,000,000.00
|
Exhibit 10.9.1
First Supplement
to
1996 Amendatory Agreement
This First Supplement, dated as of February 10, 1997, amends the 1996
Amendatory Agreement, dated as of December 4, 1996, between these parties and
is entered into by Connecticut Yankee Atomic Power Company ("Connecticut
Yankee") and Central Maine Power Company ("Purchaser").
WHEREAS, terms defined in said 1996 Amendatory Agreement are used herein
with the meanings there provided; and
WHEREAS, Connecticut Yankee and each of its Purchasers entered into
agreements substantially identical to said 1996 Amendatory Agreement to effect
certain clarifications in their contractual relationships necessitated by the
decision to permanently shut down Connecticut Yankee's generating unit; and
WHEREAS, Connecticut Yankee has detected an unintended omission in one
section of said 1996 Amendatory Agreement which renders the section meaningless
and should be corrected and, concurrently herewith, is entering into agreements
with each of its Purchasers substantially identical to this supplement.
NOW, THEREFORE, for good and valuable consideration, the receipt of which
is hereby acknowledged, it is agreed as follows:
1. Clause C of Section 3 of the 1996 Amendatory Agreement is hereby
amended to insert the following after the phrase "but without duplication:"
(a) the Total Decommissioning Costs for the month with respect to the Unit, plus (b) Connecticut Yankee's total operating expenses or the month with respect to the Unit, plus (c) an amount equal to one-twelfth of the composite percentage for such month of the net Unit investment as most recently determined in accordance with this Section 7.
2. This First Supplement shall become effective upon receipt by the
Purchaser of notice that Connecticut Yankee has entered into identical First
Supplements to the 1996 Amendatory Agreements with each of the Purchasers.
IN WITNESS WHEREOF, the parties have executed this First Supplement to the
1996 Amendatory Agreement by this respective duly authorized officers as of the
day and year first named above.
CONNECTICUT YANKEE ATOMIC POWER
COMPANY
By ________________________________________
Its
Address: P.O. Box 270
Hartford, CT 06101
CENTRAL MAINE POWER COMPANY
By ________________________________________
Its
Address: 83 Edison Drive
Augusta, Maine 04336
Exhibit 10.11.5
AMENDMENT NO. 8
TO
POWER CONTRACT
AMENDMENT NO. 8, dated as of the 1st day of June 2003, to the Power
Contract dated June 30, 1959, as heretofore amended and revised effective
June 2, 1975, October 1, 1980, April 1, 1985, May 6, 1988, June 26, 1989,
July 1, 1989 and February 1, 1992, between Yankee Atomic Electric Company
("Yankee"), a Massachusetts corporation, and ______________("Customer"),
a Massachusetts corporation (the "Power Contract").
WITNESSETH
WHEREAS, pursuant to the Power Contract, Yankee supplied to the
Customer and, pursuant to separate power contracts substantially identical
to the Power Contract except for the names of the parties, to the other
stockholders of Yankee, each of whom is contemporaneously entering into an
amendment to its power contract which is identical hereto except for the
necessary changes in the names of the parties, all of the capacity and
electric energy available from the nuclear generating unit owned by Yankee
t a site in Rowe, Massachusetts (such unit, together with the site and all
related facilities owned by Yankee, being herein referred to as the "Plant");
and
WHEREAS, the parties to the Power Contract and the Federal Energy
Regulatory Commission, which has regulatory jurisdiction over the Power
Contract, have consistently recognized that the cost of the capacity and
electric energy sold under the Power Contract necessarily included the costs
of shutting down, removing from service and decommissioning the Plant after
its useful life had ended and the parties have heretofore incorporated in the
Power Contract provisions designed to achieve that result, whether or not the
Plant produced electricity and whether or not the Plant operated for the full
term of the Facility Operating License; and
WHEREAS, Section 6 of the Power Contract allows Yankee to collects
its costs of decommissioning the Plant from the Customer and the
other stockholders of Yankee through accruals to a reserve fund, with
accruals made over a period extending to July 9, 2000; and
WHEREAS, Section 11 of the Power Contract provides that, upon
authorization by its board of directors of a uniform amendment to all customer
power contracts, Yankee shall have the right to amend the provisions of Section
6 of the Power Contract by serving an appropriate statement of such amendment
upon the Customer and filing the same with the Federal Energy Regulatory
Commission, and that the amendment shall thereupon become effective on the date
specified therein, subject to any suspension order duly issued by such agency;
and
WHEREAS, the estimated costs of completing the decommissioning of the
Plant have increased such that Yankee has determined that additional funding
under Section 6 of the Power Contract is required to pay for projected future
decommissioning costs; and
WHEREAS, the parties to the Power Contract desire to amend Section 6 of
the Power Contract to allow for accruals to be made to the decommissioning fund
established under the Power Contract to extend to January 1, 2011 so that the
costs of decommissioning the Plant can be met through the fund.
NOW, THEREFORE, in consideration of the above, the parties hereto agree
that the Power Contract is hereby amended as follows:
1. Terms used herein and not defined shall have the meanings set forth
in the Power Contract.
2. Section 6 of the Power Contract is hereby amended as follows: The
phrase "provided, however, that if a decision is made to cease electricity
production at the plant prior to July 9, 2000, then the accruals to the reserve
referred to in clause (b) shall be made over a period extending to July 9,
2000" is amended to read: "provided, however, that if a decision is made to
cease electricity production at the plant prior to July 9, 2000, then the
accruals to the reserve referred to in clause (b) shall be made over a period
extending to January 1, 2011."
3. Section 6 of the Power Contract is hereby amended as follows: The
sentence "The aggregate amounts of the annual accrual to the decommissioning
reserve shall be as from time to time approved by the Federal Energy Regulatory
Commission, such amounts to be accrued in equal monthly installments" is
amended to read: "The amounts of the accrual to the decommissioning reserve
shall be as from time to time approved by the Federal Energy Regulatory
Commission. The levels of such accruals may vary from year to year, but for
each such year the accruals will be collected in equal monthly installments."
4. This Amendment shall become effective as of the date first above
written, subject to any suspension order duly issued by the Federal Regulatory
Commission.
5. This Amendment may be executed in any number of counterparts, all of
which together shall constitute one and the same instrument.
WITNESS WHEREOF, the parties hereto have caused their respective duly
authorized representative to execute this Amendment on their behalf as of the
date first above written.
YANKEE ATOMIC ELECTRIC COMPANY PURCHASER _____________________________ ____________________________ Name: Name: Title: Title: |
Address: Address:
Exhibit 10.18.6
AMENDMENT NO. 6 TO
SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN
FOR OFFICERS OF NORTHEAST UTILITIES SYSTEM COMPANIES
The Supplemental Executive Retirement Plan for Officers of Northeast Utilities System Companies, as amended, is further amended, effective December 9, 2003, as follows:
A. The definition of Compensation is amended to read in its entirety as follows:
"Compensation" shall have the same meaning as provided in the Retirement Plan, but shall also include amounts disregarded pursuant to Section 401(a)(17) of the Code, amounts (included in Compensation as earned) receipt of which is deferred by a Participant pursuant to a plan or agreement which is not qualified under the Code, and, for any period in question, awards under the Incentive Plans to the extent made with respect to performance during such period, each such award to be allocated on a pro rata basis to each of the calendar months in the period to which it relates. Effective November 1, 2001, Long-Term Incentive Compensation Awards made under Incentive Plans after November 1, 2001 shall not be included in Compensation for purposes of this Plan, except that each individual who was a Participant prior to November 1, 2001 shall have credited to his or her Compensation in February each year while a Participant, in the same manner as such amount was credited in 2001, the "target" value of the stock option grants made to such Participant in February, 2001 for purposes of the Make-Whole Benefit and, if such individual was a Participant in the Target Benefit prior to October 2003, for purposes of the Target Benefit as well. For purposes of computing the value of a Participant's awards under the Incentive Plans, awards made in common shares of Northeast Utilities shall be valued by multiplying the per share New York Stock Exchange closing price on the date the award is approved by the Board by the number of shares awarded to such Participant. Notwithstanding the foregoing, if a Participant may become entitled to receive an award or awards under the Incentive Plans, and if the amount of such award(s), if any, will be determined after the date on which the Participant's Credited Service ends, then a provisional calculation of the Participant's Compensation during the period to which such award(s) relates (hereinafter the "Provisional Calculation") shall be made on or before the date the Participant's Credited Service ends, and benefits payable to the Participant under this Plan shall be based upon the Participant's Compensation as determined under the Provisional Calculation until such calculation is replaced as hereinafter provided. A Participant's Compensation shall be determined under the Provisional Calculation by including the target amount of any award to the Participant under the Incentive Plans as Compensation in the manner described in the first two sentences of this definition. The Provisional Calculation shall be replaced by a permanent calculation of Compensation (hereinafter the "Permanent Calculation") at the earliest possible date at which the amount of all awards that the Participant may become entitled to receive under the Incentive Plans has been determined, and as of such date the Participant's benefit under this Plan shall be recalculated and thereafter paid based upon the Participant's Compensation as determined under the Permanent Calculation. The Permanent Calculation of a Participant's Compensation shall be determined by including as Compensation the amount of awards, if any, to the Participant under the Incentive Plans that are determined after the date on which the Participant's Credited Service ends in the manner described in the first two sentences of this definition. If the amount of the Participant's benefit under this Plan as determined under the Permanent Calculation is greater than the amount of such benefit as determined under the Provisional Calculation, then the Employer shall make a lump sum payment to the Participant within 30 days following the date on which the Permanent Calculation is determined equal to the difference between (i) the sum of the benefit payment(s) that would have been made to the Participant hereunder from the date such payment(s) commenced until the date on which the Permanent Calculation was determined if such benefit(s) had been calculated based on the Participant's Compensation as determined under the Permanent Calculation, and (ii) the actual benefit Payment(s) made to the Participant hereunder for such period. If the amount of the Participant's benefit under this Plan as determined under the Permanent Calculation is less than the amount of such benefit as determined under the Provisional Calculation, then each of the Participant's benefit payments after the date on which the Permanent Calculation is determined shall be reduced by the amount that each benefit payment determined under the Provisional Calculation exceeded the benefit payment that would have been made under the Permanent Calculation until such time as the total amount of said reductions equals the difference between (i) the actual benefit payment(s) made to the Participant hereunder from the date such payment(s) commenced until the date on which the Permanent Calculation was determined, and (ii) the sum of such benefit payment(s) that the Participant would have received hereunder for such period if such benefit had been calculated based on the Participant's Compensation as determined under the Permanent Calculation.
Exhibit 10.19.1
FIRST AMENDMENT TO
TRUST UNDER SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN
Effective as of December 10, 2002
This First Amendment to Trust Under Supplemental Executive Retirement Plan (the "Trust Agreement") is hereby made pursuant to Section 12 of the Trust Agreement.
1. The first "WHEREAS" clause of the Trust Agreement is hereby amended to read in its entirety as follows:
"WHEREAS, Company has adopted the Supplemental Executive Retirement Plan for Officers of Northeast Utilities System Companies and the individual agreements set forth on Schedule A (collectively, the 'Plan');"
2. Section 1(e) of the Trust Agreement is hereby amended to add the following to the end thereof:
"Notwithstanding the foregoing, upon the occurrence of a Change in Control (as defined below), the Company shall contribute to the Trust such amount as shall be determined by the actuaries for the Northeast Utilities Service Company Retirement Plan (the 'Retirement Plan') as shall be necessary to fully fund all benefits accrued under the Plan at the date of such Change in Control, using the actuarial assumptions used for funding of the Retirement Plan. In addition, on each anniversary of the Change in Control, the Company shall contribute to the Trust such amount, if any, as shall be determined by the actuaries for the Retirement Plan to be necessary to fully fund all benefits accrued under the Plan as of such anniversary date, using the actuarial assumptions used for funding of the Retirement Plan."
3. Section 5(c) of the Trust Agreement is hereby amended by adding the following new paragraph to the end thereof:
"Upon the occurrence of a Change in Control, the appointment of any Investment Manager by the Company shall be automatically revoked and only the Trustee shall have the authority to appoint another Investment Manager to act as such pursuant to this Trust Agreement, and the Trustee, or such Investment Manager appointed by the Trustee, shall invest the assets of the Trust in accordance with the investment guidelines attached hereto as Exhibit A."
4. Section 10 of the Trust Agreement is hereby amended by adding the following sentence to the end of section (b) thereof:
"Notwithstanding the foregoing, following a Change in Control, the Company may not remove the Trustee without the written approval of at least 67% of the Plan participants and beneficiaries entitled to benefits under the Trust. For purposes of the preceding, a beneficiary shall be considered in calculating the 67% requirement only after the death of the corresponding participant."
5. Section 12(a) of the Trust Agreement is hereby amended by adding the following sentence to the end thereof:
"In addition, prior to a Change in Control, Schedule A may be amended by the Company acting alone, by providing written notice of such amendment to the Trustee, and, following a Change in Control, no amendment may be made without the written consent of any Participants affected by such amendment.
6. The Trust Agreement is hereby amended to add the following new Section 15 to the end thereof:
"SECTION 15. Definitions.
The following definitions shall apply for purposes of this Trust Agreement:
(1) 'Affiliate' shall mean an 'affiliate' as defined in Rule 12b-2 of the General Rules and Regulations under the Exchange Act.
(2) 'Change in Control' shall mean the happening of any of the following:
(i) Any 'person,' as such term is used in Sections 13(d) and 14(d) of the Exchange Act, other than Northeast Utilities, its Affiliates, or any Company employee benefit plan (including any trustee of such plan acting as trustee), is or becomes the 'beneficial owner' (as defined in Rule 13d-3 under the Exchange Act), directly or indirectly, of securities of Northeast Utilities representing more than 20% of the combined voting power of either (i) the Outstanding Common Shares or (ii) the Voting Securities; or
(ii) Individuals who, as of the beginning of any twenty-four month period, constitute the trustees of Northeast Utilities (the 'Incumbent Board') cease for any reason to constitute at least a majority of the Board or cease to be able to exercise the powers of the majority of the Board, provided that any individual becoming a trustee subsequent to the beginning of such period whose election or nomination for election by the common shareholders of Northeast Utilities was approved by a vote of at least a majority of the trustees then comprising the Incumbent Board shall be considered as though such individual were a member of the Incumbent Board, but excluding, for this purpose, any such individual whose initial assumption of office is in connection with an actual or threatened election contest relating to the election of the trustees of Northeast Utilities (as such terms are used in Rule 14a-11 of Regulation 14A promulgated under the Exchange Act); or
(iii) Consummation by Northeast Utilities of a reorganization, merger or consolidation (a 'Business Combination'), in each case, with respect to which all or substantially all of the individuals and entities who were the respective beneficial owners of the Outstanding Common Shares and Voting Securities immediately prior to such Business Combination do not, following consummation of all transactions intended to constitute part of such Business Combination, beneficially own, directly or indirectly, more than 50% of, respectively, the then outstanding shares of common stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors, as the case may be, of the corporation, business trust or other entity resulting from or being the surviving entity in such Business Combination in substantially the same proportion as their ownership immediately prior to such Business Combination of the Outstanding Common Shares and Voting Securities, as the case may be; or
(iv) Consummation of a complete liquidation or dissolution of Northeast Utilities or sale or other disposition of all or substantially all of the assets of Northeast Utilities other than to a corporation, business trust or other entity with respect to which, following consummation of all transactions intended to constitute part of such sale or disposition, more than 50% of, respectively, the then outstanding shares of common stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors, as the case may be, is then owned beneficially, directly or indirectly, by all or substantially all of the individuals and entities who were the beneficial owners, respectively, of the Outstanding Common Shares and Voting Securities immediately prior to such sale or disposition in substantially the same proportion as their ownership of the Outstanding Common Shares and Voting Securities, as the case may be, immediately prior to such sale or disposition.
(3) 'Exchange Act' shall mean the Securities Exchange Act of 1934, as amended.
(4) 'Outstanding Common Shares' at any time shall mean the then outstanding common shares of Northeast Utilities.
(5) 'Voting Securities' at any time shall mean the then outstanding voting securities of Northeast Utilities entitled to vote generally in the election of trustees of Northeast Utilities."
7. The Trust Agreement is hereby amended to add a Schedule A and an Exhibit A in the forms attached to this Amendment.
NORTHEAST UTILITIES SERVICE COMPANY
By: /s/ David R. McHale Name: David R. McHale Title: Vice President and Treasurer |
FLEET NATIONAL BANK
By: /s/ Michael Callahan Name: Michael Callahan Title: Sr. Vice President |
SCHEDULE A
Individual Agreements as of December 10, 2002
1968-1 1978-1 1978-2 1980-1 1981-1 1983-1 1984-1 1989-1 1990-1 1990-2 1990-3 1990-4 1990-5 1990-6 1990-7 1990-8 1990-9 1992-1 1992-2 1992-3 1992-4 1992-5 1992-6 1992-7 1992-8 1992-9 1992-10 1992-11 1992-12 1992-13 1993-1 1993-2 1993-2 1993-3 1993-4 1993-5 1993-6 1993-9 1994-1 1994-2 1994-3 1995-1 1995-2 1995-3 1995-5 1996-1 1996-2 1996-3 1996-4 1996-6 1997-1 1997-2 1997-3 1997-5 1997-6 1997-7 1998-1 1998-2 1998-3 1998-4 1998-5 1998-6 1999-1 2000-1 2001-1 2001-2 2001-3 2001-4 2001-5 2002-1 2002-2 2002-3 2002-4 2002-5 |
EXHIBIT A
INVESTMENT GUIDELINES APPLICABLE AFTER CHANGE IN CONTROL
OBJECTIVES
The objective of the investment policy of the Northeast Utilities Rabbi Trust is to provide guidelines that enable the Trust to achieve as high a level of investment return as is consistent with the preservation of capital and maintenance of liquidity. The Investment Manager will construct and manage a diversified portfolio that meets this objective. The Investment Manager will be measured against a benchmark of 50% Salomon Brothers 3-month Treasury Bill return index and 50% Salomon 1-3 Government/Corporate Bond index.
INVESTMENT GUIDELINES
1. Approved Instruments
The following fixed income instruments are considered appropriate for the portfolio:
a. U.S. Government and Agency securities.
b. Money market instruments; repurchase agreements, commercial paper,
certificates of deposit, bank obligations, Eurodollar certificates of
deposit, and approved money market funds.
c. High Quality Corporate bonds, including Eurodollar issues of U.S.
corporations, and U.S. dollar denominated issues of foreign
corporations.
d. Municipal securities
e. Floating rate securities without interest rate caps.
f. Asset-backed securities.
g. Foreign government and provincial securities, and securities of
international agencies that are U.S. dollar denominated.
h. Mortgage-backed securities, including collateralized mortgage
obligations (CMOs).
2. Quality Individual holdings of commercial paper must be rated A-1, P-1, or better, by either Standard and Poor's Corporation ("S&P") or Moody's Investor Services ("Moody's") at the time of purchase.
Securities of Issuers with a long-term credit rating must be rated at least A-/A3 by Standard & Poor's or Moody's, respectively. If a security held in the portfolio is downgraded by S&P or Moody's below the minimum rating specified above, the Investment Manager will notify the Company within 5 business days of the downgrade.
3. Diversification Securities of a single issuer, valued at cost at the time of purchase, should not exceed 2 1/2% of the market value of the portfolio or $5 million, whichever is smaller. Corporate securities (excluding commercial paper) of a single industry sector, and Mortgage Backed Securities, valued at cost at the time of purchase, should generally not exceed 25% of the market value of the portfolio.
For purposes of this diversification policy, securities of a parent company and its subsidiaries will always be combined except for captive finance companies. Such captives will be included with their parent company only if their primary purpose is to finance the parent's business. Securities issued by the U.S. Treasury and U.S. Government Agencies are specifically exempted from these restrictions.
4. Marketability/Liquidity The Investment Manager shall purchase liquid securities that regularly trade in a secondary market under normal conditions. The Investment Manager shall also structure the portfolio so that securities mature as needed to meet anticipated liquidity demands.
5. Maturity/Portfolio Duration The portfolio's average duration shall be no longer than that of the Salomon Brothers 1-3 Year Government/Corporate Index. In addition, the final maturity or put date of each security within the portfolio shall not exceed three years. In the case of securities with regularly scheduled principal repayments (i.e. asset- and mortgage-backed securities) the average life of the security at the time of purchase shall be no more than five years.
6. Performance Measurement Monthly, the Investment Manager will provide statements of transactions and market valuation of portfolio assets. Quarterly, the Investment Manager will provide the Company with a review of its performance relative to the benchmarks specified above.
7. Restricted Investments Private placements are prohibited except for 144a issues with registration rights. Futures contracts and options shall be used for bona fide hedging or risk management purposes only.
Exhibit 10.31
EMPLOYMENT AGREEMENT
THIS EMPLOYMENT AGREEMENT (the "Agreement") entered into as of October 1, 2003, by and between Northeast Utilities Service Company, a Connecticut corporation ("NUSCO"), with its principal office in Berlin, Connecticut, and Gregory B. Butler, a resident of Glastonbury, Connecticut ("Executive").
WHEREAS, Executive is currently employed as Senior Vice President, Secretary and General Counsel of Northeast Utilities ("NU") and holds senior executive positions with certain of the subsidiaries of NU (NU and the Affiliates, as such term is defined in Section 6.1(a), of NU being referred to collectively herein as the "Company")and both parties desire to enter into an agreement to reflect Executive's contribution to the Company's business in Executive's executive capacities and to provide for Executive's continued employment by the Company, upon the terms and conditions set forth herein:
NOW, THEREFORE, the parties hereto, intending to be legally bound, hereby agree as follows:
1. Employment. The Company hereby agrees to continue the employment of Executive, and Executive hereby accepts such employment and agrees to perform Executive's duties and responsibilities, in accordance with the terms, conditions and provisions hereinafter set forth.
1.1. Employment Term. The term of Executive's employment under this
Agreement shall commence as of October 1, 2003 (the "Effective Date") and shall
continue until September 30, 2004, unless sooner terminated in accordance with
Section 5 or Section 6 hereof, and shall automatically renew for periods of
one year unless one party gives written notice to the other, at least six
months prior to September 30, 2004 or at least six months prior to the end of
any one-year renewal period, that the Agreement shall not be further extended.
The period commencing as of the Effective Date and ending on the date on which
the term of Executive's employment under the Agreement shall terminate is
hereinafter referred to as the "Employment Term".
1.2. Duties and Responsibilities. Executive shall serve in such senior positions as directed by NUSCO's Board of Directors (the "Board") or the Board of Trustees (the "Trustees") of NU that provide Executive with duties and compensation that are substantially equivalent to Executive's current position in terms of duties and responsibilities. During the Employment Term, Executive shall perform all duties and accept all responsibilities incident to such positions as may be assigned to Executive by the Board.
1.3. Extent of Service. During the Employment Term, Executive agrees to use Executive's best efforts to carry out Executive's duties and responsibilities under Section 1.2 hereof and, consistent with the other provisions of this Agreement, to devote substantially all Executive's business time, attention and energy thereto. Except as provided in Section 3 hereof, the foregoing shall not be construed as preventing Executive from making minority investments in other businesses or enterprises provided that Executive agrees not to become engaged in any other business activity which, in the reasonable judgment of the Board, is likely to interfere with Executive's ability to discharge Executive's duties and responsibilities to the Company.
1.4. Base Salary. For all the services rendered by Executive hereunder, NUSCO shall pay Executive a base salary ("Base Salary"), commencing on the Effective Date, at the annual rate then being paid to Executive by NUSCO, payable in installments at such times as NUSCO customarily pays its other senior level executives (but in any event no less often than monthly). Executive's Base Salary shall be reviewed annually for appropriate adjustment (but shall not be reduced below that in effect on the Effective Date without Executive's written consent) by the Trustees pursuant to its normal performance review policies for senior level executives. Executive's annual Base Salary shall not be reduced below $300,000 without Executive's written consent.
1.5. Retirement and Benefit Coverages. During the Employment Term, Executive shall be entitled to participate in all (a) employee pension and retirement plans and programs ("Retirement Plans") and (b) welfare benefit plans and programs ("Benefit Coverages"), in each case made available to the Company's senior level executives as a group or to its employees generally, as such Retirement Plans or Benefit Coverages may be in effect from time to time, including, without limitation, the Company's Supplemental Executive Retirement Plan for Officers (the "Supplemental Plan"), both as to the Make-Whole Benefit and the Target Benefit.
1.6. Reimbursement of Expenses; Vacation. Executive shall be provided with reimbursement of expenses related to Executive's employment by NUSCO on a basis no less favorable than that which may be authorized from time to time for senior level executives as a group, and shall be entitled to vacation and holidays in accordance with the Company's normal personnel policies for senior level executives.
1.7. Short-Term Incentive Compensation. Executive shall be entitled to participate in any short-term incentive compensation programs established by the Company for its senior level executives generally, depending upon achievement of certain annual individual or business performance objectives specified and approved by the Trustees (or a Committee thereof) in its sole discretion; provided, however, that Executive's "target opportunity" and "maximum opportunity" under any such program shall be at least 50% and 100%, respectively, of Executive's Base Salary, except that the Trustees may change these "target opportunity" and "maximum opportunity" percentages as part of a general revision of executive compensation which also applies to other senior level executives of the Company. Executive's short-term incentive compensation, either in shares of NU or cash, as applicable from time to time, shall be paid to Executive, subject to the Trustees' reasonable discretion, not later than such payments are made to the Company's senior level executives generally.
1.8. Long-Term Incentive Compensation. Executive shall also be entitled to participate in any long-term incentive compensation programs established by the Company for its senior level executives generally, depending upon achievement of certain business performance objectives specified and approved by the Trustees (or a Committee thereof) in its sole discretion; provided, however, that Executive's "target opportunity" and "maximum opportunity" under any such program shall be at least 150% and 300%, respectively of Executive's Base Salary, except that the Trustees may change these "target opportunity" and "maximum opportunity" percentages as part of a general revision of executive compensation which also applies to other senior level executives of the Company. Executive's long-term incentive compensation, either in shares of NU, restricted stock units, options or cash, as applicable from time to time, shall be paid to Executive, subject to the Trustees' reasonable discretion, not later than such payments are made to the Company's senior level executives generally.
2. Confidential Information. Executive recognizes and acknowledges that by reason of Executive's employment by and service to the Company before, during and, if applicable, after the Employment Term Executive has had and will continue to have access to certain confidential and proprietary information relating to the business of the Company, which may include, but is not limited to, trade secrets, trade "know-how", customer information, supplier information, cost and pricing information, marketing and sales techniques, strategies and programs, computer programs and software and financial information (collectively referred to as "Confidential Information"). Executive acknowledges that such Confidential Information is a valuable and unique asset of the Company and Executive covenants that Executive will not, unless expressly authorized in writing by the Board, at any time during the course of Executive's employment use any Confidential Information or divulge or disclose any Confidential Information to any person, firm or corporation except in connection with the performance of Executive's duties for the Company and in a manner consistent with the Company's policies regarding Confidential Information. Executive also covenants that at any time after the termination of such employment, directly or indirectly, Executive will not use any Confidential Information or divulge or disclose any Confidential Information to any person, firm or corporation, unless such information is in the public domain through no fault of Executive or except when required to do so by a court of law, by any governmental agency having supervisory authority over the business of the Company or by any administrative or legislative body (including a committee thereof) with apparent jurisdiction to order Executive to divulge, disclose or make accessible such information, in which case Executive will inform NUSCO in writing promptly of such required disclosure, but in any event at least two business days prior to disclosure. All written Confidential Information (including, without limitation, in any computer or other electronic format) which comes into Executive's possession during the course of Executive's employment shall remain the property of the Company. Except as required in the performance of Executive's duties for the Company, or unless expressly authorized in writing by the Board, Executive shall not remove any written Confidential Information from the Company's premises, except in connection with the performance of Executive's duties for the Company and in a manner consistent with the Company's policies regarding Confidential Information. Upon termination of Executive's employment, Executive agrees immediately to return to the Company all written Confidential Information in Executive's possession.
3. Non-Competition; Non-Solicitation.
(a) During Executive's employment by the Company and for a period of two years after Executive's termination of employment for any reason, within the Company's "service area," as defined below, Executive will not, except with the prior written consent of the Board, directly or indirectly, own, manage, operate, join, control, finance or participate in the ownership, management, operation, control or financing of, or be connected as an officer, director, employee, partner, principal, agent, representative, consultant or otherwise with, or use or permit Executive's name to be used in connection with, any business or enterprise which is engaged in any business that is competitive with any regulated business or enterprise in which the Company is engaged ("Competitive Company"). For the purposes of this Section, "Service Area" shall mean the geographic area within the states of Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island, and Vermont, or any other state in which the Company, in the aggregate, generates 25% or more of its revenues in the fiscal year of NU in which Executive's termination of employment occurs. Further, for the purposes of this Section, "Competitive Company" shall mean Consolidated Edison, Inc., Energy East Corporation, Hydro-Quebec, KeySpan Energy, National Grid USA, NSTAR, or The United Illuminating Company, their assigns or successors, or any other company which in the future engages in competition with the regulated business of the Company in the Service Area. Executive acknowledges that the listed service area is the area in which the Company presently does business.
(b) The foregoing restrictions shall not be construed to prohibit the ownership by Executive of less than five percent (5%) of any class of securities of any corporation which is engaged in any of the foregoing businesses having a class of securities registered pursuant to the Securities Exchange Act of 1934 (the "Exchange Act"), provided that such ownership represents a passive investment and that neither Executive nor any group of persons including Executive in any way, either directly or indirectly, manages or exercises control of any such corporation, guarantees any of its financial obligations, otherwise takes any part in its business, other than exercising Executive's rights as a shareholder, or seeks to do any of the foregoing.
(c) Executive further covenants and agrees that during Executive's
employment by the Company and for the period of two years thereafter, Executive
will not, directly or indirectly, (i) solicit, divert, take away, or attempt to
solicit, divert or take away, any of the Company's "Principal Customers,"
efined for the purposes hereof to include any customer of the Company, from
which $100,000 or more of annual gross revenues are derived at such time, or
(ii) encourage any Principal Customer to reduce its patronage of the Company.
(d) Executive further covenants and agrees that during Executive's employment by the Company and for the period of two years thereafter, Executive will not, except with the prior written consent of the Trustees, directly or indirectly, solicit or hire, or encourage the solicitation or hiring of, any person who was a managerial or higher level employee of the Company at any time during the term of Executive's employment by the Company by any employer other than the Company for any position as an employee, independent contractor, consultant or otherwise. The foregoing covenant of Executive shall not apply to any person after 12 months have elapsed subsequent to the date on which such person's employment by the Company has terminated.
(e) Nothing in this Section 3 shall be construed to prohibit Executive,
if Executive is a lawyer, from being connected as a partner, principal,
shareholder, associate, counsel or otherwise with another lawyer or a law
firm which performs services for clients engaged in any business or enterprise
that is competitive with any business or enterprise in which the Company is
engaged, provided that Executive is not personally involved, directly or
indirectly, in performing services for any such clients during the period
specified in Section 3(a) and provided further that such lawyer or law firm
takes reasonable precautions to screen Executive from participating for the
period specified in Section 3(a) in the representation of any such clients.
The parties agree that any such personal performance of services by Executive
for any such clients during such period would create an unreasonable risk of
violation by Executive of the provisions of Section 2 of this Agreement, and
Executive agrees (and the Company may elect) to notify in writing any lawyer
or law firm with which Executive may be connected during the period specified
in Section 3(a) of Executive's Agreement as set forth herein. The parties
further agree that, in addition to the nondisclosure obligations of
Section 2 of this Agreement, Executive remains subject to all ethical
obligations relating to confidentiality of information to the extent that
Executive acted as a lawyer for the Company, but Executive's knowledge of such
confidential information shall not be imputed to such other lawyer or law firm
with which Executive subsequently may become connected. Executive agrees to
notify the Company in writing in advance of the precautions to be taken by
such lawyer or law firm to screen Executive from any representation of such
competing client of such lawyer or law firm.
4. Equitable Relief.
(a) Executive acknowledges and agrees that the restrictions contained in Sections 2 and 3 are reasonable and necessary to protect and preserve the legitimate interests, properties, goodwill and business of the Company, that NUSCO would not have entered into this Agreement in the absence of such restrictions and that irreparable injury will be suffered by the Company should Executive breach any of the provisions of those Sections. Executive represents and acknowledges that (i) Executive has been advised by NUSCO to consult Executive's own legal counsel in respect of this Agreement, and (ii) that Executive has had full opportunity, prior to execution of this Agreement, to review thoroughly this Agreement with Executive's counsel.
(b) Executive further acknowledges and agrees that a breach of any of the restrictions in Sections 2 and 3 cannot be adequately compensated by monetary damages. Executive agrees that the Company shall be entitled to preliminary and permanent injunctive relief, without the necessity of proving actual damages, as well as an equitable accounting of all earnings, profits and other benefits arising from any violation of Sections 2 or 3 hereof, which rights shall be cumulative and in addition to any other rights or remedies to which the Company may be entitled. In the event that any of the provisions of Sections 2 or 3 hereof should ever be adjudicated to exceed the time, geographic, service, or other limitations permitted by applicable law in any jurisdiction, it is the intention of the parties that the provision shall be amended to the extent of the maximum time, geographic, service, or other limitations permitted by applicable law, that such amendment shall apply only within the jurisdiction of the court that made such adjudication and that the provision otherwise be enforced to the maximum extent permitted by law.
(c) If Executive breaches any of Executive's obligations under Sections 2 or 3 hereof, and such breach constitutes "cause," as defined in Section 5.3 hereof, or would constitute Cause if it had occurred during the Employment Term, the Company shall thereafter have no Target Benefit obligation pursuant to the Supplemental Plan, but shall remain obligated for the Make-Whole Benefit under the Supplemental Plan, but only to the extent not modified by the terms of this Agreement, and compensation and other benefits provided in any plans, policies or practices then applicable to Executive in accordance with the terms thereof.
(d) Executive irrevocably and unconditionally (i) agrees that any suit, action or other legal proceeding arising out of Sections 2 or 3 hereof, including without limitation, any action commenced by the Company for preliminary and permanent injunctive relief and other equitable relief, may be brought in the United States District Court for the District of Connecticut, or if such court does not have jurisdiction or will not accept jurisdiction, in any court of general jurisdiction in Hartford, Connecticut, (ii) consents to the non-exclusive jurisdiction of any such court in any such suit, action or proceeding, and (iii) waives any objection which Executive may have to the laying of venue of any such suit, action or proceeding in any such court. Executive also irrevocably and unconditionally consents to the service of any process, pleadings, notices or other papers in a manner permitted by the notice provisions of Section 10 hereof.
(e) Executive agrees that for a period of five years following the termination of Executive's employment by the Company Executive will provide, and that at all times after the date hereof the Company may similarly provide, a copy of Sections 2 and 3 hereof to any business or enterprise (i) which Executive may directly or indirectly own, manage, operate, finance, join, control or participate in the ownership, management, operation, financing, or control of, or (ii) with which Executive may be connected as an officer, director, employee, partner, principal, agent, representative, consultant or otherwise, or in connection with which Executive may use or permit Executive's name to be used; provided, however, that this provision shall not apply in respect of Section 3 hereof after expiration of the time periods set forth therein.
5. Termination. The Employment Term shall terminate upon the occurrence of any one of the following events:
5.1. Disability. NUSCO may terminate the Employment Term if Executive is
unable substantially to perform Executive's duties and responsibilities
hereunder to the full extent required by the Board by reason of illness, injury
or incapacity for six consecutive months, or for more than six months in the
aggregate during any period of twelve calendar months; provided, however, that
NUSCO shall continue to pay Executive's Base Salary until NUSCO acts to
terminate the Employment Term. In addition, Executive shall be entitled to
receive (i) any amounts earned, accrued or owing but not yet paid under
Section 1 above and (ii) any other benefits in accordance with the terms of any
applicable plans and programs of the Company. Otherwise, the Company shall
have no further liability or obligation to Executive for compensation under
this Agreement. Executive agrees, in the event of a dispute under this
Section 5.1, to submit to a physical examination by a licensed physician
selected by the Board.
5.2. Death. The Employment Term shall terminate in the event of Executive's death. In such event, NUSCO shall pay to Executive's executors, legal representatives or administrators, as applicable, an amount equal to the installment of Executive's Base Salary set forth in Section 1.4 hereof for the month in which Executive dies. In addition, Executive's estate shall be entitled to receive (i) any other amounts earned, accrued or owing but not yet paid under Section 1 above and (ii) any other benefits in accordance with the terms of any applicable plans and programs of the Company. Otherwise, the Company shall have no further liability or obligation under this Agreement to Executive's executors, legal representatives, administrators, heirs or assigns or any other person claiming under or through Executive.
5.3. Cause. NUSCO may terminate the Employment Term, at any time, for "cause" upon written notice, in which event all payments under this Agreement shall cease, except for Base Salary to the extent already accrued, and no Target Benefit shall be due under the Supplemental Plan, but Executive shall remain entitled to the Make-Whole Benefit under the Supplemental Plan, but only to the extent not modified by the terms of this Agreement, and any other benefits in accordance with the terms of any applicable plans and programs of the Company. For purposes of this Agreement, Executive's employment may be terminated for "cause" if (i) Executive is convicted of a felony, (ii) in the reasonable determination of the Board, Executive has (x) committed an act of fraud, embezzlement, or theft in connection with Executive's duties in the course of Executive's employment with the Company, (y) caused intentional, wrongful damage to the property of the Company or intentionally and wrongfully disclosed Confidential Information, or (z) engaged in gross misconduct or gross negligence in the course of Executive's employment with the Company or (iii) Executive materially breached Executive's obligations under this Agreement and shall not have remedied such breach within 30 days after receiving written notice from the Board specifying the details thereof. For purposes of this Agreement, an act or omission on the part of Executive shall be deemed "intentional" only if it was not due primarily to an error in judgment or negligence and was done by Executive not in good faith and without reasonable belief that the act or omission was in the best interest of the Company.
5.4. Termination Without Cause and Non-Renewal.
(a) NUSCO may remove Executive, at any time, without cause from the position in which Executive is employed hereunder (in which case the Employment Term shall be deemed to have ended) upon not less than 60 days' prior written notice to Executive; provided, however, that, in the event that such notice is given, Executive shall be under no obligation to render any additional services to the Company and, subject to the provisions of Section 3 hereof, shall be allowed to seek other employment. Upon any such removal or if NUSCO informs Executive that the Agreement will not be renewed after September 30, 2004 or at the end of any subsequent renewal period, Executive shall be entitled to receive, as liquidated damages for the failure of the Company to continue to employ Executive, only the amount due to Executive under the Company's then current severance pay plan for employees. No other payments or benefits shall be due under this Agreement to Executive, but Executive shall be entitled to any other benefits in accordance with the terms of any applicable plans and programs of the Company. Notwithstanding anything in this Agreement to the contrary, on or after Executive attains age 65, no action by the Company shall be treated as a removal from employment or non-renewal if on the effective date of such action Executive satisfies all of the requirements for the executive or high policy-making exception to applicable provisions of state and federal age discrimination legislation.
(b) Notwithstanding the provisions of Section 5.4(a) (other than the last sentence), in the event that Executive executes a written release upon such removal or non-renewal, substantially in the form attached hereto as Annex 1, (the "Release"), of any and all claims against the Company and all related parties with respect to all matters arising out of Executive's employment by the Company (other than any entitlements under the terms of this Agreement or under any other plans or programs of the Company in which Executive participated and under which Executive has accrued a benefit), or the termination thereof, Executive shall be entitled to receive, in lieu of the payment described in subsection (a) hereof, which Executive agrees to waive,
(i) as liquidated damages for the failure of the Company to continue to employ Executive, a single cash payment, within 30 days after the effective date of the removal or non-renewal, equal to Executive's Base Compensation, as defined in Section 6.1(b) below, which shall not constitute a "severance benefit" to Executive for purposes of the Target Benefit under the Supplemental Plan;
(ii) for a period of two years following the end of the Employment Term, Executive and Executive's spouse and dependents shall be eligible for a continuation of those Benefit Coverages, as in effect at the time of such termination or removal, and as the same may be changed from time to time, as if Executive had been continued in employment during said period or to receive cash in lieu of such benefits or premiums, as applicable, where such Benefit Coverages may not be continued (or where such continuation would adversely affect the tax status of the plan pursuant to which the Benefit Coverage is provided) under applicable law or regulations;
(iii) any other amounts earned, accrued or owing but not yet paid under
Section 1 above;
(iv) any other benefits in accordance with the terms of any applicable plans and programs of the Company and a payment equal to any unused vacation;
(v) as additional consideration for the non-competition and non- solicitation covenant contained in Section 3, a single cash payment, within 30 days after the effective date of the removal or non-renewal, equal to Executive's Base Compensation, as defined in Section 6.1(b) below, which shall not constitute a "severance benefit" to Executive for purposes of Target Benefit under the Supplemental Plan; and
(vi) Under the Supplemental Plan, Executive shall be entitled to receive
Target Benefit and a Make-Whole Benefit commencing on the first day of any
month following Executive's Termination, whether or not Executive has then
satisfied the requirements for early, normal or deferred retirement under, or
is then entitled to receive a vested benefit under, the Company's Retirement
Plan, using the Termination Date as the "date of retirement" contemplated by
Section IV(b) of the Supplemental Plan; Executive's years of service with the
Company through the 24th month following the Termination Date shall be taken
into account in determining the amount of the Target Benefit and the Make-Whole
Benefit and 24 months shall be added to Executive's age for purposes of
determining the reduction in such Benefits, if any, to reflect early
commencement, utilizing the early commencement factor for Executive's age and
years of service, each as so modified, set forth in the Company's Retirement
Plan as in effect on the Termination Date or, if there is no such factor for
Executive's age as so modified as of the Termination Date, a full actuarial
reduction for Executive's age as so modified, as determined by the enrolled
actuary for the Retirement Plan; and
(vii) All stock option grants, to the extent not already vested prior to the removal or non-renewal, shall be fully vested and exercisable or paid as if Executive had remained actively employed by the Company, and had satisfied all time requirements as to exercise, including the right of exercise, where appropriate, within 36 months after the removal or non-renewal.
5.5. Voluntary Termination. Executive may voluntarily terminate the Employment Term upon 30 days' prior written notice for any reason. In such event, after the effective date of such termination, no further payments shall be due under this Agreement except that Executive shall be entitled to any benefits due in accordance with the terms of any applicable plan and programs of the Company.
6. Payments Upon a Change in Control.
6.1. Definitions. For all purposes of this Section 6, the following terms shall have the meanings specified in this Section 6.1 unless the context otherwise clearly requires:
(a) "Affiliate" shall mean an "affiliate" as defined in Rule 12b-2 of the General Rules and Regulations under the Exchange Act.
(b) "Base Compensation" shall mean, for a calendar year, Executive's
annualized Base Salary as would be reported for federal income tax purposes on
Form W-2 for such calendar year, together with any and all salary reduction
authorized amounts under any of the Company's benefit plans or programs for
such calendar year, and all short-term incentive compensation at the target
level to be paid to Executive in all employee capacities with the Company
attributable to such calendar year and taxable in the following calendar year.
"Base Compensation" shall be the higher of (i) Base Compensation for the
calendar year in which occurs the Change of Control or, if no Change of Control
occurs, the calendar year in which occurs the involuntary termination; or
(ii) Base Compensation for the full calendar year immediately prior thereto.
"Base Compensation" shall not include the value of any stock options,
performance units, or other elements of Long-Term Incentive Compensation or
any exercise thereunder.
(c) "Change of Control" shall mean the happening of any of the following:
(i) When any "person," as such term is used in Sections 13(d) and 14(d) of the Securities Exchange Act of 1934 (the "Exchange Act"), other than the Company, its Affiliates, or any Company employee benefit plan (including any trustee of such plan acting as trustee), is or becomes the "beneficial owner" (as defined in Rule 13d-3 under the Exchange Act), directly or indirectly, of securities of NU representing more than 20% of the combined voting power of either (i) the then outstanding common shares of NU (the "Outstanding Common Shares") or (ii) the then outstanding voting securities of NU entitled to vote generally in the election of directors (the "Voting Securities"); or
(ii) Individuals who, as of the beginning of any twenty-four month period, constitute the Trustees (the "Incumbent Trustees") cease for any reason to constitute at least a majority of the Trustees or cease to be able to exercise the powers of the majority of the Trustees, provided that any individual becoming a trustee subsequent to the beginning of such period whose election or nomination for election by NU's shareholders was approved by a vote of at least a majority of the trustees then comprising the Incumbent Trustees shall be considered as though such individual were a member of the Incumbent Trustees, but excluding, for this purpose, any such individual whose initial assumption of office is in connection with an actual or threatened election contest relating to the election of the Trustees of NU (as such terms are used in Rule 14a-11 of Regulation 14A promulgated under the Exchange Act); or
(iii) Consummation by NU of a reorganization, merger or consolidation (a "Business Combination"), in each case, with respect to which all or substantially all of the individuals and entities who were the respective beneficial owners of the Outstanding Common Shares and Voting Securities immediately prior to such Business Combination do not, following consummation of all transactions intended to constitute part of such Business Combination, beneficially own, directly or indirectly, more than 50% of, respectively, the then outstanding shares of common stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors, as the case may be, of the corporation, business trust or other entity resulting from or being the surviving entity in such Business Combination in substantially the same proportion as their ownership immediately prior to such Business Combination of the Outstanding Common Shares and Voting Securities, as the case may be; or
(iv) Consummation of a complete liquidation or dissolution of NU or sale or other disposition of all or substantially all of the assets of NU other than to a corporation, business trust or other entity with respect to which, following consummation of all transactions intended to constitute part of such sale or disposition, more than 50% of, respectively, the then outstanding shares of common stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors, as the case may be, is then owned beneficially, directly or indirectly, by all or substantially all of the individuals and entities who were the beneficial owners, respectively, of the Outstanding Common Shares and Voting Securities immediately prior to such sale or disposition in substantially the same proportion as their ownership of the Outstanding Common Shares and Voting Securities, as the case may be, immediately prior to such sale or disposition.
(d) "Termination Date" shall mean the date of receipt of a Notice of Termination of this Agreement or any later date specified therein.
(e) "Termination of Employment" shall mean the termination of Executive's actual employment relationship with the Company, including a failure to renew the Agreement after September 30, 2004 or at the end of any subsequent renewal period, in either case occasioned by the Company's action.
(f) "Termination upon a Change of Control" shall mean a Termination of Employment during the period beginning on the earlier of (a) approval by the shareholders of NU of a Change of Control or (b) consummation of a Change of Control and, in either case, ending on the second anniversary of the consummation of the transaction that constitutes the Change of Control (or if such period started on shareholder approval and after such shareholder approval the Trustees abandon the transaction, on the date the Trustees abandoned the transaction) either:
(i) initiated by the Company for any reason other than Executive's (w) disability, as described in Section 5.1 hereof, (x) death, (y) retirement on or after attaining age 65, or (z) "cause," as defined in Section 5.3 hereof, or
(ii) initiated by Executive (A) upon any failure of the Company materially to comply with and satisfy any of the terms of this Agreement, including any significant reduction by the Company of the authority, duties or responsibilities of Executive, any reduction of Executive's compensation or benefits as in effect immediately prior to the Change of Control, or the assignment to Executive of duties which are materially inconsistent with the duties of Executive's position as defined in Section 1.2 above, or (B) if Executive is transferred, without Executive's written consent, to a location that is more than 50 miles from Executive's principal place of business immediately preceding such approval or consummation; provided, that the imposition on Executive following a Change of Control of a limitation of Executive's scope of authority such that Executive's responsibilities relate primarily to a company or companies whose common equity is not publicly held shall be considered a "significant reduction by the Company of the authority, duties or responsibilities of Executive" for the purposes hereof.
Notwithstanding the foregoing, for purposes of this definition:
(i) a Termination of Employment which occurs prior to consummation of a Change
of Control shall not constitute a Termination upon a Change of Control, as
determined above, unless it is specifically approved by the Trustees in their
sole discretion; and (ii) a Termination initiated by Executive prior to
consummation of a Change of Control shall not constitute a Termination upon a
Change of Control if the failure, reduction, assignment or transfer is
determined by the Trustees to be unrelated to the impending Change of Control.
6.2. Notice of Termination. Any Termination upon a Change of Control shall be communicated by a Notice of Termination to the other party hereto given in accordance with Section 10 hereof. For purposes of this Agreement, "Notice of Termination" means a written notice which (i) indicates the specific termination provision in this Agreement relied upon, (ii) briefly summarizes the facts and circumstances deemed to provide a basis for a Termination of Employment and the applicable provision hereof, and (iii) if the Termination Date is other than the date of receipt of such notice, specifies the Termination Date (which date shall not be more than 15 days after the giving of such notice).
6.3. Payments upon Termination. Subject to the provisions of Sections 6.6 and 6.7 hereof, in the event of Executive's Termination upon a Change of Control, the Company agrees (a) in the event Executive executes the Release required by Section 5.4(b), to pay to Executive, in a single cash payment, within thirty days after the Termination Date, two multiplied by Executive's Base Compensation and, in addition, all amounts, benefits and Benefit Coverages described in Section 5.4(b)(ii), (iii), (iv) and (v), provided that in (ii) Benefit Coverages shall continue for three years instead of two, or (b) in the event Executive fails or refuses to execute the Release required by Section 5.4(b), to pay to Executive, in a single cash payment, within thirty days after the Termination Date, the amount due under Section 5.4(a) above and, in addition, all other amounts and benefits described in Section 5.4(a).
6.4. Other Payments, Supplemental Plan, Stock Option and Stock Grants, etc. Subject to the provisions of Sections 6.6 and 6.7 hereof, in the event of Executive's Termination upon a Change of Control, and the execution of the Release required by Section 5.4(b):
(a) Under the Supplemental Plan, Executive shall be entitled to a Target Benefit and a Make-Whole Benefit commencing as provided below, whether or not Executive has then satisfied the requirements for early, normal or deferred retirement under, or is then entitled to receive a vested benefit under the Company's Retirement Plan or has attained age 60, using the Termination Date as the "date of retirement" contemplated by Section IV(b) of the Supplemental Plan. There shall be an actuarial reduction in the event the Target Benefit and Make-Whole Benefit commence prior to age 65, if at the Termination Date Executive has not yet attained age 52, or if at the Termination Date Executive's attained age and service for retirement benefit calculations do not total at least 85 years. The actuarial reduction shall be 2% for each year younger than age 65 to age 60, if applicable, 3% for each year younger than age 60 to age 55 and 4% for each year younger than 55, unless actuarial reduction factors more favorable to Executive are adopted in the Retirement Plan, in hich case those factors shall apply. Executive's years of service with the Company through the 36th month following the Termination Date shall be taken into account in determining the amount of the Target Benefit and Make-Whole Benefit and 36 months shall be added to Executive's age for purposes of determining Executive's eligibility for both such Benefits and the actuarial reduction under the Plan as modified herein. Executive shall determine the form of payment in which the Target Benefit and Make-Whole Benefit shall be paid, in accordance with the terms of the Supplemental Plan or may elect to receive a single sum payment equal to the then actuarial present value (computed using the 1983 GAM (50%/Male/50%/Female) Mortality Table and at an interest rate equal to the discount rate used in the Retirement Plan's previous year's FASB 87 accounting) of the amount of the Target Benefit and Make-Whole Benefit as determined in accordance with the first three sentences of this subsection (a). Payment shall commence or be made within 30 days after the Termination Date or on any date thereafter, as specified by Executive in a written election. Such election may be made at any time and amended at any time but any election or amendment, other than one made within 30 days of the Effective Date, shall be ineffective if made within six months prior to the Termination Date. In the absence of any election or determination provided for herein, the terms of the Supplemental Plan shall govern the form and time of payment.
(b) Executive's age and years of service with the Company through the 36th month following the Termination Date shall be taken into account in determining Executive's eligibility for benefits, but not cost-sharing, under the Company's retiree health plan. For the purpose of determining such eligibility, a Termination upon a Change of Control shall be considered to be an involuntary termination.
(c) Unless the Compensation Committee of the Northeast Utilities Board of Trustees comprises the same members as those on the Committee immediately before the Change of Control and determines otherwise, (i) all stock option grants previously granted to Executive, to the extent not already vested prior to such occurrence, shall be fully vested and immediately exercisable as if Executive had satisfied all requirements as to exercise, including the right of exercise, where appropriate, within 36 months of such occurrence and, if the Change of Control results in the Voting Securities of NU ceasing to be traded on a national securities exchange or though the national market system of the National Association of Securities Dealers Inc., the value of a share of tock on the day the option is exercised shall be deemed to be the closing price on the day such Voting Securities cease trading; and (ii) if NU is not the surviving corporation (or survives only as a subsidiary of another corporation), those portions of any such options that have not been exercised shall be assumed by, or replaced with comparable options or rights by, the surviving corporation. Notwithstanding the foregoing, such Committee (if composed of the same members as those on the Committee immediately before the Change of Control) may require Executive to surrender the remainder of any or all such options, in each case in exchange for a payment by the Company, in cash or common shares as determined by the Committee, in an amount equal to the amount by which the then fair market value of the common shares subject to such option exceeds the exercise price per share of such option, or, after giving Executive an opportunity to exercise such option, terminate the option at such time as the Committee deems appropriate.
6.5. Non-Exclusivity of Rights. Nothing in this Agreement shall prevent or limit Executive's continuing or future participation in or rights under any benefit, bonus, incentive or other plan or program provided by the Company and for which Executive may qualify; provided, however, that if Executive becomes entitled to and receives all of the payments provided for in this Agreement, Executive hereby waives Executive's right to receive payments under any severance plan or similar program applicable to all employees of the Company.
6.6. Certain Increase in Payments.
(a) Anything in this Agreement to the contrary notwithstanding, in the event that it shall be determined that any payment or distribution by the Company to or for the benefit of Executive, whether paid or payable or distributed or distributable pursuant to the terms of this Agreement or otherwise (the "Payment"), would constitute an "excess parachute payment" within the meaning of Section 280G of the Internal Revenue Code of 1986, as amended (the "Code"), Executive shall be paid an additional amount (the "Gross-Up Payment") such that the net amount retained by Executive after deduction of any excise tax imposed under Section 4999 of the Code, and any federal, state and local income and employment tax and excise tax imposed upon the Gross-Up Payment shall be equal to the Payment. For purposes of determining the amount of the Gross-Up Payment, Executive shall be deemed to pay federal income tax and employment taxes at the highest marginal rate of federal income and employment taxation in the calendar year in which the Gross-Up Payment is to be made and state and local income taxes at the highest marginal rate of taxation in the state and locality of Executive's residence on the Termination Date, net of the maximum reduction in federal income taxes that may be obtained from the deduction of such state and local taxes.
(b) All determinations to be made under this Section 6 shall be made by the Company's independent public accountant immediatelyprior to the Change of Control (the "Accounting Firm"), which firm shall provide its determinations and any supporting calculations both to the Company and Executive within 10 days of the Termination Date. Any such determination by the Accounting Firm shall be binding upon the Company and Executive. Within five days after the Accounting Firm's determination, the Company shall pay (or cause to be paid) or distribute (or cause to be distributed) to or for the benefit of Executive such amounts as are then due to Executive under this Agreement.
(c) In the event that upon any audit by the Internal Revenue Service, or by a state or local taxing authority, of the Payment or Gross-Up Payment, a change is finally determined to be required in the amount of taxes paid by Executive, appropriate adjustments shall be made under this Agreement such that the net amount which is payable to Executive after taking into account the provisions of Section 4999 of the Code shall reflect the intent of the parties as expressed in subsection (a) above, in the manner determined by the Accounting Firm.
(d) All of the fees and expenses of the Accounting Firm in performing the determinations referred to in subsections (b) and (c) above shall be borne solely by the Company. The Company agrees to indemnify and hold harmless the Accounting Firm of and from any and all claims, damages and expenses resulting from or relating to its determinations pursuant to subsections (b) and (c) above, except for claims, damages or expenses resulting from the gross negligence or willful misconduct of the Accounting Firm.
6.7 Changes to Sections 6.3 and 6.4. The payments, benefits and other compensation provided under Sections 6.3 and 6.4 may be revised, in the sole discretion of the Board, after the expiration of two years following written notice to Executive of the Board's intention to do so and the changes to be made; provided, however, that no revision may be made that would reduce the payments, benefits and other compensation below those provided under Section 5.4 in the event Executive's employment is terminated without cause or this Agreement is not renewed; and provided, further, that no such notice may be given and no such revision may become effective following a Change of Control. Notice under this Section 6.7 shall not constitute a non-renewal or removal of Executive, nor shall any such actual revision be grounds for a determination that this Agreement is not being renewed or that Executive has been removed, for purposes of Section 5.4.
7. Survivorship. The respective rights and obligations of the parties under this Agreement shall survive any termination of Executive's employment to the extent necessary to the intended preservation of such rights and obligations.
8. Mitigation. Executive shall not be required to mitigate the amount of any payment or benefit provided for in this Agreement by seeking other employment or otherwise and there shall be no offset against amounts due Executive under this Agreement on account of any remuneration attributable to any subsequent employment that Executive may obtain.
9. Arbitration; Expenses. In the event of any dispute under the provisions of this Agreement other than a dispute in which the primary relief sought is an equitable remedy such as an injunction, the parties shall be required to have the dispute, controversy or claim settled by arbitration in the City of Hartford, Connecticut in accordance with National Rules for the Resolution of Employment Disputes then in effect of the American Arbitration Association, before a panel of three arbitrators, two of whom shall be selected by the Company and Executive, respectively, and the third of whom shall be selected by the other two arbitrators. Any award entered by the arbitrators shall be final, binding and nonappealable (except as provided in Section 52- 418 of the Connecticut General Statutes) and judgment may be entered thereon by ither party in accordance with applicable law in any court of competent jurisdiction. This arbitration provision shall be specifically enforceable. The arbitrators shall have no authority to modify any provision of this Agreement or to award a remedy for a dispute involving this Agreement other than a benefit specifically provided under or by virtue of the Agreement. If Executive prevails on any material issue which is the subject of such arbitration or lawsuit, the Company shall be responsible for all of the fees of the American Arbitration Association and the arbitrators and any expenses relating to the conduct of the arbitration (including the Company's and Executive's reasonable attorneys' fees and expenses). Otherwise, each party shall be responsible for its own expenses relating to the conduct of the arbitration (including reasonable attorneys' fees and expenses) and shall share the fees of the American Arbitration Association.
10. Notices. All notices and other communications required or permitted under this Agreement or necessary or convenient in connection herewith shall be in writing and shall be deemed to have been given when hand delivered or mailed by registered or certified mail, as follows (provided that notice of change of address shall be deemed given only when received):
If to the Company, to:
Northeast Utilities Service Company
P.O. Box 270
Hartford, CT 06141-0270
Attention: Assistant Corporate Secretary
If to Executive, to:
Gregory B. Butler 17 Green Briar Glastonbury, CT 06033
or to such other names or addresses as the Company or Executive, as the case may be, shall designate by notice to each other person entitled to receive notices in the manner specified in this Section.
11. Contents of Agreement; Amendment and Assignment.
(a) This Agreement sets forth the entire understanding between the parties hereto with respect to the subject matter hereof and cannot be changed, modified, extended or terminated except upon written amendment approved by the Board and executed on its behalf by a duly authorized officer and by Executive.
(b) All of the terms and provisions of this Agreement shall be binding upon and inure to the benefit of and be enforceable by the respective heirs, executors, administrators, legal representatives, successors and assigns of the parties hereto, except that the duties and responsibilities of Executive under this Agreement are of a personal nature and shall not be assignable or delegatable in whole or in part by Executive. The Company shall require any successor (whether direct or indirect, by purchase, merger, consolidation, reorganization or otherwise) to all or substantially all of the business or assets of the Company, by agreement in form and substance satisfactory to Executive, expressly to assume and agree to perform this Agreement in the same manner and to the extent the Company would be required to perform if no such succession had taken place.
12. Severability. If any provision of this Agreement or application thereof to anyone or under any circumstances is adjudicated to be invalid or unenforceable in any jurisdiction, such invalidity or unenforceability shall not affect any other provision or application of this Agreement which can be given effect without the invalid or unenforceable provision or application and shall not invalidate or render unenforceable such provision or application in any other jurisdiction. If any provision is held void, invalid or unenforceable with respect to particular circumstances, it shall nevertheless remain in full force and effect in all other circumstances.
13. Remedies Cumulative; No Waiver. No remedy conferred upon a party by this Agreement is intended to be exclusive of any other remedy, and each and every such remedy shall be cumulative and shall be in addition to any other remedy given under this Agreement or now or hereafter existing at law or in equity. No delay or omission by a party in exercising any right, remedy or power under this Agreement or existing at law or in equity shall be construed as a waiver thereof, and any such right, remedy or power may be exercised by such party from time to time and as often as may be deemed expedient or necessary by such party in its sole discretion.
14. Beneficiaries/References. Executive shall be entitled, to he extent permitted under any applicable law, to select and change a beneficiary or beneficiaries to receive any compensation or benefit payable under this Agreement following Executive's death by giving the Company written notice thereof. In the event of Executive's death or a judicial determination of Executive's incompetence, reference in this Agreement to Executive shall be deemed, where appropriate, to refer to Executive's beneficiary, estate or other legal representative.
15. Miscellaneous. All section headings used in this Agreement are for convenience only. This Agreement may be executed in counterparts, each of which is an original. It shall not be necessary in making proof of this Agreement or any counterpart hereof to produce or account for any of the other counterparts.
16. Withholding. The Company may withhold from any payments under this Agreement all federal, state and local taxes as the Company is required to withhold pursuant to any law or governmental rule or regulation. Executive shall bear all expense of, and be solely responsible for, all federal, state and local taxes due with respect to any payment received under this Agreement.
17. Governing Law. This Agreement shall be governed by and interpreted under the laws of the State of Connecticut without giving effect to any conflict of laws provisions.
18. Adoption by Affiliates; Obligations. The obligations under this Agreement shall, in the first instance, be paid and satisfied by NUSCO; provided, however, that NUSCO will use its best efforts to cause NU and each entity in which NU (or its successors or assigns) now or hereafter holds, directly or indirectly, more than a 50 percent voting interest to approve and adopt this Agreement and, by such approval and adoption, to be bound by the terms hereof as though a signatory hereto. If NUSCO shall be dissolved or for any other reason shall fail to pay and satisfy the obligations, each individual such entity thereafter shall be jointly and severally liable to pay and satisfy the obligations to Executive.
19. Establishment of Trust. The Company may establish an irrevocable trust fund pursuant to a trust agreement to hold assets to satisfy any of its obligations under this Agreement. Funding of such trust fund shall be subject to the Board's discretion, as set forth in the agreement pursuant to which the fund will be established.
IN WITNESS WHEREOF, the undersigned, intending to be legally bound, have executed this Agreement as of the date first above written.
NORTHEAST UTILITIES
SERVICE COMPANY
/s/ Michael G. Morris
Michael G. Morris
Date: 10/15/03
/s/ Gregory B. Butler
EXECUTIVE: Gregory B. Butler
Date: October 17, 2003
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EXHIBIT 10.3
DESCRIPTION OF TERMS OF EMPLOYMENT OF LEON J. OLIVIER
The terms of Mr. Olivier's employment are as follows:
1. Start Date: September 10, 2001.
2. Title: President, The Connecticut Light and Power Company
3. Base Salary: $300,000
4. Sign-on Bonus: $100,000 of restricted shares and 10,000 stock options vesting over three years, and payment to prior employer on account of voluntary resignation.
5. Incentive Opportunities: Annual bonus and long term incentive program participation under NU Incentive Plan, each at 50 percent of salary target and 100 percent maximum.
6. Pension: Eligibility for the make-whole benefit under the Supplemental Executive Retirement Plan for Officers of Northeast Utilities System Companies (the SERP), and duplication of pension arrangement with current employer as follows: If he is continuously employed with the Company until September 10, 2011 (or earlier with the Company's permission), eligible for a special benefit, subject to reduction for termination prior to age 65, of three percent of Final Average Compensation (as defined in the SERP) for each of the 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 for Officers of Northeast Utilities System Companies, he may receive upon retirement a lump sum payment of $2,050,000 in lieu of the benefit described in the preceding sentence. These benefits are in lieu of the make-whole benefit and are offset by benefits payable under the Northeast Utilities Service Company Retirement Plan.
7. Previous pension: Payment of $8,830.46 per month in special nonqualified pension benefits on account of previous position in Northeast Utilities System at Millstone Station is paid concurrently with current employment.
8. Miscellaneous: Retiree health benefits upon involuntary termination other than for cause; leased vehicle; club membership; and five weeks vacation.
Summary prepared March 4, 2004
EXHIBIT 12
NORTHEAST UTILITIES
Ratio of Earnings to Fixed Charges
(Thousands of Dollars)
Year Year Year Year Year
1999 2000 2001 2002 2003
---- ---- ---- ---- ----
Earnings, as defined:
Net income before extraordinary item and
cumulative effect of accounting changes....... $ 34,216 $205,295 $220,124 $152,109 $121,152
Income taxes................................ 98,611 161,725 171,483 82,304 59,862
Equity in earnings of regional
nuclear generating and transmission
companies................................. (2,905) 13,667 3,090 11,215 4,487
Minority interest........................... 9,300 9,300 3,100 - -
Fixed charges, as below..................... 279,851 311,175 295,141 273,711 251,191
-------- -------- -------- -------- --------
Total earnings, as defined...................... $419,073 $701,162 $692,938 $519,339 $436,692
======== ======== ======== ======== ========
Fixed Charges, as defined:
Interest on long-term debt...................... $258,093 $200,696 $147,049 $134,471 $126,259
Interest on rate reduction bonds................ - - 87,616 115,791 108,359
Other interest.................................. 5,558 98,605 44,993 20,249 11,740
Rental interest factor - capital................ 13,700 8,657 13,144 600 2,300
Rental interest factor - 1/3 operating.......... 2,500 3,217 2,339 2,600 2,533
-------- -------- -------- -------- --------
Total fixed charges, as defined................. $279,851 $311,175 $295,141 $273,711 $251,191
======== ======== ======== ======== ========
Ratio of earnings to fixed charges................ 1.50 2.25 2.35 1.90 1.74
======== ======== ======== ======== ========
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Exhibit 21
SUBSIDIARIES OF THE REGISTRANT
State of
Incorporation
----------------
Northeast Utilities (a Massachusetts business trust) MA
The Connecticut Light and Power Company CT
CL&P Funding LLC DE
CL&P Receivables Corporation CT
Holyoke Water Power Company MA
Holyoke Power and Electric Company MA
North Atlantic Energy Corporation NH
North Atlantic Energy Service Corporation NH
Northeast Nuclear Energy Company CT
Northeast Utilities Service Company CT
NU Enterprises, Inc. CT
Select Energy Services, Inc. MA
Select Energy Contracting, Inc. MA
Mode 1 Communications, Inc. CT
Northeast Generation Company CT
Northeast Generation Services Company CT
E. S. Boulos Company CT
Woods Electrical Co., Inc. CT
Select Energy, Inc. CT
Select Energy New York, Inc. DE
Woods Network Services, Inc. CT
Public Service Company of New Hampshire NH
PSNH Funding LLC DE
PSNH Funding LLC 2 DE
The Quinnehtuk Company MA
The Rocky River Realty Company CT
Western Massachusetts Electric Company MA
WMECO Funding LLC DE
Yankee Energy System, Inc. CT
Yankee Gas Services Company CT
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EXHIBIT 23
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration Statement Nos. 33-34622, 333-55142, 33-40156, 333-105273 and 333-108712 on Forms S-3 and Nos. 33-44814, 33-63023, 333-52413, 333-52415, 333-63144 and 333-106008 on Forms S-8 of Northeast Utilities (the Company) of our reports dated February 23, 2004 (which express an unqualified opinion and include 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 and Financial Accounting Standards Board Interpretation No. 46, Consolidation of Variable Interest Entities) appearing in and incorporated by reference in this Annual Report on Form 10-K of Northeast Utilities for the year ended December 31, 2003.
/s/ Deloitte & Touche LLP
Deloitte & Touche LLP
Hartford, Connecticut
March 12, 2004
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EXHIBIT 31
CERTIFICATION PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, Charles W. Shivery, President of Northeast Utilities (the registrant), certify that:
1. I have reviewed this Annual Report on Form 10-K of the registrant;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over
financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-
15(f)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date: March 12, 2004
/s/ Charles W. Shivery
(Signature)
Charles W. Shivery
President
(Principal Executive Officer)
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EXHIBIT 31.1
CERTIFICATION PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, John H. Forsgren, Vice Chairman, Executive Vice President and Chief Financial Officer of Northeast Utilities (the registrant), certify that:
1. I have reviewed this Annual Report on Form 10-K of the registrant;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over
financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-
15(f)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date: March 12, 2004
/s/ John H. Forsgren
(Signature)
John H. Forsgren
Vice Chairman
Executive Vice President and
Chief Financial Officer
(Principal Financial Officer)
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EXHIBIT 32
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Annual Report of Northeast Utilities (the registrant) on Form 10-K for the period ending December 31, 2003 as filed with the Securities and Exchange Commission (the Report), we, Charles W. Shivery, President of the registrant and John H. Forsgren, Vice Chairman, Executive Vice President and Chief Financial Officer of the registrant, certify, pursuant to 18 U.S.C. Sec. 1350, as adopted pursuant to Sec. 906 of the Sarbanes-Oxley Act of 2002, that:
1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
2) The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the registrant.
/s/ Charles W. Shivery
(Signature)
Charles W. Shivery
President
/s/ John H. Forsgren
(Signature)
John H. Forsgren
Vice Chairman, Executive Vice President and
Chief Financial Officer
March 12, 2004
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A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the registrant and will be retained by the registrant and furnished to the Securities and Exchange Commission or its staff upon request.
EXHIBIT 31
CERTIFICATION PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, Cheryl W. Grise, Chief Executive Officer of The Connecticut Light and Power Company (the registrant), certify that:
1. I have reviewed this Annual Report on Form 10-K of the registrant;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over
financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-
15(f)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date: March 12, 2004
/s/ Cheryl W. Grise
(Signature)
Cheryl W. Grise
Chief Executive Officer
(Principal Executive Officer)
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EXHIBIT 31.1
CERTIFICATION PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, John H. Forsgren, Executive Vice President and Chief Financial Officer of The Connecticut Light and Power Company (the registrant), certify that:
1. I have reviewed this Annual Report on Form 10-K of the registrant;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over
financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-
15(f)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date: March 12, 2004
/s/ John H. Forsgren
(Signature)
John H. Forsgren
Executive Vice President and
Chief Financial Officer
(Principal Financial Officer)
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EXHIBIT 32
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Annual Report of The Connecticut Light and Power Company (the registrant) on Form 10-K for the period ending December 31, 2003 as filed with the Securities and Exchange Commission (the Report), we, Cheryl W. Grise, Chief Executive Officer of the registrant and John H. Forsgren, Executive Vice President and Chief Financial Officer of the registrant, certify, pursuant to 18 U.S.C. Sec. 1350, as adopted pursuant to Sec. 906 of the Sarbanes-Oxley Act of 2002, that:
1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
2) The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the registrant.
/s/ Cheryl W. Grise
(Signature)
Cheryl W. Grise
Chief Executive Officer
/s/ John H. Forsgren
(Signature)
John H. Forsgren
Executive Vice President and
Chief Financial Officer
March 12, 2004
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A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the registrant and will be retained by the registrant and furnished to the Securities and Exchange Commission or its staff upon request.
EXHIBIT 31
CERTIFICATION PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, Cheryl W. Grise, Chief Executive Officer of Public Service Company of New Hampshire (the registrant), certify that:
1. I have reviewed this Annual Report on Form 10-K of the registrant;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over
financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-
15(f)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date: March 12, 2004
/s/ Cheryl W. Grise
(Signature)
Cheryl W. Grise
Chief Executive Officer
(Principal Executive Officer)
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EXHIBIT 31.1
CERTIFICATION PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, John H. Forsgren, Executive Vice President and Chief Financial Officer of Public Service Company of New Hampshire (the registrant), certify that:
1. I have reviewed this Annual Report on Form 10-K of the registrant;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over
financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-
15(f)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date: March 12, 2004
/s/ John H. Forsgren
(Signature)
John H. Forsgren
Executive Vice President and
Chief Financial Officer
(Principal Financial Officer)
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EXHIBIT 32
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Annual Report of Public Service Company of New Hampshire (the registrant) on Form 10-K for the period ending December 31, 2003 as filed with the Securities and Exchange Commission (the Report), we, Cheryl W. Grise, Chief Executive Officer of the registrant and John H. Forsgren, Executive Vice President and Chief Financial Officer of the registrant, certify, pursuant to 18 U.S.C. Sec. 1350, as adopted pursuant to Sec. 906 of the Sarbanes-Oxley Act of 2002, that:
1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
2) The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the registrant.
/s/ Cheryl W. Grise
(Signature)
Cheryl W. Grise
Chief Executive Officer
/s/ John H. Forsgren
(Signature)
John H. Forsgren
Executive Vice President and
Chief Financial Officer
March 12, 2004
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A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the registrant and will be retained by the registrant and furnished to the Securities and Exchange Commission or its staff upon request.
EXHIBIT 31
CERTIFICATION PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, Cheryl W. Grise, Chief Executive Officer of Western Massachusetts Electric Company (the registrant), certify that:
1. I have reviewed this Annual Report on Form 10-K of the registrant;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over
financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-
15(f)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date: March 12, 2004
/s/ Cheryl W. Grise
(Signature)
Cheryl W. Grise
Chief Executive Officer
(Principal Executive Officer)
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EXHIBIT 31.1
CERTIFICATION PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, John H. Forsgren, Executive Vice President and Chief Financial Officer of Western Massachusetts Electric Company (the registrant), certify that:
1. I have reviewed this Annual Report on Form 10-K of the registrant;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over
financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-
15(f)) for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and
5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
Date: March 12, 2004
/s/ John H. Forsgren
(Signature)
John H. Forsgren
Executive Vice President and
Chief Financial Officer
(Principal Financial Officer)
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EXHIBIT 32
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Annual Report of Western Massachusetts Electric Company (the registrant) on Form 10-K for the period ending December 31, 2003 as filed with the Securities and Exchange Commission (the Report), we, Cheryl W. Grise, Chief Executive Officer of the registrant and John H. Forsgren, Executive Vice President and Chief Financial Officer of the registrant, certify, pursuant to 18 U.S.C. Sec. 1350, as adopted pursuant to Sec. 906 of the Sarbanes-Oxley Act of 2002, that:
1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
2) The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the registrant.
/s/ Cheryl W. Grise
(Signature)
Cheryl W. Grise
Chief Executive Officer
/s/ John H. Forsgren
(Signature)
John H. Forsgren
Executive Vice President and
Chief Financial Officer
March 12, 2004
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A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the registrant and will be retained by the registrant and furnished to the Securities and Exchange Commission or its staff upon request.