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
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(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
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The Connecticut Light and Preferred Stock, par value $50.00 per share, issuable in
Power Company 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
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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.
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).
The aggregate market value of Northeast Utilities' Common Shares, $5.00 Par Value, held by nonaffiliates, was $1,778,613,088 based on a closing sales price of $14.00 per share for the 127,043,792 common shares outstanding on February 28, 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, 2002:
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 March 27, 2003 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.
BMC............................... BMC Energy LLC
Boulos............................ E.S. Boulos Company
Citigroup......................... Citigroup, Inc.
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.
Dominion.......................... Dominion Resources, 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
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
NMEM.............................. Niagara Mohawk Energy Marketing, Inc.
NNECO............................. Northeast Nuclear Energy Company
NRG............................... NRG Energy, Inc.
NRG-PM............................ 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.
SENY.............................. Select Energy New York, 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
ARO............................... Asset Retirement Obligation
BFA............................... Business Finance Authority
CAAA.............................. Clean Air Act Amendments of 1990
DCA............................... Designated Congestion Areas
District Court.................... United States District Court for the
Southern District of New York
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
ICAP.............................. Installed Capability
Incentive Plan.................... Northeast Utilities Incentive Plan
ISO............................... Independent System Operator
ITC............................... Independent Transmission Company
kWh............................... Kilowatt-hour
LMP............................... Locational Marginal Pricing
Merger Agreement.................. Agreement and Plan of Merger, as
amended and restated as of January 11,
2000, between NU and Con Edison
MW................................ Megawatts
NEIL.............................. Nuclear Electric Insurance Limited
NEPOOL............................ New England Power Pool
NPDES............................. National Pollutant Discharge
Elimination System
NUG&T............................. Northeast Utilities Generation and
Transmission Agreement
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
ROC............................... Risk Oversight Council
ROE............................... Return on Equity
RRBs.............................. Rate Reduction Bonds
RRCs.............................. Rate Reduction Certificates
RTO............................... Regional Transmission Organization
SERP.............................. Supplemental Executive Retirement Plan
SFAS.............................. Statement of Financial Accounting
Standards
SMD............................... Standard Market Design
SPE............................... Special Purpose Entity
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
2002 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...................... 9
Competitive System Businesses................................... 11
Wholesale and Retail Marketing............................. 12
Energy Trading............................................. 14
Electric Generation........................................ 15
Competitive Energy Subsidiaries' Market
and Other Risks............................................ 15
Energy Management Services................................. 17
Telecommunications......................................... 18
Financing Program............................................... 19
2002 Financings............................................ 19
2003 Financing Requirements................................ 20
2003 Financing Plans....................................... 21
Financing Limitations...................................... 21
Construction and Capital Improvement Program.................... 26
Regulated Electric Operations................................... 27
Distribution and Sales..................................... 27
Regional and System Coordination........................... 27
Transmission Access and FERC Regulatory Changes............ 28
Regulated Gas Operations........................................ 30
Nuclear Generation.............................................. 30
General.................................................... 30
Nuclear Fuel............................................... 32
Decommissioning............................................ 33
Other Regulatory and Environmental Matters...................... 35
Environmental Regulation................................... 35
Electric and Magnetic Fields............................... 37
FERC Hydroelectric Project Licensing....................... 38
Employees....................................................... 39
Item 2. Properties................................................. 40
Item 3. Legal Proceedings.......................................... 44
Item 4. Submission of Matters to a Vote of Security Holders........ 50
PART II
Item 5. Market for Registrants' Common Equity and Related
Stockholder Matters........................................ 51
Item 6. Selected Financial Data.................................... 52
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations........................ 52
Item 7A. Quantitative and Qualitative Disclosures About
Market Risk................................................ 52
Item 8. Financial Statements and Supplementary Data................ 53
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure........................ 54
PART III
Item 10. Directors and Executive Officers of the Registrants........ 55
Item 11. Executive Compensation..................................... 59
Item 12. Security Ownership of Certain Beneficial Owners and
Management and Related Stockholder Matters................. 67
Item 13. Certain Relationships and Related Transactions............. 69
Item 14. Controls and Procedures.................................... 69
PART IV
Item 15. Exhibits, Financial Statement Schedules and
Reports on Form 8-K........................................ 71
Signatures and Certifications Pursuant to Section 302 of
the Sarbanes-Oxley Act of 2002....................................... 73
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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 409 cities and towns in Connecticut,
New Hampshire and western Massachusetts through three of NU's wholly-owned
subsidiaries (The Connecticut Light and Power Company [CL&P], Public Service
Company of New Hampshire [PSNH] and Western Massachusetts Electric Company
[WMECO]).
The NU system also furnishes franchised retail natural gas service in a large part of Connecticut through Yankee Gas Services Company (Yankee Gas), a subsidiary of Yankee Energy System, Inc. (Yankee), the largest natural gas distribution company in Connecticut. Yankee Gas serves approximately 191,000 residential, commercial and industrial customers in 70 cities and towns in Connecticut, including large portions of the central and southwest sections of the state.
NU, through its wholly owned subsidiary, NU Enterprises, Inc. (NUEI), owns a number of competitive energy and related businesses, including Northeast Generation Company (NGC), Northeast Generation Services Company (NGS), Select Energy, Inc. (Select Energy), Select Energy Services, Inc. (SESI; formerly HEC Inc.) and Mode 1 Communications, Inc. (Mode 1). Holyoke Water Power Company (HWP), a subsidiary of NU, is a resource of NUEI through an output contract. For information regarding the activities of these subsidiaries, see "Competitive System Businesses."
North Atlantic Energy Corporation (NAEC) is a wholly owned special-purpose operating subsidiary of NU that owned a 35.98 percent interest in the Seabrook station nuclear unit (Seabrook) in Seabrook, New Hampshire prior to its sale to the FPL Group, Inc. (FPL) in November 2002. North Atlantic Energy Service Corporation (NAESCO) had operational responsibility for Seabrook prior to its sale. Several other wholly owned subsidiaries of NU provide support services for the NU system companies and, in some cases, for other New England utilities. Northeast Utilities Service Company (NUSCO) provides centralized accounting, administrative, information technology, engineering, financial, legal, operational, planning, purchasing and other services to the NU system companies. Three other subsidiaries construct, acquire or lease some of the property and facilities used by the NU system companies.
The NU system is regulated in virtually all aspects of its business by various federal and state agencies, including the Securities and Exchange Commission (SEC), the Federal Energy Regulatory Commission (FERC), the Nuclear Regulatory Commission (NRC) and various state and/or local regulatory authorities with jurisdiction over the industry and the service areas in which each company operates, including the Connecticut Department of Public Utility Control (DPUC), the New Hampshire Public Utilities Commission (NHPUC) and the Massachusetts Department of Telecommunications and Energy (DTE). In recent years, there has been significant legislative and regulatory activity changing the nature of regulation of the industry. For more information regarding these restructuring initiatives, see "Rates and Electric Industry Restructuring" and "Regulated Electric Operations."
SAFE HARBOR STATEMENT UNDER THE PRIVATE SECURITIES
LITIGATION REFORM ACT OF 1995
In connection with the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 (Reform Act), NU and its reporting subsidiaries are hereby filing cautionary statements identifying important factors that could cause NU or its subsidiaries' actual results to differ materially from those projected in forward looking statements (as such term is defined in the Reform Act) made by or on behalf of NU or its subsidiaries in this combined Form 10-K, in any subsequent filings with the SEC, in presentations, in response to questions, or otherwise. Any statements that express or involve discussions as to expectations, beliefs, plans, objectives, assumptions or future events, or performance (often, but not always, through the use of words or phrases such as will likely result, are expected to, will continue, is anticipated, estimated, projection, outlook) are not statements of historical facts and may be forward looking. Forward looking statements involve estimates, assumptions and uncertainties that could cause actual results to differ materially from those expressed in the forward looking statements. Accordingly, any such statements are qualified in their entirety by reference to, and are accompanied by, the following important factors that could cause NU or its subsidiaries' actual results to differ materially from those contained in forward looking statements of NU or its subsidiaries made by or on behalf of NU or its subsidiaries.
Any forward looking statement speaks only as of the date on which such statement is made, and NU and its subsidiaries undertake no obligation to update any forward looking statement or statements to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time and it is not possible for management to predict all of such factors, nor can it assess the impact of each such factor on the business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward looking statements.
Some important factors that could cause actual results or outcomes to differ materially from those discussed in the forward looking statements include prevailing governmental policies and regulatory actions, including those of the SEC, the NRC, the FERC, and state regulatory agencies, with respect to allowed rates of return, industry and rate structure, operation of nuclear power facilities, acquisition and disposal of assets and facilities, operation and construction of plant facilities, recovery of purchased-power costs, stranded costs, decommissioning costs, and present or prospective wholesale and retail competition (including but not limited to retail wheeling and transmission costs).
The business and profitability of NU and its subsidiaries are also influenced by economic and geographic factors including political and economic risks, changes in environmental and safety laws and policies, weather conditions (including natural disasters), population growth rates and demographic patterns, competition for retail and wholesale customers, pricing and transportation of commodities, market demand for energy from plants or facilities, changes in tax rates or policies or in rates of inflation, changes in project costs, unanticipated changes in certain expenses and capital expenditures, capital market conditions, competition for new energy development opportunities, and legal and administrative proceedings (whether civil or criminal) and settlements.
All such factors are difficult to predict, contain uncertainties which may materially affect actual results and are beyond the control of NU or its subsidiaries.
RATES AND ELECTRIC INDUSTRY RESTRUCTURING
GENERAL
NU's electric utility subsidiaries, CL&P, WMECO and PSNH, have undergone fundamental changes in their business operations as a result of the restructuring of the electric industry in their respective jurisdictions. The year 2002 represented the final year of a four-year process of selling most of the regulated generating assets of the NU system. Most notably, CL&P and WMECO have divested all of their generation assets and are acting solely as transmission and distribution companies, while divestiture of PSNH's fossil and hydro generation has been postponed by state statute until at least 2004. All operating company customers are now able to choose their energy suppliers, with the electric utility companies furnishing "standard offer," "default" or "transition" service to those customers who do not choose a competitive supplier. Critical to this restructuring is the companies' ability to recover their stranded costs. Stranded costs are expenditures incurred, or commitments for future expenditures made, on behalf of customers with the expectation such expenditures would continue to be recoverable in the future through rates.
As discussed more fully below, CL&P and WMECO have received regulatory orders allowing each to recover all or substantially all of their prudently incurred stranded costs. Under an April 2000 settlement agreement among NU, PSNH and the State of New Hampshire (Restructuring Settlement), which has been approved by the NHPUC, PSNH is entitled to recover all of its remaining prudently incurred stranded costs. All three companies have recovered significant portions of their stranded costs through the issuance of rate reduction bonds (RRBs) and rate reduction certificates (RRCs) (securitization) and are recovering these costs through rates.
Electric utility restructuring in Connecticut, New Hampshire and Massachusetts provides for a transition period of several years following the opening of each state's electric market to customer choice. During that interim period, the energy delivery companies, including CL&P, WMECO and PSNH, are responsible for arranging for the supply of power to customers who do not select alternative energy suppliers. Management recognizes that in other states electric companies have been negatively affected by the inability to recover supply costs on a timely basis. However, the Company believes that current statutes and regulatory policy in the three states in which NU subsidiaries operate electric delivery businesses will permit timely recovery.
CL&P has signed fixed-price contracts with three suppliers who together will serve all of CL&P's standard offer requirements through 2003. One of these suppliers is the company's competitive marketing affiliate, Select Energy, and the other two suppliers, NRG Power Marketing, Inc. (NRG-PM) and Duke Energy Trading and Marketing Northeast, LLC (Duke Energy), are unaffiliated with CL&P. CL&P is fully recovering all of the payments it is making to those suppliers and has limited financial guarantees from each unaffiliated supplier to shield CL&P from risk in the event any of the suppliers encounters financial difficulties. See "Connecticut Rates and Restructuring."
After a competitive solicitation, WMECO signed supply agreements for standard offer service in November 2002 for the 2003 calendar year. Select Energy was the winning bidder. The DTE approved the standard offer contract and approved rates, which will allow WMECO to recover fully its standard offer service supply costs. In addition, in Massachusetts there is a second type of service supplied by electric distribution companies called default service. Default service is provided to those customers not on competitive supply that are not eligible for standard offer service. A single unaffiliated supplier won the competitive solicitation to provide default service to WMECO for the period January 1, 2003, through June 30, 2003. Default service supply for the second half of the year will be solicited in the spring of 2003.
Retail competition for all PSNH customers began on May 1, 2001. PSNH provides transition service energy to its retail customers from its owned generating plants, from purchase power obligations and from market purchases. See "New Hampshire Rates and Restructuring."
CONNECTICUT RATES AND RESTRUCTURING
Since retail competition began in Connecticut in 2000, an extremely small number of CL&P customers (about 20,000 out of 1.2 million CL&P customers) have opted to choose their retail supplier. Through December 2003, 50 percent of CL&P's standard offer supply requirements will be purchased from Select Energy, 45 percent from NRG-PM, and 5 percent from Duke Energy.
In November 2001, at the request of NRG-PM, CL&P filed a request with the DPUC to raise the standard offer rate from an average of $0.0495 per kilowatt- hour (kWh) to $0.0595 per kWh, which would help promote competition in advance of the January 1, 2004 termination of the standard offer period and provide financial relief to standard offer suppliers. In December 2001, the DPUC rejected CL&P's request, but opened two new dockets to examine the absence of effective retail competition in Connecticut and the financial condition of the suppliers. The first docket culminated in a joint study report issued in a DPUC decision on February 15, 2002, which provided the DPUC's and the Connecticut Office of Consumer Counsel's (OCC) findings on how to best structure default service and other issues related to electric industry restructuring. In the second docket, the DPUC concluded on June 17, 2002, "that there does not exist either a legal or factual basis upon which to find probable cause to commence further proceedings regarding the standard offer generation service charge."
On July 18, 2002, CL&P, concerned with NRG-PM's financial viability, filed a new proposal with the DPUC to maintain current total rates, but to shift $0.007 per kWh from being used to accelerate the amortization of stranded costs to instead provide additional payments to NRG-PM and Select Energy. The payments to NRG-PM would help ensure that there are adequate available generating units to maintain electric reliability in the near term in southwest Connecticut. On July 26, 2002, the DPUC denied the request, indicating that it expects CL&P to enforce the current standard offer contracts. Subsequent to July 26, NRG-PM announced that it entered an agreement with ISO-New England to keep three units at its Devon, Connecticut station in service. Under the terms of the agreement, NRG-PM will be provided compensation to continue operating the units until the end of the agreement on September 30, 2003. These units will accordingly remain available until ISO-New England determines that they are no longer needed for reliability. Based on this information and the fact that there were no further issues brought to the DPUC's attention, the docket was closed on August 29, 2002.
In light of recent downgrades of NRG Energy, Inc., NRG-PM's parent company (NRG), by all three major rating companies to below minimum investment grade levels, NU continues to evaluate NRG-PM's financial health. If CL&P is required to seek an alternate source of supply, CL&P would pursue recovery of any additional costs from NRG-PM pursuant to the contract. In the event NRG-PM did not pay such costs, CL&P may be required to seek DPUC approval to flow through any such costs, including any increased payments to its other standard offer service suppliers, to its customers. On February 21, 2003, Fitch Ratings lowered its ratings outlook on CL&P to negative as a result of its concern over timely recovery of higher purchased-power costs if NRG-PM were to default on its CL&P standard offer obligations. Management believes that recovery of these costs would be consistent with the provisions of Connecticut's electric utility restructuring legislation and all other ratings outlooks on CL&P remain stable. In view of the deterioration of NRG's financial condition, CL&P exercised its contractual right to withhold past due congestion costs from the July 2002 standard offer payment to NRG-PM pending the outcome of litigation between the parties concerning contractual liability for congestion costs ongoing in the United States District Court for the District of Connecticut. All subsequent standard offer payments to NRG-PM have similarly been reduced to reflect continued withholding of congestion costs.
On December 20, 2002, FERC issued an order in connection with a dispute between CL&P and NRG concerning the provision of station service to Connecticut generating plants purchased from CL&P by NRG affiliates in December 1999. CL&P filed a complaint at FERC seeking interpretation of a FERC-filed interconnection agreement in which NRG agreed to pay CL&P's applicable retail rates for station service power (if procured from CL&P) and delivery of such power (whether procured from CL&P or a third party supplier). FERC further affirmed the language in its Order 888 concerning state jurisdiction over the delivery of power to end users, even in the absence of distribution facilities, and the state's authority to impose certain charges on end users, such as those associated with stranded cost recovery. CL&P has made a demand upon NRG for payment of $13.3 million in station service charges through January 2003 and is preparing to take any steps necessary to collect the unpaid balance. For further information relating to NRG-related litigation, see Item 3, "Legal Proceedings."
On September 27, 2001, CL&P filed its application with the DPUC for approval of the disposition of the proceeds from the sale of the Millstone nuclear units (Millstone) to Dominion Nuclear Connecticut, Inc. (DNCI). This application described and requested DPUC approval for CL&P's treatment of its share of the proceeds from the sale, including CL&P's recovery of approximately $75 million of capital additions at Millstone during the approximately four years prior to sale. On February 27, 2003, the DPUC issued a final decision in this docket requiring a $26.9 million increase in the amount of proceeds CL&P had proposed to be applied to stranded costs.
On May 17, 2002, CL&P filed an application with the DPUC for approval of the auction results in the sale of Seabrook to a subsidiary of FPL. A final decision approving the sale was issued in September 2002 and the sale closed on November 1, 2002.
On November 23, 2001, CL&P petitioned the DPUC to adjust its stranded costs to account for the announced sale of the Vermont Yankee nuclear unit (VY) to an unaffiliated company. On June 12, 2002, the DPUC issued a final decision that found CL&P's request was beneficial to ratepayers and allowed for stranded cost recovery through the Competitive Transition Assessment.
CL&P was unable to negotiate buy down or buy out arrangements with 15 independent power producers (IPPs) that produce approximately 345 megawatts (MW). CL&P is selling the output from these projects into the market and will, pursuant to DPUC authority, continue to collect the difference between the contract prices and the market revenues as stranded costs. These stranded costs cannot be securitized.
As of December 31, 2002, CL&P had fully recovered all stranded costs except those to be recovered through RRBs, ongoing IPP costs, costs associated with the ongoing decommissioning of the Maine Yankee, Connecticut Yankee and Yankee Rowe nuclear units and annual decontamination and decommissioning costs payable under federal law.
In December 2000, the Attorney General of the State of Connecticut (AG) and the OCC each filed a petition requesting that the DPUC initiate a proceeding to consider whether an interim decrease in the rates charged by CL&P is required. The applicable statute requires the DPUC to commence a special public hearing on the need for an interim rate decrease when, among other reasons, a public service company has for six consecutive months earned a return on equity (ROE) that exceeds the return authorized by the DPUC by at least one percentage point. In June 2001, the DPUC concluded its investigation on potential overearnings by CL&P and ordered a $21.1 million reduction in CL&P's electric transmission and distribution rates and an equal increase in CL&P's generation services charge. The DPUC also implemented an earnings sharing mechanism under which earnings in excess of a 10.3 percent authorized ROE are shared equally by shareholders and ratepayers. In September 2001, the DPUC ordered a $21.3 million annual reduction in CL&P's System Benefits Charge as a result of a sharp reduction in decommissioning collections and an equal increase in the competitive transition assessment, effective March 1, 2002. The net result of the decisions noted above was to reduce CL&P's pretax earnings by $21.1 million beginning June 20, 2001, and accelerate CL&P's recovery of stranded costs in 2002 and 2003. For the twelve-month period ended June 30, 2002, CL&P overearned its allowed 10.3 percent ROE by .23 percent, resulting in an approximate $1 million reduction in stranded costs.
In July 2001, the DPUC authorized CL&P to assess a charge of approximately $0.002 per kWh through December 2003 to collect approximately $98.5 million of deferred fuel costs, including carrying costs, primarily incurred prior to January 1, 2000.
In December 2001, the AG filed a petition seeking an investigation into CL&P's potential overearnings. On February 6, 2002, the DPUC rejected the petition.
In mid-2003, CL&P expects to file a distribution rate case with the DPUC for rates that would be effective January 2004. Also, in the second half of 2003, CL&P will need to secure bids for power supply contracts to meet the needs of its customers for 2004. Management has not yet identified what level of rates it will request in 2004.
On December 2, 2002, the Connecticut Siting Council (CSC) resumed hearings on CL&P's proposed $135 million project to build a new 345,000-volt transmission line between Bethel and Norwalk, Connecticut. A final decision on the project is expected by mid-April 2003. CL&P expects to file with the CSC later in 2003 to build a 65-mile 345,000-volt line between Norwalk and Middletown, Connecticut. The two projects are needed to resolve a host of growth-related problems in the import-dependent Norwalk-Stamford and southwest Connecticut load pockets. For additional information on CL&P's proposed expansion of its transmission system, see "Construction and Capital Improvement Plan."
On March 1, 2003, ISO-New England implemented a new Standard Market Design (SMD). As part of this effort, locational marginal pricing (LMP) will be utilized to assign value and causation to transmission congestion. Transmission congestion costs will be assigned to the load zone in which the congestion occurs. Those costs are now spread across virtually all New England electric customers. In addition, the implementation of SMD will impact wholesale energy contracts with respect to the energy delivery points contained in these contracts. See "Competitive System Businesses-Wholesale and Retail Marketing."
Connecticut has been designated a single load zone. Due to transmission constraints and inadequate generation Connecticut could experience significant additional congestion costs under SMD. The New England ISO has estimated that the costs of transmission congestion for 2003 in New England under SMD will range between $50 million and $300 million. ISO-New England estimates that the majority of this congestion and its costs will be in Connecticut, where approximately 80 percent of those costs are expected to be paid by CL&P beginning on March 1, 2003. CL&P believes that under the terms of its standard offer service contracts with its standard offer suppliers, these costs are its responsibility. The contracts with the standard offer suppliers expire on December 31, 2003. In addition, the determination of the energy delivery points associated with the standard offer service contracts under SMD could also produce significant costs for CL&P that management cannot determine at this time.
Another factor affecting the level of congestion costs is the designation of certain generating units by ISO-New England as units needed for system reliability. Some of the companies owning these units have applied to the FERC for "reliability must run" (RMR) treatment. RMR treatment allows these units to receive cost of service based payments that recognize their reliability value. Prior to March 1, 2003, all RMR costs were spread across New England with all utilities being billed by ISO-New England based upon their share of New England's load. NU's regulated electric utilities were responsible for approximately 25 percent of these costs. Effective with the March 1, 2003 implementation of SMD by ISO-New England, RMR costs will be allocated to the load zone in which the RMR unit is located. At present, the only load zone that will experience a cost increase in which a NU regulated electric company operates is Connecticut. With respect to the Connecticut load zone, there are two generating units operating under a RMR contract with an additional contract pending before FERC. These contracts are for one year terms, and one contract contains an extension option. On a combined basis, these two RMR contracts will result in an annual cost of approximately $45 million to the Connecticut load zone. CL&P accounts for approximately 80 percent of the Connecticut load zone, and would be responsible for approximately $36 million of this cost. In the near future, it is probable that there will be significant new requests for RMR treatment in Connecticut which, if approved by FERC, would add significant additional costs to the total cost of energy in Connecticut. However, generating units operating under RMR contracts could potentially mitigate the overall level of congestion costs.
These unavoidable congestion and RMR costs are part of the prudent cost of providing regulated electric service in Connecticut. A DPUC regulatory proceeding is expected to be initiated soon to determine the appropriate recovery mechanism for these costs. If these costs are incurred before the final recovery mechanism is established by the DPUC, CL&P expects to record a regulatory asset for those costs incurred.
In response to the regional transmission expansion plan prepared by ISO- New England, CL&P has advised ISO-New England that it will seek to obtain approximately 60 to 80 MW of peaking capacity to be located in southwest Connecticut for the summer of 2003. CL&P is also seeking a longer-term solution to the peaking capacity needs of southwest Connecticut.
For further information on SMD and transmission-related issues, see "Regulated Electric Operations - Transmission Access and FERC Regulatory Changes."
In July 2001, Yankee Gas filed an application to increase customers' rates by approximately $29.2 million, or an average of 7.64 percent. Yankee Gas requested the increase to fund system reliability projects and a proposed expansion of its distribution system. On January 30, 2002, the DPUC issued a final decision in the case, ordering a $4.0 million reduction in Yankee Gas rates, which became effective April 1, 2002. The DPUC authorized Yankee Gas' distribution expansion plan, subject to annual reviews, and approved, with some conditions, its capital investment ratemaking recovery mechanism (Infrastructure Expansion Rate Mechanism or IERM). The final decision also authorized an 11 percent ROE for Yankee Gas and a sharing formula for earnings above that level from 2002 through 2005. On August 1, 2002, Yankee Gas filed testimony and exhibits with the DPUC reflecting its proposal for IERM projects to be placed in-service during the period July 1, 2002 through December 31, 2003 and that meet certain financial criteria outlined by the DPUC. Yankee Gas is currently proposing no IERM charge for 2003 and that any over-collection for 2003 be carried forward to the 2004 IERM period. A decision in this docket is expected in the first quarter of 2003.
On December 4, 2002, the DPUC opened a docket to review Yankee Gas earnings in excess of its authorized ROE. Hearings are scheduled for March 2003 and a decision is expected in May 2003.
A schedule has been set in Yankee Gas' proceeding before the DPUC to obtain rate approval to build a two billion cubic foot liquefied natural gas production and storage facility in Waterbury, Connecticut. The rate schedule includes hearings in March 2003 with a final decision in the second quarter of 2003. If approved, construction of the facility, which could cost approximately $60 million, could begin in the fourth quarter of 2003.
MASSACHUSETTS RATES AND RESTRUCTURING
Massachusetts enacted comprehensive electric utility industry restructuring in November 1997. That legislation required each electric company to submit a restructuring plan and to reduce its rates by 15 percent adjusted for inflation by September 1999. The 15 percent rate reduction is a rate cap for standard offer service customers that extends until February 2005, the end of the restructuring transition period. The restructuring plan approved by the DTE in 1999 allows WMECO's customers to choose their energy suppliers and WMECO to recover stranded costs. Two parties have appealed the DTE's decision on WMECO's restructuring plan to the Massachusetts Supreme Judicial Court. One appeal has been dismissed without prejudice by the Supreme Judicial Court because the appellant has failed to prosecute the appeal. There has been no significant action in the other appeal since it was filed in December 1999.
In December 2002, the DTE approved a 1.8 percent increase in WMECO's overall bills, primarily reflecting slightly increased standard offer service and default service costs as well as other inflationary factors. See "Rates and Electric Industry Restructuring-General" information relating to WMECO's standard offer service and default service supply.
During the first quarter of 2000, WMECO filed its first annual stranded cost reconciliation filing covering the period March 1, 1998 through December 31, 1999. The DTE issued its decision on this filing on June 7, 2002. The decision included, among other things, a ruling that investment tax credits associated with generation assets that have been divested should not be used to reduce rates. As a result, WMECO recognized approximately $13 million in tax credits in the second quarter of 2002.
On March 30, 2001, WMECO filed its second annual stranded cost reconciliation with the DTE for calendar year 2000. On March 29, 2002, WMECO filed its 2001 annual transition cost reconciliation with the DTE for calendar year 2001. Included in that filing were the sales proceeds from WMECO's interest in Millstone, the impact of securitization and approximately a $13 million benefit to ratepayers from WMECO's performance-based ratemaking process. On July 8, 2002, WMECO submitted a compliance filing in accordance with the DTE's June 7, 2002 order in WMECO's 1998-1999 stranded cost reconciliation proceedings. This filing reflected changes to the 1998 through 1999 reconciliations as agreed to by WMECO and/or ordered by the DTE and also included a revised transition charge filing for 2000 and 2001 to reflect the June 7, 2002 order. Subsequent to the July 8, 2002 filing, WMECO and the office of the Massachusetts Attorney General reached a settlement covering all transition charge issues for the 1998 through 2001 reconciliations. This settlement was approved by the DTE on December 27, 2002. The after-tax impact of this settlement increased 2002 earnings by approximately $5.7 million.
NEW HAMPSHIRE RATES AND RESTRUCTURING
In July 2001, the NHPUC opened a docket to review the fuel and purchased- power adjustment clause (FPPAC) costs incurred by PSNH between August 2, 1999 and April 30, 2001, in order to determine the amount of deferred FPPAC costs PSNH should be entitled to recover through the stranded cost recovery charge. Hearings at the NHPUC concluded in June 2002, and PSNH filed its closing brief with the NHPUC in July 2002. Under the Restructuring Settlement, FPPAC deferrals are recovered as Part 3 stranded costs through the stranded cost recovery charge. On December 31, 2002, the NHPUC approved the recovery of all but $17,000 of PSNH's request to recover approximately $200 million.
On June 28, 2002, PSNH made its first stranded cost recovery charge reconciliation filing with the NHPUC for the period May 1, 2001 through December 31, 2001. This filing reconciles stranded cost revenues against actual stranded costs with any difference being refunded to customers or deferred for future recovery. Included in the stranded cost charges are the net generation revenues and generation cost charges for the filing period. Where generation revenues exceed costs, additional stranded costs were amortized; where generation costs exceed revenues, costs were deferred for future recovery. The generation costs included in this filing are subject to a prudence review by the NHPUC. PSNH entered into a settlement with the NHPUC staff and the Office of Consumer Advocate recommending that the NHPUC find that all of PSNH's generation costs were prudently incurred. The NHPUC held a hearing on January 8, 2003 and a decision was issued on February 14, 2003, effectively adopting the terms of the settlement.
On September 12, 2002, the NHPUC issued a final decision approving the auction results in the sale of Seabrook to FPL. Under the terms of the Settlement Agreement, PSNH non-securitized stranded costs will be reduced by the net proceeds from NAEC's ownership interest in Seabrook. To date, NAEC has credited PSNH with approximately $179 million through the contracts under which PSNH was obligated to purchase NAEC's ownership of the output and capacity of Seabrook (Seabrook Power Contracts). These credits are being used to offset Part 3 stranded costs, which are nonsecuritized regulatory assets which must be recovered by a recovery end date determined in accordance with the Restructuring Settlement or be written off.
In 2002, NAEC supplied PSNH with approximately 2.74 billion kWh. PSNH fossil and hydroelectric units generated 3.52 billion kWh and PSNH purchased another 4.67 billion kWh, some under long-term rate orders with small power producers based in New Hampshire. Of that total 10.93 billion kWh, 7.91 billion kWh were used to service PSNH's retail electric customers and the remaining 3.02 billion kWh were sold in the wholesale market. As a result of NAEC's sale of Seabrook, PSNH expects its wholesale electric sales to decline significantly in 2003. However, PSNH expects to generate most of the electricity it needs to serve transition service for its customers from its own generating plants or purchased-power obligations and to purchase the remainder in the wholesale market.
On December 5, 2002, PSNH announced an agreement to acquire the franchise and electric system of Connecticut Valley Electric Company, Inc. (CVEC), a subsidiary of Central Vermont Public Service Corporation (CVPS) that serves approximately 10,000 customers in western New Hampshire. Under the agreement, PSNH will pay CVPS approximately $9 million for its assets and an additional $21 million to terminate a wholesale power contract between CVPS and CVEC. Customers of CVEC will become customers of PSNH, whose residential rates are now approximately 20 percent lower than those of CVEC. PSNH will be allowed to recover the $21 million payment with a return consistent with Part 3 stranded cost treatment under the Restructuring Settlement. Part 3 stranded costs are nonsecuritized regulatory assets which must be recovered by a recovery end date determined in accordance with the Restructuring Settlement or be written off. The sale agreement is supported by the New Hampshire Governor's Office, NHPUC staff, the state Office of Consumer Advocate, the City of Claremont and New Hampshire Legal Assistance. The FERC and the NHPUC must approve the sale, which is expected to become effective on January 1, 2004.
On February 1, 2003, in accordance with New Hampshire law, PSNH raised the transition service rate for residential and small commercial customers to 4.60 cents per kWh from 4.40 cents per kWh. On the same date, pursuant to New Hampshire law and order of the NHPUC, PSNH also raised its transition supply rate for large commercial and industrial customers to 4.67 cents per kWh from 4.40 cents per kWh. PSNH expects those rates to be adequate to recover its generation and power purchased-power costs, including the recovery of carrying costs on PSNH's generation investment. If recoveries exceed PSNH's costs, those overrecoveries will be credited against PSNH's Part 3 stranded cost balance. If actual costs exceed those recoveries, PSNH will defer those costs for future recovery from customers through its Stranded Cost Recovery Charge.
PSNH's delivery rates are fixed until February 1, 2004. Under the Restructuring Settlement, PSNH must file a rate case by December 31, 2003 for the purpose of commencing a review of PSNH's delivery rates.
COMPETITIVE SYSTEM BUSINESSES
NU is engaged in a variety of competitive businesses which are primarily involved in the marketing of electricity and natural gas in the Northeast United States and the provision of energy related services to large government, industrial, commercial and institutional facilities. NU's competitive businesses operate four major business units: wholesale marketing, retail marketing, energy trading and energy products and services.
NUEI is the lead competitive energy business within NU. NUEI is a wholly owned subsidiary of NU and acts as the holding company for certain of NU's competitive energy subsidiaries. These subsidiaries include SESI, a provider of energy management, demand-side management and related consulting services for commercial, industrial and institutional customers and electric utility companies; NGC, a corporation that acquires and manages generation facilities; NGS, a corporation that maintains and services fossil and hydroelectric facilities, and Select Energy, a corporation engaged in the trading, marketing, transportation, storage and sale of energy commodities, at wholesale and retail, in designated geographical areas. NUEI and its integrated competitive energy business affiliates had aggregate revenues of approximately $1.7 billion in 2002 as compared to approximately $2.1 billion in 2001 and lost $54.1 million in 2002, as compared to earnings of approximately $5 million (before extraordinary items) in 2001.
NGC is the competitive generating subsidiary of NU and a major provider of pumped storage and conventional hydroelectric power in the northeastern United States. NGC owns and operates a portfolio of approximately 1,291 MW of generating assets in New England. The generation facilities owned by NGC were acquired at auction from CL&P and WMECO. NGC's portfolio consists of seven hydro facilities along the Housatonic River System (121 MW), the three facilities comprising the Eastern Connecticut System, including one gas turbine (28 MW), all located in Connecticut, and the Northfield Mountain pumped storage station (1,080 MW) and the Cabot and Turners Falls No. 1 hydroelectric stations (62 MW) located in Massachusetts. NGC sells all its generation output to Select Energy, which in turn markets it to customers. Select Energy's performance under its contract with NGC is guaranteed by NU through 2005.
Select Energy also buys and manages the entire generation output of HWP, which consists of approximately 147 MW generated at the Mt. Tom station in Holyoke, Massachusetts under a renewable contract.
NUEI's deregulated operations are a core business of NU. NGC's assets and Mt. Tom perform functions that are critical to NUEI's wholesale and retail businesses by providing Select Energy with access to electric generation within New England and thus reducing its exposure to energy price fluctuations.
WHOLESALE AND RETAIL MARKETING
NUEI, through Select Energy, sells multiple energy products including electricity and natural gas to wholesale and retail customers in the northeastern United States. Select Energy procures and delivers energy and capacity required to serve its electric and gas customers. Select Energy is one of the largest wholesale and retail electric energy marketers in New England as measured by megawatt load. In order to support and complement its growing wholesale and retail business, Select Energy contracted in December of 1999 with NGC to purchase and market all of NGC's 1,291 MW for a 6-year period. In addition, during 2002 Select Energy purchased approximately 147 MW of coal generating plant output from its affiliate, HWP, and more than 2,800 MW of electrical supply from various New England generating facilities on a long-term basis to meet its New England load obligations. Select Energy may also utilize generation failure insurance, options and energy futures to hedge its supply requirements. NUEI also offers energy management consulting and construction services through its affiliate, SESI, discussed more fully below.
In 2002, Select Energy reported revenues of $1.5 billion and had retail and wholesale marketing sales of approximately 26,000 gigawatt-hours (GWh) of electricity and 52 billion cubic feet (BcF) of natural gas to approximately 19,000 customers. During 2001, Select Energy reported revenues of $1.9 billion and had retail and wholesale marketing sales of approximately 25,000 GWh of electricity and 32 BcF of natural gas to approximately 18,000 customers. Twelve months of operations from Select Energy New York, Inc. are reflected in 2002 versus one month of operations in 2001.
There are a number of large energy companies bidding for business in the restructured Northeast market. During 2002, the breadth and depth of the market for energy trading and marketing products in Select Energy's market was adversely affected by the withdrawal or financial weakening of a number of companies who have historically done significant amounts of business with Select Energy. In general, the market for such products has become shorter term and less liquid in nature and participants are more often unable to meet Select Energy's credit standards without additional credit support. Select Energy's business has been adversely affected by these factors and they could continue to adversely affect Select Energy's results in 2003.
Changes are occurring in the administration of transmission systems in territories in which Select Energy does business. Regional transmission organizations (RTO) are being contemplated, and other changes in market design are occurring within transmission regions. For example, SMD was implemented in New England on March 1, 2003 and will create challenges and opportunities for Select Energy. The impact of SMD on the wholesale marketing business could be significant. The determination of the energy delivery points in many wholesale marketing contracts and the location of sources of supply could have a significant effect on Select Energy. As more information regarding the timing and impact of SMD becomes available, there could be additional adverse effects that management cannot determine at this time. For more information on the proposed changes, see "Regulated Electric Operations-Transmission Access and FERC Regulatory Charges" and "Rates and Electric Industry Restructuring- Connecticut Rates and Restructuring."
Wholesale Marketing. Select Energy's goal is to be the regional leader in providing electric service to the Northeastern competitive markets. In 2002, Select Energy supplied more than 5,600 MW of standard offer and default service load in the region, making it one of the largest providers of standard offer service in the Northeast. Revenues from these services comprised in the aggregate approximately 70 percent of Select Energy's 2002 revenues.
On January 1, 2000, Select Energy began serving one half of CL&P's standard offer load for a four-year period at fixed prices. This equates to approximately 2,000 MW annually for each of the four contract years. Approximately 38 percent of Select Energy's 2002 competitive energy revenues came from CL&P's supply contract. Although Select Energy lost an estimated $47 million on this arrangement last year, in 2003 Select Energy expects improved results due to more favorable purchase contracts. A return to normal river conditions at NGC's hydroelectric plants, in contrast to the near-drought conditions New England experienced during much of 2002, is also expected to improve results. In 2003, Select Energy will also focus on improved management of power supply associated with its full requirements contracts. To meet its profit target in 2003, Select Energy must also secure a significant amount of new business at acceptable margins. Management expects Select Energy's wholesale marketing business will be profitable in 2003.
In addition to its contract with CL&P, Select is serving 2,100 MW of New Jersey's basic generation supply (BGS) load through July 31, 2003, 1,200 MW of BGS load from August 1, 2003 through May 31, 2004, and 500 MW of BGS load from June 1, 2004 through May 31, 2006. In addition, on January 1, 2003, Select Energy began serving the 500 MW standard offer load of its affiliate, WMECO, for a 12 month period. There are also approximately 300 MW of fixed price market-based wholesale contracts throughout New England that were previously supplied by WMECO and CL&P that are now the responsibility of Select Energy.
Retail Marketing. Select Energy is licensed to provide retail electric supply in Connecticut, Delaware, Maryland, New Jersey, Maine, Pennsylvania, Virginia, New York, Massachusetts, Rhode Island and New Hampshire. Within these states, Select Energy is currently registered with approximately 36 electric distribution companies and 51 gas distribution companies to provide retail services.
As of December 31, 2002, Select Energy had contracts with retail electric customers in states throughout the Northeast with over 900 MW of peak load at 13,000 locations, including predominately commercial, industrial, institutional and governmental accounts. As over 600 MW of this load is in New England, Select Energy is among the largest competitive retail suppliers of electricity in New England as measured by megawatt load. No single retail electric customer accounts for more than ten percent of Select Energy's expected retail revenues.
Select Energy's retail marketing business had far weaker performance in 2002, when it lost approximately $28 million, than in 2001, when it lost approximately $8 million, prior to a $22.4 million accounting change. The weaker performance is attributed to unusually warm weather in the first quarter of 2002, which particularly affected retail gas sales, and to unfavorable retail supply contracts, many of which were terminated by the end of 2002. Select Energy expects its retail marketing business to break even in 2003. In order to achieve this goal, Select Energy plans to size the retail organization to better fit the expected level of business and to better manage volumetric risk, particularly in the winter heating months. This goal also assumes that Select Energy will be successful in securing and managing a significant amount of new business at acceptable margins.
During 2002, Select Energy's competitive natural gas business, primarily retail in nature, produced revenues of approximately $247 million, an increase from 2001 revenues of approximately $200 million. This increase was due to changes in gas prices and increased volume. As of December 31, 2002, Select Energy provided over 39 BcF of natural gas to approximately 6,000 retail gas customers, primarily located in Connecticut, Massachusetts and Pennsylvania. These contracts generally have one-year terms and include primarily commercial, institutional, industrial and governmental accounts. No single retail gas customer accounts for more than ten percent of Select Energy's expected retail gas revenues. In 2002, Select Energy's retail gas revenues were approximately $180 million representing approximately a 13 percent increase compared to 2001.
ENERGY TRADING
Select Energy trades a number of energy-related products in the Eastern United States, primarily for price discovery and risk management purposes. The trading segment of the business can buy, sell, hold or trade any energy futures, options, third party or counter-party positions for energy commodities. The energy trading business also includes entering into associated risk management products, including derivatives, as part of managing the exposure and risk of energy commodity trading.
In early 2002, after concluding that a mild winter and high natural gas inventories would result in falling prices, Select Energy established a significant "short" position in natural gas. Despite contrary fundamentals, natural gas prices rose significantly in March and April 2002, resulting, after break-even performance for the balance of 2002, in an after-tax loss of approximately $24 million for the year compared with earnings of $19 million in 2001. After April 2002, senior NU management decided to reduce significantly its speculative trading activities and the capital at risk in the trading area to a daily average of approximately $0.4 million from up to $6 million in early 2002 and is continuing to evaluate the scope and size of Select Energy's trading function. Management projects that its trading business will be modestly profitable in 2003.
NU provides credit assurance as the credit support provider in Select Energy's contracts, in the form of guarantees and letters of credit for the financial performance obligations of certain of its competitive energy subsidiaries. NU currently has authorization from the SEC to provide up to $500 million of guarantees through September 30, 2003, and has applied for authority to increase this amount to $750 million and extend the authorization period through September 30, 2005. As of December 31, 2002, NU had provided approximately $183 million of such guarantees and $7 million of letters of credit. In addition, NU's "aggregate investment" in Select Energy and its other energy service companies (but not including NGC, HWP or SESI) (which is inclusive of most such credit assurances) is limited by SEC rule to 15 percent of NU's most recent quarterly consolidated capitalization. NU has applied for authority to exempt its investments in such energy services companies from this limitation.
ELECTRIC GENERATION
NGC, NU's competitive electric generating affiliate, owns approximately 1,291 MW of hydroelectric and pumped storage generating assets in Connecticut and Massachusetts. NGC sells all of its energy and capacity to its affiliate, Select Energy. Select Energy's performance under its contract with NGC is guaranteed by NU. Select also buys and manages the entire generation output of approximately 147 MW from HWP's Mt. Tom generating plant under a renewable contract. Select Energy uses the NGC and Mt. Tom generation to furnish a portion of the resources it uses to meet supply commitments to its marketing customers.
NGC's contract with Select Energy extends through December 2005. About 85 percent of NGC's revenues from this contract (including all of the revenues from Northfield Mountain) are in the form of predetermined, fixed monthly payments based on the capacity of specified facilities. The remaining 15 percent of the revenues are in the form of monthly payments at predetermined rates per unit of actual energy output. NGC currently derives approximately 80 percent of its revenues from Northfield Mountain.
This contract provides NGC with a stable stream of revenues at prices that are currently higher than average wholesale electricity prices in the markets served by NGC's facilities. If NGC's agreement with Select Energy were to terminate at the end of its term in 2005, NGC may, depending upon market conditions, pursue similar contracts or choose to optimize the value of its assets in another manner. NGC plans to continue to evaluate growth opportunities in the northeastern United States; however, its ability to pursue such opportunities is limited by capital and regulatory constraints.
COMPETITIVE ENERGY SUBSIDIARIES' MARKET AND OTHER RISKS
NU's competitive energy subsidiaries, primarily Select Energy, are exposed to certain market and other risks inherent in their business activities.
A significant portion of their retail and wholesale marketing business is providing full requirements service to customers, primarily regulated distribution companies. The "full requirements" obligation commits these companies to supply the total energy requirement for the customers' load at all times. An important component of their risk management strategy is to manage the volume and price risks of their full requirements contracts. These risks include unexpected fluctuations in both supply and demand due to numerous factors which are not within their control, such as weather, plant availability, exposure to transmission congestion costs and price volatility. Select Energy's 2002 results were negatively impacted when contracted supply exceeded demand in the warmer than expected winter months and additional supply had to be acquired during summer months at higher than expected prices.
In serving its marketing customers, Select Energy utilizes derivative financial and commodity instruments, including futures and forward contracts, to manage the risk of fluctuating market prices. At December 31, 2002, Select Energy had net hedging derivative assets of $20.8 million, as compared to net derivative liabilities of $55.5 million at December 31, 2001. Generally, such derivatives impact earnings over the life of the contracts which they hedge, but in certain cases the impact is accelerated and affects earnings immediately.
In addition, Select Energy's trading business is exposed to certain risks. Select Energy trades in both financial derivative (non-physical delivery) and physical delivery transactions for electricity, natural gas and oil in which it attempts to profit from short-term changes in market prices. Energy trading contracts of both types are recorded at fair value, changes in which impact Select Energy's earnings in the period of change. Such fair values are derived from a number of sources, including market quotes of exchange-traded commodities, prices provided by external sources in over-the-counter transactions and, in rare cases, values derived from pricing models.
Select Energy's trading portfolio had a net positive $41 million fair value at December 31, 2002, as compared to a net positive $56.4 million fair value at December 31, 2001. Approximately 90 percent of the $41 million was priced from external sources, while the balance of approximately $4.5 million was from pricing models, and only a nominal amount was based on exchange quotes. Of the $41 million of net fair value in the trading portfolio at December 31, 2002, $1.6 million will mature in 2003, $24.8 million in 2004-2007 and $14.6 million after 2007. Generally, valuations of short-term contracts derived from quotes or other external sources are more reliable while valuations based on trading models are less certain.
Accordingly, there is a risk that the trading portfolio will not be realized in the amount recorded. Realization of cash will depend upon a number of factors over which Select Energy has limited or no control, including the accuracy of its valuation methodologies, the volatility of commodity prices, changes in market design and settlement mechanisms, the outcome of future transactions, the performance of counterparties, the breadth and depth of the trading market and other factors.
In addition, the application of derivative accounting principles is complex and requires management judgment in identification of derivatives and embedded derivatives, election and designation of the "normal purchases and sales" exceptions, identifying hedge relationships and assessing hedge effectiveness, determining the fair value of derivatives and measuring hedge ineffectiveness. All of these judgments, depending upon their timing and effect, can have a significant impact on the competitive subsidiaries' performance and, ultimately, NU's consolidated net income.
Risk management within the competitive energy subsidiaries, including Select Energy, is organized by management to address the market, credit and operational exposures arising from the company's primary business segments, including wholesale marketing, retail marketing and trading. The framework and degree to which these risks are managed and controlled is consistent with the limitations imposed by NU's Board of Trustees as established and communicated in NU's overall risk management policies and procedures. As a means to monitor and control compliance with these policies and procedures, NU has formed a Risk Oversight Council (ROC) to monitor competitive energy risk management processes independently from the businesses that create or manage these risks. The ROC ensures that the policies pertaining to these risks are followed and makes recommendations to the Board of Trustees regarding periodic adjustment to the metrics used in measuring and controlling portfolio risk while also confirming the methodologies employed by management to discern portfolio values.
ENERGY MANAGEMENT SERVICES
NUEI has two affiliated companies in the energy management business: NGS and SESI.
NGS was formed in 1999 to provide a full range of integrated energy- related services to owners of generation facilities and the industrial market in the Northeast. NGS designs, builds, manages, operates, maintains and supports electric power generating equipment, facilities and associated transmission and distribution equipment and provides turnkey management and operation services to owners of electric generation facilities. NGC and HWP have contracted with NGS to operate and maintain all of their generating plants.
Through its wholly-owned subsidiaries, E.S. Boulos Company and Woods Electrical Co., Inc. (Woods Electrical), NGS provides electrical construction and contracting services. These services focus on high and medium voltage installations and upgrades and substation and switchyard construction. Woods Network Services, Inc. (Woods Network), a subsidiary of NUEI, is a network products and services company. Woods Electrical and Woods Network were acquired in July 2002 for an aggregate adjusted purchase price of $16.3 million.
NGS's construction and maintenance services include construction management and mechanical construction and maintenance services for industrial and power generation customers. NGS also provides consulting services to its customers, including engineering and design, asset development, due diligence reviews and environmental regulatory compliance and permitting services. In addition, NGS provides laboratory analyses and specialized electrical testing services.
During 2002, NGS's revenues were approximately $76 million, excluding intercompany transactions, and are forecasted to grow by approximately 30 percent in 2003. This anticipated growth is expected to be driven by NGS's increased geographical scope, additional contracts with both new and repeat customers and the effect of recent acquisitions. Thirty-six percent of NGS's revenues in 2002 were derived from contracts with its affiliates NGC, PSNH, SESI and HWP.
SESI was acquired in 1990 and provides energy efficiency, design and construction solutions to government, institutional and commercial facilities. In delivering its services, SESI focuses on reducing its customers' energy costs, improving the efficiency and reliability of their energy-consuming equipment and conserving energy and other resources. SESI also designs, builds and maintains central energy plants producing power, heating and cooling for their hosts. SESI's engineering and construction management services have been directed primarily to markets in the eastern United States. SESI's subsidiary, Select Energy Contracting, Inc. (SECI), provides service contracts and mechanical and electrical contracting, primarily directed to energy systems in commercial markets.
In competitive procurements by the United States Departments of Defense and Energy and the General Services Administration, SESI has been selected as an "Energy Saving Performance Contractor" (ESPC) for all fifty states and overseas facilities. Over the last several years, SESI became one of the major providers of design, construction, financing and long-term operation and maintenance of energy-efficient and environmentally clean systems to replace older infrastructure. SESI has recently installed the largest fuel cell-based energy plant in the United States (at a state school in Connecticut) and the new stand-alone energy plant at Bradley International Airport in Connecticut. SESI is under contract to operate and maintain the plants for at least 20 years. In 2002, federal ESPC work constituted 20 percent of SESI's revenues, which were approximately $99 million. In 2003, SESI's revenues are anticipated to grow by approximately 30 percent based on existing backlog and continuing success in its existing business lines.
TELECOMMUNICATIONS
Mode 1 was established in 1996 to participate in a wide range of telecommunications activities both within and outside New England and is currently owned by NUEI. Mode 1 is a licensed competitive local exchange carrier authorized to provide local phone service within the state of Connecticut. Mode 1 provides telecommunication network services at the retail and wholesale levels, primarily dark fiber. It has built high speed fiberoptic connectivity to secondary and tertiary markets within cities such as Hartford, Connecticut and serves the City of Hartford's schools and libraries with an optical network.
NU has invested approximately $22 million in Mode 1 since it was established, which investment was principally used to fund Mode 1's investment in NEON Communications, Inc., a wholesale telecommunication infrastructure provider of dark and light fiber-optic services (NEON). As of January 1, 2002, Mode 1 was the largest equity investor in NEON, owning approximately 19.3 percent of the common shares of NEON. NEON is a wholesale provider of high bandwidth, advanced optical networking solutions and services on intercity, regional and metro networks in the twelve-state Northeast and mid-Atlantic markets, utilizing a portion of the NU system companies' transmission and distribution facilities. An officer and trustee of NU is a member of the Board of Directors of NEON.
In June 2001, NEON and Mode 1 entered into a purchase agreement pursuant to which Mode 1 purchased from NEON an 18 percent subordinated convertible note due 2008 in the principal amount of $15 million (Note). On June 25, 2002 NEON filed for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code. Following negotiations with its senior debtholders and Mode 1, NEON filed a plan of reorganization and emerged from bankruptcy on December 22, 2002. Under NEON's plan of reorganization, all existing shares of NEON's common stock, including those held by Mode 1, were cancelled along with the Note held by Mode 1. As part of the reorganization, Mode 1 agreed to purchase seven percent of the outstanding securities of the reorganized NEON for approximately $3.2 million. This phase of NEON's reorganization closed in December 2002.
FINANCING PROGRAM
2002 FINANCINGS
On January 30, 2002, PSNH Funding LLC 2, a subsidiary of PSNH, sold $50 million of additional RRBs at an interest rate of 4.58 percent. The bonds, which were rated AAA by three credit rating agencies, will amortize over the next six years with an average maturity of 3.5 years and have a scheduled maturity date of February 1, 2008. PSNH used the proceeds to repay short-term debt that was incurred to buy out a high-cost purchase power obligation in December 2001. In 2001, funding affiliates of PSNH, CL&P and WMECO sold an aggregate of approximately $2.1 billion of RRBs and RRCs in similar transactions. All RRBs and RRCs are payable solely from collections from customers of PSNH, CL&P and WMECO, respectively, and are non-recourse to the companies.
On April 4, 2002, NU issued $263 million of 10-year senior unsecured notes. The notes carry a coupon of 7.25 percent and mature on April 1, 2012. Proceeds from the issuance were used to redeem a similar amount of variable rate notes that were issued on February 28, 2001 to finance NU's merger with Yankee.
On July 10, 2002, CL&P renewed its accounts receivable securitization bank credit line and extended its termination date to July 9, 2003. The credit line capacity remained the same at $100 million.
On August 29, 2002, SESI entered into an assignment of delivery orders payments (Assignment) with a financing entity, BFL Funding IV LLC (BFL), to finance the construction and installation of certain energy conservation measures at several federal government installations which SESI had agreed to install pursuant to delivery orders issued by the federal government. Pursuant to the Assignment, SESI assigned the payments due under the delivery orders by the federal government to BFL in exchange for $12.5 million. BFL issued $12.6 million of trust certificates at an interest rate of 6.25 percent that mature in October 2021 to fund this payment. Certain obligations of SESI under the transaction documents and the delivery order payments due from the government are backed by an NU parent guaranty.
On September 9, 2002, CL&P entered into a replacement standby bond purchase agreement supporting the 1996A series pollution control revenue bonds (PCRBs). The $62.9 million, 364-day agreement replaced a similar agreement and expires on October 21, 2003. The original transaction was approved by the DPUC in 1997.
On October 24, 2002, Hannie Mae LLC purchased from SESI monies due or to become due under certain task order contracts for $30 million. The proceeds will be used to fund the construction of energy conservation projects at several governmental facilities and will be recorded as debt as construction draws occur through April 2004. The interest rate is approximately 7.65 percent and the amortizing debt will mature on December 1, 2026. The debt, payable from the resulting energy savings, is backed by an NU parent guaranty.
On November 1, 2002, NAEC used its share of proceeds from the sale of the Seabrook nuclear generating station to pay off its $90 million term credit agreement that expired on November 9, 2001.
On November 12, 2002, CL&P, WMECO, PSNH and Yankee Gas entered into a new unsecured 364-day revolving credit facility for $300 million, replacing a similar $350 million facility that was due to expire on November 15, 2002. CL&P may draw up to $150 million, and WMECO, PSNH and Yankee Gas may draw up to $100 million each, subject to the $300 million maximum for the entire facility. Unless extended, the credit facility will expire on November 11, 2003.
On November 12, 2002, NU entered into a new unsecured 364-day revolving credit facility for $350 million, replacing a similar $300 million facility that was due to expire on November 15, 2002. The facility supports the working capital needs of NU and its competitive subsidiaries. The new facility provides a total commitment of $350 million which is available subject to two overlapping sub-limits. First, subject to the notional amount of any letters of credit outstanding, amounts up to $350 million are available for advances. Second, subject to the advances outstanding, letters of credit may be issued in an aggregate amount of up to $250 million, an increase of $50 million over the prior facility. The agreement provides for letters of credit to be issued in the name of NU or any of its subsidiaries. Unless extended, the credit facility will expire on November 11, 2003.
NU paid common dividends totaling $67.8 million in 2002, compared to $60.9 million paid in 2001, reflecting increases in the quarterly dividend rate that were effective September 30, 2001 and September 30, 2002. The higher levels of dividends were easily accommodated by rising general liquidity at the NU parent level, due in part to the continued return of equity capital from the regulated subsidiaries, as well as their payment of common dividends to the parent. Liquidity at the parent company is also reinforced by the absence of debt maturities and minimal sinking fund payments in the near term ($23 million in 2003 and $24 million in 2004).
Total NU system debt, including short-term and capitalized lease obligations but not including RRCs and RRBs, was $2.4 billion as of December 31, 2002, compared with $2.7 billion as of December 31, 2001. The decrease was primarily due to a reduction in short-term bank borrowings.
For more information regarding NU system financing, see "Notes to Consolidated Statements of Capitalization" in NU's financial statements, other footnotes related to long-term debt, short-term debt and the sale of accounts receivables, as applicable, in the notes to NU's, CL&P's, PSNH's, and WMECO's financial statements and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."
2003 FINANCING REQUIREMENTS
The NU system's aggregate capital requirements for 2003 are approximately as follows:
Yankee NU
CL&P PSNH WMECO Gas Other System
(Millions)
Construction $327 $116 $ 28 $ 73 $ 96 $640
Maturities 0 0 0 0 0 0
Cash Sinking
Funds * 0 0 0 2 55 57
---- ---- ---- ---- ---- ----
Total $327 $116 $ 28 $ 75 $151 $697
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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 2003 financing requirements, see "Notes to Consolidated Statements of Capitalization" in NU's financial statements, "Long-Term Debt" in the notes to CL&P's, PSNH's and WMECO's financial statements and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."
2003 FINANCING PLANS
NU projects a moderate level of system financings in 2003.
CL&P is contemplating the issuance of up to $220 million of debt to refinance its pre-1983 spent nuclear fuel obligations and has applied to the DPUC for authority to issue this debt. CL&P has also announced plans for the construction of various transmission facilities. The projects require numerous federal and state regulatory approvals. If approved, construction of these facilities would require external financing. See "Financing Program - Construction and Capital Improvement Program."
WMECO has applied to the DTE to issue approximately $105 million of debt to refinance its existing short-term debt and pre-1983 spent nuclear fuel obligations.
Yankee Gas may seek to issue up to $75 million of long-term debt in 2003 to finance its capital requirements and may also require additional debt issuances in later years, depending on the extent of its capital program. Yankee Gas is currently implementing a number of capital projects and is planning the construction of a liquefied natural gas storage and production facility in Waterbury, Connecticut that could cost approximately $60 million. See "Financing Program - Construction and Capital Improvement Program."
FINANCING LIMITATIONS
Many of the NU system companies' charters and borrowing facilities contain financial limitations that must be satisfied before borrowings can be made and for outstanding borrowings to remain outstanding. In addition, the NU system companies are subject to certain federal and state orders and policies which limit their financial activities.
Under their current revolving credit facility agreement, CL&P, WMECO, PSNH and Yankee Gas are allowed to maintain a ratio of debt to total capitalization (leverage ratio) of no more than 65 percent. At December 31, 2002, CL&P's, WMECO's, PSNH's, and Yankee Gas's leverage ratios were 44 percent, 48 percent, 56 percent and 30 percent, respectively. This agreement also requires the companies to maintain 12-month earnings before interest and taxes to interest expense ratio (interest coverage ratio) of at least 2.25 to 1.0. At December 31, 2002, CL&P's, WMECO's, PSNH's and Yankee Gas' interest coverage ratios were 4.37 to 1, 10.78 to 1, 6.54 to 1 and 2.76 to 1, respectively. These ratios do not include RRBs and RRCs.
NU is allowed, under its current revolving short-term credit agreement facility, to maintain a debt to total capitalization (leverage ratio) of no more than 66 percent. At December 31, 2002, NU's leverage ratio was 50 percent. In addition, NU is required to maintain a 12-month consolidated interest coverage ratio of at least 2.0 to 1.0. This covenant was reduced from 2.25 to 1.0 in the prior year's facility to provide additional flexibility to NU. At December 31, 2002, NU's consolidated interest coverage ratio was 2.57 to 1.0. These ratios do not include RRBs and RRCs.
The amount of short-term debt that may be incurred by NU, CL&P, PSNH, WMECO, NAEC, Northeast Nuclear Energy Company (NNECO), Yankee, Yankee Gas and HWP is also subject to periodic approval by the SEC under the Public Utility Holding Company Act of 1935 (1935 Act). Current short-term debt authorizations expire on June 30, 2003 and NU plans to file in early 2003 with the SEC to extend the short-term debt authority for these companies and to add certain additional subsidiaries to the Northeast Utilities System Money Pool (Pool). PSNH's and NAEC's short-term debt in excess of 10 percent of net fixed plant is also regulated by the NHPUC. The following table shows the amount of short- term borrowings authorized by the SEC or the NHPUC for each company, as the case may be, as of December 31, 2002, and the amounts of outstanding short-term debt of those companies at the end of 2002 and as of March 3, 2003:
Maximum Authorized Outstanding
Short-Term Debt Short-Term Debt (1)
December 31, 2002 March 3, 2003
(Millions)
NU $400 $ 0.0 $ 0.0
CL&P 375 38.1 14.0
PSNH (2) 225 0.0 0.0
WMECO 250 92.9 86.8
NAEC(3) 260 0.0 0.0
NNECO 75 0.0 0.0
Yankee 50 0.0 0.0
Yankee Gas 100 66.0 58.6
HWP 5 0.0 0.0
Select Energy N/A 217.2 161.7
NGS(4) N/A 18.5 17.9
SESI(4) N/A 6.5 0.0
RRR(4) N/A 32.7 33.0
Other 7.5 9.3
------ ------
Total $479.4 $381.3
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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 $56 million at December 31, 2002 and $20 million at March 3, 2003.
(2) Under applicable NHPUC provisions, PSNH can incur short-term debt up to $100 million.
(3) Under applicable NHPUC regulations, NAEC can incur short term debt up to 10 percent of net fixed plant or such other amount as approved by the NHPUC. Prior to the sale of Seabrook, NAEC had authorization from the NHPUC to issue up to $260 million of short-term debt. NAEC has no plans to incur any future short-term borrowings.
(4) The SEC limits, as indicated, the following companies' borrowings from the Pool (but not borrowings from either parent companies or non-affiliates): NUEI ($100 million); Select Energy ($200 million); NGS ($20 million); SESI ($20 million) and The Rocky River Realty Company (RRR) ($30 million). NU, NGC and Mode 1 may lend to but are not authorized to borrow from the Pool.
The supplemental indentures under which NU issued $175 million in principal amount of 8.58 percent amortizing notes in December 1991 and $75 million in principal amount of 8.38 percent amortizing notes in March 1992 contain restrictions on dispositions of certain NU system companies' stock, limitations of liens on NU assets and restrictions on distributions on and acquisitions of NU stock. Under these provisions, NU, CL&P, PSNH and WMECO may not dispose of voting stock of CL&P, PSNH or WMECO other than to NU or another NU system company, except that CL&P may sell voting stock for cash to third persons if so ordered by a regulatory agency so long as the amount sold is not more than 19 percent of CL&P's voting stock after the sale. The restrictions also generally prohibit NU from pledging voting stock of CL&P, PSNH or WMECO or granting liens on its other assets in amounts greater than five percent of the total common equity of NU. Many of the NU system companies' credit agreements have similar restrictions. As of December 31, 2002, no NU debt was secured by liens on NU assets. Furthermore, NU may not declare or make distributions on its capital stock, acquire its capital stock (or rights thereto), or permit an NU system company to do the same, at times when there is an event of default existing under the supplemental indentures under which the amortizing notes were issued.
The indenture under which NU issued $263 million in principal amount of 7.25 percent notes in April 2002 contains a limitation of liens on NU assets and a limitation of sale and leaseback transactions on those assets.
CL&P's charter contains preferred stock provisions restricting the amount of additional unsecured debt it may incur. As of December 31, 2002, the amount of additional unsecured debt it could incur was $480 million.
The indentures securing the outstanding first mortgage bonds of CL&P provide that additional bonds may not be issued, except for certain refunding purposes, unless earnings are at least twice the pro forma annual interest charges on outstanding bonds, and certain prior lien obligations and bonds to be issued.
The preferred stock provisions of CL&P's charter also prohibit the issuance of additional preferred stock (except for refinancing purposes) unless income before interest charges (as defined and after income taxes and depreciation) is at least 1.5 times the pro forma annual interest charges on indebtedness and the annual dividend requirements on preferred stock that will be outstanding after the additional stock is issued. At December 31, 2002, CL&P's income before interest charges was approximately 2.95 times the pro forma annual interest and dividend requirements. CL&P has no current plans to issue any preferred stock.
Certain consolidated subsidiaries have dividend restrictions imposed by their long-term debt agreements. These restrictions also limit the amount of retained earnings available for NU common dividends. At December 31, 2002, retained earnings available for the payment of dividends totaled $765.6 million.
The Federal Power Act limits the payment of dividends by PSNH, NAEC, CL&P, and WMECO to retained earnings. At December 31, 2002, retained earnings for these companies were $195 million, $20.3 million, $308.6 million and $77.5 million, respectively.
New Hampshire statutes also limit the payment of dividends by PSNH and NAEC to the amount of retained earnings.
CL&P's first mortgage bond indenture limits dividend payments and share repurchases to an amount equal to (i) retained earnings accumulated after December 31, 1966; plus (ii) retained earnings accumulated prior to January 1, 1967, not exceeding $13.5 million; plus (iii) any additional amounts authorized by the SEC. In 2000 and 2002, the SEC approved CL&P's proposal to pay dividends and repurchase shares from capital or unearned surplus of up to $410 million in aggregate from proceeds derived from industry restructuring transactions.
Applicable merger accounting rules required that upon acquisition by NU, Yankee's and its subsidiaries' retained earnings were reclassified as capital surplus. Also, the merger premium NU paid to acquire Yankee was allocated among Yankee and its subsidiaries and "pushed down" to their balance sheets. Under accounting conventions in existence at the time of the merger, the majority of the merger premium would be amortized over 40 years. In June 2001, the Financial Accounting Standards Board issued a statement that, effective January 1, 2002, no longer requires companies to amortize goodwill as an expense to the income statement. Instead goodwill is required to be evaluated for impairment and any impairments to goodwill would be charged to expense. The effect of the new accounting standard was a $0.4 million annual reduction in goodwill amortization expense.
Under the 1935 Act, subsidiaries of registered holding companies are only allowed to pay dividends out of retained earnings unless the SEC allows otherwise. The effect of this rule would be to prevent Yankee from paying dividends to NU from any source other than post-merger earnings, as reduced by the merger premium amortization. NU had received permission from the SEC, through June 2002, for Yankee and Yankee Gas to pay dividends (i) out of additional paid-in capital up to the amount of their respective retained earnings just prior to the merger with NU and (ii) out of earnings before the amortization of the merger goodwill (gross earnings) in the case of Yankee Gas and out of distributed earnings in the case of Yankee. To assure that Yankee Gas has sufficient cash to fund operations, Yankee Gas will not pay dividends in excess of 80 percent of gross earnings on a rolling five-year average basis. In no case would dividends be paid by Yankee or Yankee Gas if their common equity to total capitalization ratios were below 35 percent. NU also received permission from the SEC, through June 2002, for Yankee and Yankee Gas to repurchase their common stock such that their common equity to total capitalization ratios do not fall below 35 percent. To date, Yankee Gas has paid no dividends to NU since the merger.
NGC bond covenants prevent NGC from making dividend payments unless (i) no default or event of default will occur from doing so, (ii) the debt service reserve account has been sufficiently funded with six months of principal and interest on the outstanding bonds, and (iii) the debt service coverage ratio for the previous four fiscal quarters (or, if shorter, since the bond issuance closing date) and projected debt service coverage ratio for the next eight fiscal quarters is (a) greater than or equal to 1.35 if contracted generating capacity is greater than 75 percent or (b) greater than or equal to 1.70 if contracted generating capacity is less than 75 percent. At December 31, 2002, NGC's contracted generating capacity was greater than 75 percent. NGC expects to meet its debt service coverage ratio requirements under this covenant and to pay dividends in 2003.
NU is required under the 1935 Act to maintain its consolidated common equity at a level equal to at least 30 percent of its consolidated capitalization. In planning for the issuance of RRBs and RRCs by its subsidiaries in 2001, NU anticipated being unable to meet this standard because such bonds and certificates, although nonrecourse to the NU system company issuers, are considered to be indebtedness of the companies under generally accepted accounting principles. In 2000, the SEC authorized the consolidated common equity ratio of NU to fall below 30 percent through December 31, 2002 on account of such sales and certain related restructuring transactions. NU's consolidated common equity ratio was greater than 30 percent as of December 31, 2002 and is expected to remain above this level in the future. The 30 percent test also applies to NU's electric operating subsidiaries. The SEC has consented to the common equity ratios of CL&P, WMECO and PSNH falling below 30 percent through December 31, 2004. As of December 31, 2002, NU's, CL&P's, WMECO's and PSNH's ratios were 33.6 percent, 24.1 percent, 31.9 percent and 26 percent, respectively. These ratios include RRBs and RRCs as debt.
NU provides credit assurance in the form of guarantees and letters of credit for the financial performance obligations of certain of its unregulated subsidiaries. NU currently has authorization from the SEC to provide up to $500 million of such guarantees through September 30, 2003 and has applied for authority to increase this amount to $750 million and extend the authorization period through September 30, 2005. As of December 31, 2002, NU had provided approximately $183 million and $7 million, respectively, of such guarantees and letters of credit. As of January 31, 2003, NU had provided approximately $234 million and $22 million, respectively, of such guarantees and letters of credit.
Certain NU system credit financing agreements have trigger events tied to the credit ratings of certain NU system companies, as discussed below.
RRR is a real estate subsidiary that owns NU's Connecticut headquarters site. It has approximately $6.5 million of debt outstanding that could be affected by a ratings change. If NU, CL&P, PSNH or WMECO ratings fall below a B1 Moody's rating or a B+ Standard & Poor's rating, bondholders would have the right to demand mandatory prepayments.
NGC has a debt reserve account related to the $440 million bond issue that can be funded with cash, an NU guarantee or a letter of credit from an acceptable counterparty. The account is currently funded with cash and may be funded with a guarantee from NU only if NU has an investment grade rating by Standard & Poor's and Moody's.
NU and its subsidiaries have $650 million of revolving credit agreements with a number of banks. There are no ratings triggers that would result in a default, but lower ratings would increase interest on future borrowings from the credit lines.
A number of Select Energy's contracts require the posting of additional collateral in the form of cash or letters of credit in the event NU's ratings were to decline and in increasing amounts dependent upon the severity of the decline. At NU's present investment grade ratings, Select Energy has not had to post any collateral based on credit downgrades. Were NU's unsecured ratings to decline two to three levels to sub-investment grade, Select Energy would, under its present contracts, be asked to provide approximately $140 million of collateral or letters of credit to various unaffiliated counterparties and approximately $80 million to several independent system operators (ISO) and unaffiliated local distribution companies, which NU, under present circumstances, would be able to provide from available sources. NU's ratings are currently stable, and management does not believe that at this time there is a significant risk of a ratings downgrade to sub-investment grade levels.
CONSTRUCTION AND CAPITAL IMPROVEMENT PROGRAM
The NU system's construction program expenditures, including allowance for funds used during construction, is estimated to total $640 million in 2003. Of such total amount, approximately $327 million is expected to be expended by CL&P, $116 million by PSNH, $73 million by Yankee Gas, $28 million by WMECO and up to $96 million by other system entities. This construction program data includes all anticipated costs necessary for committed projects and for those reasonably expected to become committed projects in 2003, regardless of whether the need for the project arises from environmental compliance, reliability requirements or other causes. The construction program's main focus is maintaining, upgrading and expanding the existing transmission and distribution system and natural gas distribution system. The system expects to evaluate its needs beyond 2003 in light of future developments, such as restructuring, industry consolidation, performance and other events.
The $96 million in construction expenditures planned for other system entities in 2003 includes $23 million for NUEI (including NGS).
CL&P has announced plans to invest approximately $535 million by the end of 2008 to construct two new 345,000 volt transmission lines from inland Connecticut to Norwalk, Connecticut and another $40 million to replace an existing 138,000 volt transmission line beneath Long Island Sound. The investment in transmission lines and continued upgrading of the electric distribution system are expected to increase CL&P's net investment in electric plant by between $240 million and $360 million for the years 2003 to 2005. All of these projects are in the developmental or governmental approval stage and management cannot yet determine whether the projects will be built as proposed. If current plans are implemented on schedule, the NU system would likely require additional external financing to construct these projects. If all of the transmission projects are built as proposed, the NU system's net investment in electric transmission would increase to nearly $1.1 billion by the end of 2008.
Yankee Gas will continue to emphasize system expansion of its natural gas distribution system in Connecticut and plans to move forward with its three year plan to install a liquid natural gas facility in Waterbury, Connecticut. See "Connecticut Rates and Restructuring" for information on Yankee Gas' DPUC filing and the related decision.
REGULATED ELECTRIC OPERATIONS
DISTRIBUTION AND SALES
CL&P, PSNH and WMECO furnish retail franchise electric service in 149, 201 and 59 cities and towns in Connecticut, New Hampshire and Massachusetts, respectively. In December 2002, CL&P provided retail franchise service to approximately 1.2 million customers in Connecticut, PSNH provided retail service to approximately 449,000 customers in New Hampshire and WMECO served approximately 204,000 retail customers in Massachusetts.
The following table shows the sources of 2002 electric franchise retail revenues based on categories of customers (exclusive of HWP):
Total NU
CL&P PSNH WMECO System
---- ---- ----- --------
Residential 46% 42% 45% 45%
Commercial 40% 38% 36% 39%
Industrial 12% 19% 18% 15%
Other 2% 1% 1% 1%
---- ---- ---- ----
Total 100% 100% 100% 100%
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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 2012 for CL&P, PSNH and WMECO are set forth below:
Forecast
2003-2012
2002 over 2001 over Compound Rate
2001 2000 Of Growth
NU System 1.3% 2.3% 1.0%
CL&P 1.8% 2.4% 1.0%
PSNH -0.1% 3.9% 1.5%
WMECO 1.9% -0.9% 0.7%
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Consolidated NU retail sales rose by 1.3 percent in 2002, compared with 2001, primarily due to higher cooling requirements. Residential electric sales were up 4.5 percent. Commercial sales were up by 2.6 percent for the year and industrial sales decreased by 7.7 percent. Retail sales for CL&P, WMECO and PSNH were up 1.8 percent, up 1.9 percent and down 0.1 percent, respectively.
REGIONAL AND SYSTEM COORDINATION
The NU system companies and most other New England utilities are parties to an agreement (NEPOOL Agreement), which provides for coordinated planning and operation of the region's generation and transmission facilities. The NEPOOL Agreement was restated and revised as of March 1997 to provide for (i) a pool- wide open access transmission tariff; (ii) the creation of an ISO; and (iii) a broader governance structure for New England Power Pool (NEPOOL) and a more open, competitive market structure. Under these new arrangements the ISO, a nonprofit corporation whose board of directors and staff are not controlled by or affiliated with market participants, ensures the reliability of the NEPOOL transmission system, administers the NEPOOL tariff and oversees the efficient and competitive functioning of the regional power market.
The NEPOOL tariff provides for nondiscriminatory open access to the regional transmission network at a single rate regardless of transmitting distance for all transactions. The rate is a formula rate, structured to ensure that each transmission provider under the NEPOOL tariff recovers its revenue requirements.
In 1999, the NEPOOL Executive Committee filed a comprehensive settlement of all issues set for hearing concerning the NEPOOL transmission tariff. The settlement resolves disputes concerning the calculation of revenue requirements for transmission over NEPOOL facilities and resolves disputes over alleged "double charges" under grandfathered transmission contracts retained by individual transmission providers, including the NU system. The settlement also includes a return on earnings (ROES) component which sets the ROES for each individual transmission provider owning NEPOOL transmission facilities with respect to those facilities from March 1, 1997 through at least June 1, 2000, provided no changes to individual network transmission tariff rates are made after December 31, 1999. NU's ROES has been set at 11.75 percent. NU has made no changes to its transmission tariff rates since the settlement was reached; accordingly, its ROES has remained unchanged.
As part of the settlement, ISO is required to independently audit the charges in effect for the period June 1997 through May 2000 or direct that such an audit be conducted under its supervision. In June 2000, ISO engaged an independent auditing firm to conduct such an audit. The audit was conducted over a two-year period and the resulting audit report was filed at FERC on April 24, 2002. The audit report identified several areas of disagreement between the auditors and the audited transmission owners. The issues are currently being addressed through an alternative dispute resolution process with the FERC.
In December 2000, NU was notified by FERC that it, along with several other companies, would be the subject of a separate FERC industry-wide audit of the accounting related to formula rate transmission tariffs. FERC commenced its audit of NU in February 2001 and an exit conference was held on February 12, 2002.
Under an agreement (NUG&T) among CL&P, WMECO and HWP, these companies pool their electric production costs and the costs of their principal transmission facilities. The NUG&T was revised in 1999 to eliminate the generation aspects of the agreement. Final agreement from FERC on this revision was granted in October 2000.
Transmission revenues are allocated between the NUG&T signatories (CL&P, HWP, WMECO) and PSNH based upon the respective companies' cost of service.
TRANSMISSION ACCESS AND FERC REGULATORY CHANGES
Pursuant to FERC Order 888 (issued in April 1996), NU system companies operate their transmission system under an open access, nondiscriminatory transmission tariff.
In December 1999, the FERC issued an order calling on all transmission owners to voluntarily join RTOs in order to boost competition in electric markets (Order 2000). In general, each such organization would be an independent operator over all transmission facilities, and would perform, among other functions, tariff administration, construction planning and reliability management for the particular regional transmission system.
In January 2002, ISO-New England and New York ISO proposed to FERC that the two pools combine to form a single RTO. On November 22, 2002 the ISOs withdrew their application. On January 16, 2003, ISO-New England announced its intent to file a joint application with the New England transmission organizations to create a New England RTO.
On July 15, 2002, the NEPOOL Participants Committee and ISO-New England management filed a new NEPOOL market rule in a joint filing to implement SMD in New England. SMD would adopt LMP as a congestion tool as well as other market features similar to market rules in New York and the Pennsylvania-New Jersey- Maryland (PJM) Interconnection. The proposed New England SMD also includes market mitigation rules that would allow ISO-New England to set congestion proxy prices within certain Designated Congestion Areas (DCA) and would allow ISO-New England to utilize RMR contracts to ensure the availability of certain generating plants to run when it would otherwise be uneconomic for such plants to do so in order to maintain system reliability. NU intervened in the SMD docket at FERC largely supporting the new market rules, with the exception of the DCA proposal which, if implemented without restrictions on the ISO, NU believes could artificially inflate prices in DCAs. The New England SMD proposal was approved by FERC on December 20, 2002 and was implemented on March 1, 2003.
In response to concerns raised by the DPUC and the Connecticut Attorney General concerning the impact of LMP on transmission constrained areas such as southwest Connecticut, FERC held that the costs of transmission expansion projects already identified in ISO-New England's 2002 regional transmission expansion plan (i.e., NU's Phase I and Phase II southwest Connecticut projects) built within five years from the date of the order should be spread across the New England region. The December 20, 2002 Order also approved the DCA mitigation proposal, however, in apparent recognition of the inherent flaws of the DCA methodology, required ISO-New England to comment within 90 days on an alternative methodology. NU is seeking rehearing of the order with respect to the DCA approval. For further information regarding the effect of SMD in the NU system companies service territory, see "Rates and Electric Industry Restructuring-Connecticut Rates and Restructuring."
On July 31, 2002, FERC issued a notice of proposed rulemaking (NOPR) on SMD. The SMD NOPR would require markets to adopt rules similar to those proposed in the New England SMD, but would also require transmission owners to either transfer ownership or operational control over their transmission facilities to an independent transmission provider (ITP) or to become an ITP. An ITP is similar to the RTO required by Order 2000 except that it need not cover as large a geographic area as RTOs. The SMD NOPR also proposes to change the nature of transmission service by eliminating the notion of non-firm service and establishing priority of service based on the customer's holding of financial transmission rights. Comments were filed on November 15, 2002 and a second round of comments on more controversial issues such as transmission planning and pricing, financial transmission rights and resource adequacy requirements were filed on January 10, 2003. A final rule is expected to be issued some time in 2003.
REGULATED GAS OPERATIONS
In March 2000, NU acquired Yankee and Yankee became a wholly owned subsidiary of NU. Yankee is the parent of Yankee Gas, the largest natural gas distribution company in Connecticut. Yankee continues to act as the holding company of Yankee Gas and its two active nonutility subsidiaries, NorConn Properties, Inc. (NorConn), which holds the property and facilities of Yankee and its subsidiaries, and Yankee Energy Financial Services Company, which provides customers with financing for energy equipment installations.
Yankee Gas operates the largest natural gas distribution system in Connecticut as measured by number of customers and size of service territory. Total throughput (sales and transportation) for 2002 was 49.9 billion cubic feet. In 2002, total gas operating revenues of $293 million were comprised of the following: 48 percent residential; 28.1 percent commercial; 19.4 percent industrial; and the remaining 4.1 percent other. Yankee Gas provides firm gas sales service to customers who require a continuous gas supply throughout the year, such as residential customers who rely on gas for their heating, hot water and cooking needs. Yankee Gas also provides interruptible gas sales service to certain commercial and industrial customers that have the capability to switch from natural gas to an alternative fuel on short notice. Yankee Gas can interrupt service to these customers during peak demand periods. Yankee Gas offers firm and interruptible transportation services to customers who purchase gas from sources other than Yankee Gas. In addition, Yankee Gas performs gas sales, gas exchanges and capacity releases to marketers to reduce its overall gas expense.
Although Yankee Gas is not subject to FERC jurisdiction, the FERC does regulate the interstate pipelines serving Yankee Gas' service territory. Yankee Gas, therefore, is directly and substantially affected by the FERC's policies and actions. Accordingly, Yankee Gas closely follows and, when appropriate, participates in proceedings before the FERC.
Yankee Gas is subject to regulation by the DPUC, which, among other things, has jurisdiction over rates, accounting procedures, certain dispositions of property and plant, mergers and consolidations, issuances of securities, standards of service, management efficiency and construction and operation of distribution, production and storage facilities. For information relating to Yankee Gas DPUC proceedings, see "Rates and Electric Industry Restructuring - Connecticut Rates and Restructuring."
For information on the proposed expansion of Yankee Gas' natural gas delivery system in Connecticut, see "Construction and Capital Improvement Program."
NUCLEAR GENERATION
GENERAL
During 2002, certain NU system companies had ownership interests in one nuclear unit, Seabrook, and equity interests in four regional nuclear companies (the Yankee Companies) that separately own the Connecticut Yankee nuclear unit (CY), the Maine Yankee nuclear unit (MY), VY (prior to its sale) and the Yankee Rowe nuclear unit (Yankee Rowe). One NU system company operated Seabrook prior to its sale in November 2002. Yankee Rowe, CY and MY have been permanently removed from service and are being decontaminated and decommissioned.
On November 1, 2002, CL&P and NAEC and certain nonaffiliated joint owners consummated the sale of their collective 88.2 percent interests in Seabrook to FPL. The remaining interests held by certain other nonaffiliated joint owners were retained by those entities. The NU system received approximately $384 million of cash proceeds from the sale and used those proceeds primarily to pay down debt maturing in less than one year. As part of the sale, FPL assumed responsibility for decommissioning Seabrook.
Before Seabrook was sold to FPL, CL&P and NAEC together owned 40.04 percent of Seabrook as tenants in common. Their respective ownership interests in each unit were 4.06 percent and 35.98 percent. The unit was shut down for a scheduled 28 day refueling outage beginning on May 4, 2002. The unit returned to service on June 1, 2002, completing the shortest outage in Seabrook's history. During 2002, Seabrook operated at a capacity factor of 90.2 percent through November 1, 2002, the date of closing on the sale of the unit.
CL&P, PSNH, WMECO and other New England electric utilities are the stockholders of the Yankee Companies. Each Yankee Company, other than VYNPC, owns a single nuclear generating unit. The stockholder-sponsors of each Yankee Company are responsible for proportional shares of the operating and decommissioning costs of the respective Yankee Company. The relative rights and obligations with respect to the Yankee Companies are approximately proportional to the stockholders' percentage stock holdings, but vary slightly to reflect arrangements under which nonstockholder electric utilities have contractual rights to some of the output of particular units. CL&P's, PSNH's and WMECO's stock ownership percentages in the Yankee Companies are set forth below:
NU
CL&P PSNH WMECO System
Connecticut Yankee Atomic
Power Company (CYAPC) 34.5% 5.0% 9.5% 49.0%
Maine Yankee Atomic Power
Company (MYAPC) 12.0% 5.0% 3.0% 20.0%
Vermont Yankee Nuclear
Power Corporation (VYNPC) 10.1% 4.3% 2.6% 17.0%
Yankee Atomic Electric
Company (YAEC) 24.5% 7.0% 7.0% 38.5%
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The ownership interests of CL&P, PSNH and WMECO in VYNPC increased slightly in early 2002 when VYNPC redeemed the stock owned by certain Vermont municipal electric systems which had previously owned about five percent of VYNPC's stock.
In March 2001, the board of VYNPC voted to proceed to auction the plant. J.P. Morgan was selected to conduct the auction. In August 2001, the owners of VYNPC announced they would sell the VY unit to a subsidiary of Entergy Corporation for approximately $180 million (approximately $145 million for the plant, materials and supplies and $35 million for the nuclear fuel). NU subsidiaries owned 17 percent of the VY unit and, under the terms of the sale, will continue to buy 17 percent of the plant's output through March 2012 at fixed prices. The sale of the unit was consummated on July 31, 2002. Prior to its sale, VY operated at a capacity factor of 91.7 percent during 2002. Although there was no refueling outage in 2002 prior to the sale, a 12 day mid- cycle outage began on May 11, 2002. This outage was undertaken primarily to replace some defective fuel in the reactor.
In conjunction with the sales of Millstone in 2001 and Seabrook in 2002, NU terminated its nuclear insurance related to these plants. However, through its continuing association with Nuclear Electric Insurance Limited (NEIL) and its interests in CYAPC and VYNPC, NU is subject to potential retrospective assessments totaling $0.8 million under the respective NEIL insurance policies.
The NRC has broad jurisdiction over the design, construction and operation of nuclear generating stations, including matters of public health and safety, financial qualifications, antitrust considerations and environmental impact. The NRC also has jurisdiction over the decommissioning activities at Yankee Rowe, CY and MY.
NUCLEAR FUEL
GENERAL
In 1998, an action was initiated by the owners of Millstone in the United States Court of Federal Claims against the United States Department of Energy (DOE) regarding the special annual assessment that the DOE imposes on purchasers of enriched uranium to meet the future costs of decontaminating and decommissioning (D&D) of government owned uranium enrichment facilities. Similar actions for Seabrook and CY were also filed. The lawsuits challenge the imposition of the D&D assessment on federal constitutional grounds and are similar to actions filed by a number of other utilities against DOE. Proceedings in the Millstone, Seabrook and CY cases were stayed pending the final resolution of a similar claim brought against the DOE by MYAPC. In July 1999, the claims court dismissed MYAPC's complaint. In November 2001, the Federal circuit court affirmed the dismissal of MYAPC's claims. On February 6, 2002, MYAPC filed a petition for certiorari, asking the United States Supreme Court to review the decision of the Federal circuit court, which petition was denied on May 28, 2002. The Millstone case was dismissed on July 19, 2002.
Nuclear fuel costs associated with nuclear plant operations include amounts for disposal of spent nuclear fuel. The NU system companies include in their nuclear fuel expense spent fuel disposal costs accepted by the DPUC, NHPUC and DTE in rate case or fuel adjustment decisions. Spent fuel disposal costs also are reflected in the FERC-approved wholesale charges.
HIGH-LEVEL RADIOACTIVE WASTE
The Nuclear Waste Policy Act of 1982 (NWPA) provides that the federal government is responsible for the permanent disposal of spent nuclear reactor fuel (SNF) and other high-level waste. As required by the NWPA, electric utilities generating SNF and high-level waste are obligated to pay fees into a fund which would be used to cover the cost of siting, constructing, developing and operating a permanent disposal facility for this waste. The NU system companies have been paying for such services for fuel burned on or after April 7, 1983, on a quarterly basis since July 1983. The DPUC, NHPUC and DTE permit the fee to be recovered through rates. For nuclear fuel used to generate electricity prior to April 7, 1983 (prior-period fuel), payment must be made upon the first delivery of spent fuel to the DOE. The DOE's current estimate for an available site is 2010 at the earliest.
On July 9, 2002, the United States Senate approved a resolution designating the Yucca Mountain site in Nevada as the nation's repository for used nuclear fuel. With this vote of approval, Congress formally rejected the Nevada disapproval and affirmed President Bush's decision to designate Yucca Mountain as the repository site. The DOE can now prepare and file a license application with the NRC and begin the development of a transportation policy and plan.
In return for payment of the fees prescribed by the NWPA, the federal government is to take title to and dispose of the utilities' high-level wastes and SNF. There have been numerous litigation proceedings involving the DOE's statutory and contractual obligation to accept high-level waste and SNF. While the courts have declined to order the DOE to begin accepting spent fuel for disposal on January 31, 1998, the courts have left open the utilities' ability to bring damage claims against the DOE.
In 1998, YAEC, CYAPC and MYAPC filed separate complaints against the DOE in the United States Court of Federal Claims seeking monetary damages resulting from DOE's failure to accept spent nuclear fuel for disposal. In decisions later that year, the court found liability on the part of DOE to the companies for breach of the standard contract, based upon the DOE's failure to begin disposal of spent nuclear fuel. The damages owed to YAEC, CYAPC and MYAPC as a result of DOE's failure to begin disposing of spent nuclear fuel is in litigation and revised damage claims are expected to be filed in the spring of 2003.
Until the federal government begins accepting nuclear waste for disposal, nuclear generating plants will need to retain high-level waste and spent fuel onsite or make some other provisions for its storage.
Construction of dry spent fuel storage facilities, to hold the spent nuclear fuel and other high level waste generated at those facilities until the DOE accepts this waste, is in progress at CY, MY and Yankee Rowe. No fuel has yet been moved to the dry storage facility site at CY, as this move is expected to begin by the fourth quarter of 2003 and targeted completion of the facility is by the end of 2004. Approximately 20 percent of the spent fuel has been transferred to the storage facility at MY, with completion estimated during late 2003 or early 2004. Approximately 85 percent of the spent fuel at Yankee Rowe has been moved to the storage site, with completion estimated during the second quarter of 2003.
DECOMMISSIONING
Pursuant to the Purchase and Sale Agreement with FPL for the sale of Seabrook, upon the closing of the sale on November 1, 2002, NAEC and CL&P were obligated to deliver to FPL decommissioning funds in the amount of $66.1 million. In addition, a "top off" payment of $36.8 million was made. Upon the closing, FPL assumed full responsibility for decommissioning NU's former interests in Seabrook, and NU shareholders, the NU system companies and their ratepayers have no further obligation related to decommissioning.
CYAPC and MYAPC are currently collecting revenues for the decommissioning of the related sites through their power purchasers. YAEC ceased decommissioning collections in June 2000. The table below sets forth the NU system companies' estimated share of remaining decommissioning costs of the Yankee Companies' units as of December 31, 2002. The estimates are based on the latest decommissioning cost estimates. For information on the equity ownership of the NU system companies in each of the Yankee Companies' units, see "Electric Operations-Nuclear Generation-General."
CL&P PSNH WMECO NU System
(Millions)
CY* $126.4 $18.3 $34.8 $179.5
MY* $ 53.0 $22.1 $13.3 $ 88.4
Rowe* $ 55.1 $15.7 $15.7 $ 86.5
------ ----- ----- ------
Total $234.5 $56.1 $63.8 $354.4
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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, 2002, which have been recorded as an obligation on the books of the NU system companies.
As of December 31, 2002, the Yankee Companies' share of the external decommissioning trust fund balances (at market), reflecting the contribution share provided by the NU system companies, is as follows:
CL&P PSNH WMECO NU System
(Millions)
CY $ 79.1 $11.4 $21.8 $112.3
Rowe 17.7 5.1 5.1 27.9
MY 13.1 5.4 3.3 21.8
------ ----- ----- ------
Total $109.9 $21.9 $30.2 $162.0
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As part of an ongoing review process, management of CYAPC, YAEC and MYAPC prepared preliminary revised estimates of the cost of the nuclear units owned by those companies. The estimated costs of decommissioning CY, Yankee Rowe and MY have increased by approximately $150 million, $190 million and $40 million, respectively, over prior estimates and are subject to FERC approval prior to recovery in rates by the Yankee Companies. Such prior estimated costs were included in the Yankee Companies' rates which have been approved by the FERC. The new cost estimates will be revised from time to time based on information available to the Yankee Companies regarding future costs and are attributable mainly to increases in the projected costs of spent fuel storage, security and liability and property insurance. The respective shares of the increased costs would be approximately as follows: CL&P: $103 million; PSNH: $23 million; and WMECO: $29 million.
CYAPC is required to file with FERC no later than mid-2004 for increased costs associated with the decommissioning of CYAPC. YAEC is expected to file with FERC in the spring of 2003 to renew decommissioning collections from its sponsor companies. The anticipated decommissioning collection levels, pending FERC approval, are assumed to begin in June 2003. The delay in YAEC's fuel transfer activities is expected to extend the completion of decommissioning activities to 2005. It is also anticipated that MYAPC will file with FERC no later than November 1, 2003 for new rates to be effective January 1, 2004. In the case of each of CYAPC, YAEC and MYAPC, the precise annual collection amounts and duration will be determined as part of the FERC approval process.
In January 2001, NNECO filed a written notification with the NRC reporting that during a reconciliation and verification of Millstone spent nuclear fuel records, personnel concluded that the location of two full-length irradiated fuel pins could not be determined and were not properly tracked in the records. NNECO reported that the two fuel rods are from the same fuel assembly, which was disassembled in 1972 for inspection, and were displaced from the fuel assembly in 1974. NNECO further reported that records indicate that in 1979 and 1980 the displaced rods were physically verified to be stored in a canister in the Millstone 1 spent fuel pool, and that the rods and canister are no longer in the spent fuel pool location documented in 1979 and 1980. NNECO's report indicated that records retrieved to date do not document the relocation or disposition of the two fuel rods.
On October 5, 2001, NU issued a report, following an extensive search, concerning two missing fuel pins at the retired Millstone 1 nuclear unit which was subsequently sold to DNCI. As of December 31, 2002, costs related to this search totaled $9.1 million. The report concluded that the pins are currently located in one of four facilities licensed to store low or high-level nuclear waste and that they are not a threat to public health and safety. A follow-up inspection by the NRC concluded that NU's investigation was thorough and complete and its conclusions were reasonable and supportable. These events have, however, resulted in the issuance of an NRC notice of violation and the imposition of a $288,000 civil penalty. The NRC is expected to conclude its review of this matter in 2003.
OTHER REGULATORY AND ENVIRONMENTAL MATTERS
ENVIRONMENTAL REGULATION
GENERAL
The NU system and its subsidiaries are subject to federal, state and local regulations with respect to water quality, air quality, toxic substances, hazardous waste and other environmental matters. Additionally, the NU system's major generation and transmission facilities may not be constructed or significantly modified without a review by the applicable state agency of the environmental impact of the proposed construction or modification. Compliance with increasingly more stringent environmental laws and regulations, particularly air and water pollution control requirements, may limit operations or require substantial investments in new equipment at existing facilities.
SURFACE WATER QUALITY REQUIREMENTS
The federal Clean Water Act requires every "point source" discharger of pollutants into navigable waters to obtain a National Pollutant Discharge Elimination System (NPDES) permit from the United States Environmental Protection Agency (EPA) or state environmental agency specifying the allowable quantity and characteristics of its effluent. NU system facilities are in the process of obtaining or renewing all required NPDES permits in effect. Compliance with NPDES and state water discharge permits has necessitated substantial expenditures, which are difficult to estimate, and may require further expenditures because of additional requirements that could be imposed in the future. For information regarding civil lawsuits related to alleged violations of certain facilities' NPDES permits, see Item 3, "Legal Proceedings."
The Federal Oil Pollution Act of 1990 (OPA 90) sets out the requirements for facility response plans and periodic inspections of spill response equipment at facilities that can cause substantial harm to the environment by discharging oil or hazardous substances into the navigable waters of the United States and onto adjoining shorelines. The NU system companies are currently in compliance with the requirements of OPA 90. OPA 90 includes limits on the liability that may be imposed on persons deemed responsible for release of oil. The limits do not apply to oil spills caused by negligence or violation of laws or regulations. OPA 90 also does not preempt state laws regarding liability for oil spills. In general, the laws of the states in which the NU system owns facilities and through which the NU system transports oil could be interpreted to impose strict liability for the cost of remediating releases of oil and for damages caused by releases. The NU system currently carries general liability insurance in the total amount of $160 million annual coverage, which includes liability coverage for oil spills.
AIR QUALITY REQUIREMENTS
The Clean Air Act Amendments of 1990 (CAAA), as well as state laws in Connecticut, Massachusetts and New Hampshire, impose stringent requirements on emissions of sulfur dioxide (SO2) and nitrogen oxide (NOX) for the purpose of controlling acid rain and ground level ozone. In addition, the CAAA address the control of toxic air pollutants. Installation of continuous emissions monitors and expanded permitting provisions also are included. Compliance with CAAA requirements has cumulatively cost the NU system approximately $72 million as of December 31, 2002: $11 million for CL&P, $55 million for PSNH, $1 million for WMECO, and $5 million for HWP. In addition, PSNH expects to spend approximately $3 million a year for SO2 allowances and approximately $3 million for annual operational costs for NOX controls.
Massachusetts and New Hampshire are both imposing significant emission reduction requirements on power plants, in addition to the Federal requirements. The cost for Mt. Tom Station to meet current Massachusetts emission limits is estimated to be approximately $7 million. Additional costs for compliance with expected mercury limits are unknown at this time. In New Hampshire, the emissions reduction Clear Air Bill was signed into law in May 2002. This law addresses emissions reductions of four pollutants. Oxides of nitrogen, sulfur dioxide and carbon dioxide have their emission caps established for current compliance beginning in 2007. The mercury emission cap is expected to be set prior to July 1, 2005. Estimates for compliance (excluding mercury control) are between $4 and $5 million dollars and will be better known after the mercury reduction requirement is established.
HAZARDOUS MATERIALS REGULATIONS
As many other industrial companies have done in the past, the NU system companies disposed of residues from operations by depositing or burying such materials on-site or disposing of them at off-site landfills or facilities. Typical materials disposed of include coal gasification waste, fuel oils, ash, gasoline and other hazardous materials that might contain polychlorinated biphenyls (PCBs). It has since been determined that deposited or buried wastes, under certain circumstances, could cause groundwater contamination or create other environmental risks. The NU system has recorded a liability for what it believes is, based upon currently available information, its estimated environmental remediation costs for waste disposal sites for which the NU system companies expect to bear legal liability, and continues to evaluate the environmental impact of its former disposal practices. Under federal and state law, government agencies and private parties can attempt to impose liability on NU system companies for such past disposal. At December 31, 2002, the liability recorded by the NU system for its estimated environmental remediation costs for known sites needing remediation, including those sites described below, exclusive of recoveries from insurance or from third parties, was approximately $42 million, representing 48 sites. This total includes liabilities recorded by Yankee Gas of $19.5 million. All cost estimates were made in accordance with generally accepted accounting principles where remediation costs are probable and reasonably estimable. These costs could be significantly higher if alternative remedies become necessary. These liabilities break down as follows:
1. Under the federal Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended, commonly known as Superfund, EPA has the authority to clean up or order the clean up of hazardous waste sites and to impose the clean up costs on parties deemed responsible for the hazardous waste activities on the sites. Responsible parties include the current owner of a site, past owners of a site at the time of waste disposal, waste transporters, and waste generators. The NU system currently is involved in five Superfund sites: one in Connecticut, one in New Jersey, two in New Hampshire and one in Kentucky, which could have a material impact on the NU system. The NU system has committed in the aggregate approximately $750,000 to its share of the clean up of these sites. For further information on litigation relating to the Connecticut site, see Item 3, "Legal Proceedings."
2. The greatest liabilities currently relate to former manufactured gas plant (MGP) facilities which represent the largest share of future clean up costs. These facilities were owned and operated by predecessor companies to the NU system from the mid-1800's to mid-1900. Byproducts from the manufacture of gas using coal resulted in fuel oils, hydrocarbons, coal tar, metals and other waste products that may pose risks to human health and the environment. The NU system currently has partial or full ownership responsibilities at 29 former MGP sites. Of the total NU system liabilities, $38.5 million has been established to address future remediation costs at MGP sites.
3. Other sites undergoing comprehensive investigations or remedial actions under state programs located in Connecticut, Massachusetts, New Hampshire or New Jersey include two former fuel oil releases, two landfills, two asbestos hazard abatement projects and nine miscellaneous projects. To date, approximately $2.75 million has been established to address future remediation costs at these sites.
In the past, the NU system has received other claims from government agencies and third parties for the cost of remediating sites not currently owned by the NU system but affected by past NU system disposal activities and may receive more such claims in the future. The NU system expects that the costs of resolving claims for remediating sites about which it has been notified will not be material, but cannot estimate the costs with respect to sites about which it has not been notified.
ELECTRIC AND MAGNETIC FIELDS
Published reports have discussed the possibility of adverse health effects from electric and magnetic fields (EMF) associated with electric transmission and distribution facilities and appliances and wiring in buildings and homes. Most researchers, as well as numerous scientific review panels considering all significant EMF epidemiological and laboratory studies to date, agree that current information remains inconclusive, inconsistent and insufficient for characterizing EMF as a health risk.
Based on this information, management does not believe that a causal relationship between EMF exposure and adverse health effects has been established or that significant capital expenditures are appropriate to minimize unsubstantiated risks. The NU system companies have closely monitored research and government policy developments for many years and will continue to do so.
If further investigation were to demonstrate that the present electricity delivery system is contributing to increased risk of cancer or other health problems, the industry could be faced with the difficult problem of delivering reliable electric service in a cost-effective manner while managing EMF exposures. To date, no courts have concluded that individuals have been harmed by EMF from electric utility facilities, but if utilities were to be found liable for damages, the potential monetary exposure for all utilities, including the NU system companies, could be enormous. Without definitive scientific evidence of a causal relationship between EMF and health effects, and without reliable information about the kinds of changes in utilities' transmission and distribution systems that might be needed to address the problem, if one is found, no estimates of the cost impacts of remedial actions and liability awards are available.
FERC HYDROELECTRIC PROJECT LICENSING
New Federal Power Act licenses may be issued for hydroelectric projects for terms of 30 to 50 years as determined by the FERC. Upon the expiration of an existing license, (i) the FERC may issue a new license to the existing licensee, or (ii) the United States may take over the project or the FERC may issue a new license to a new licensee, upon payment to the existing licensee of the lesser of the fair value or the net investment in the project, plus severance damages, less certain amounts earned by the licensee in excess of a reasonable rate of return.
The NU system companies currently hold FERC licenses for 11 hydroelectric projects totaling 16 plants. In addition, the NU system companies own and operate five unlicensed hydroelectric projects that are currently deemed non- jurisdictional by FERC. These licensed and unlicensed hydroelectric projects are located in Connecticut, Massachusetts and New Hampshire and aggregate approximately 1,367 MW of capacity. CL&P's and WMECO's five licensed projects and four unlicensed projects with approximately 1,302 MW of capacity were transferred to NGC in March 2000. As part of the Restructuring Settlement, PSNH has proposed to auction its seven hydroelectric projects (totaling nine plants) with approximately 65 MW of capacity upon approval of the agreement. Subsequently, the New Hampshire legislature deferred the sale of any PSNH fossil or hydroelectric facilities until at least February 2004.
NGC's FERC licenses for operation of the Falls Village and Housatonic hydroelectric projects expired in August 2001. Annual operating licenses allow NGC to continue plant operations until new licenses are granted. NGC filed an application for a new license which proposed to combine both projects under one license, in August 1999. The Connecticut Department of Environmental Protection (CDEP) has issued its Section 401 water quality certification for the combined Housatonic River Project. A draft environmental impact statement for the relicensing is anticipated in April 2003 and a final environmental impact statement is expected in October 2003. A new license for the Housatonic Project is likely to be issued in 2005. At this time, it is impossible to determine the terms and conditions of any new license, or to predict the effect of any terms and conditions on project economics.
PSNH's FERC license for the Merrimack River Hydroelectric Project that consists of the Amoskeag, Hooksett and Garvins Falls hydroelectric generating stations expires on December 31, 2005. In December 2000, PSNH filed a notice of intent with the FERC stating its plan to file an application for a new license by December 31, 2003. PSNH has begun formal consultations with federal and state resource agencies, as well as non-governmental organizations and the public. PSNH plans to file its final license application with the FERC no later than December 31, 2003. The FERC's review of license applications normally takes several years. If a new license is not issued by the expiration of the current license (December 31, 2005), it is expected that FERC will issue an annual license for the project. Annual licenses are commonly issued under the same terms and conditions as the current license, but may include new conditions if such conditions are authorized by the existing license.
Licensed operating hydroelectric projects are not generally subject to decommissioning during the license term in the absence of a specific license provision which expressly permits the FERC to order decommissioning during the license term. However, the FERC has taken the position that under appropriate circumstances it may order decommissioning of hydroelectric projects at relicensing or may require the establishment of decommissioning trust funds as a condition of relicensing. The FERC may also require project decommissioning during a license term if a hydroelectric project is abandoned, the project license is surrendered or the license is revoked.
At this time, it appears unlikely that the FERC will order decommissioning of NGC or PSNH hydroelectric projects at relicensing or that the projects will be abandoned, surrendered or the project licenses revoked. However, it is impossible to predict the outcome of FERC relicensing proceedings with certainty, or to determine the impact of future regulatory actions on project economics. Until such time as a project is ordered to be decommissioned and the terms and conditions of a decommissioning order are known, it is not possible to accurately estimate or predict the cost of project decommissioning.
EMPLOYEES
As of December 31, 2002, the NU system companies had 6,561 employees on their payrolls, excluding temporary employees, of which 2,098 were employed by CL&P, 1,252 by PSNH, 398 by WMECO, 494 by Yankee Gas, 311 by NGS, 1,426 by NUSCO, 141 by Select, 89 by SESI and 352 by SECI. NU, NGC, NAEC, Mode 1, NUEI and Select Energy Portland Pipeline, Inc. have no employees.
In response to the reduced demand for certain services and the increasingly competitive nature of their business environments, NGS and SESI eliminated some of their service lines and reduced their workforce in other parts of their businesses. As a result, during the second quarter of 2002, SESI reduced its workforce by seven employees, during the third quarter of 2002, NGS reduced its workforce by 27 employees and during the fourth quarter of 2002, Select Energy reduced its workforce by seven employees, at a total cost of approximately $1.2 million.
On September 4, 2002, NU announced a reorganization of its administrative and support-related functions to reflect the divestiture of most of its generating facilities. On September 26, 2002, 142 full time equivalent employees of NUSCO and PSNH were involuntarily terminated. Severance and other costs related to the terminations were approximately $4.8 million.
In November 2001, CL&P announced a reorganization to reflect the separation of regulated from competitive services and to refocus the organization on distribution responsibilities. The reorganization began with the selection of new officers in December 2001, with further selection processes at subsequent management levels during the first quarter of 2002. The majority of the costs associated with the reorganization is attributable to restructuring in Connecticut and is not expected to impact earnings. In connection with this process, 60 managerial and other employees of CL&P participated in a voluntary reduction program in 2002, the costs of which were approximately $8.1 million.
Approximately 2,329 employees of CL&P, PSNH, WMECO, HWP, NUSCO and Yankee Gas are covered by 16 union agreements, three of which were in negotiation as of the end of January 2003, and the remainder of which will expire between September 1, 2004 and May 31, 2006.
ITEM 2. PROPERTIES
The physical properties of the NU system are owned or leased by subsidiaries of NU. CL&P's properties are located either on land which is owned in fee or on land, as to which CL&P owns perpetual occupancy rights adequate to exclude all parties except possibly state and federal governments, which has been reclaimed and filled pursuant to permits issued by the United States Army Corps of Engineers. The principal properties of PSNH are held by it in fee. In addition, PSNH leased space in an office building under a 30- year lease which expired in March of 2002. In March of 2002, PSNH moved its headquarters to a refurbished former PSNH generating station site. A major portion of WMECO's properties are owned in fee. In 2002, NAEC sold its 35.98 percent interest in Seabrook. In addition, CL&P, PSNH and WMECO lease certain data processing equipment, vehicles, and office space. Also CL&P and WMECO lease certain substation equipment. With few exceptions, the NU system companies' lines are located on or under streets or highways, or on properties either owned or leased, or in which they have appropriate rights, easements, licenses or permits from the owners or the appropriate governmental authorities.
Yankee Gas' property consists primarily of its gas distribution facilities including distribution lines (mains and services), meter, valves, pressure regulators and flow controllers. Yankee Gas owns various propane facilities with a combined storage capacity equivalent to approximately 245,000 Mcf. Yankee Gas also owns service buildings in Meriden, Waterbury, Norwalk, and Danielson, Connecticut. Yankee Gas rents buildings in Ansonia, Danbury and Waterford, Connecticut, and leases a service building in East Windsor, Connecticut, from an affiliate, NorConn. Yankee Gas' customer information center is located in Wethersfield, Connecticut and its corporate headquarters are located in Berlin, Connecticut.
CL&P, PSNH, NGC and Yankee Gas' properties are subject to the lien of each company's respective first mortgage indentures. In addition, CL&P's interest in transmission assets is subject to a second mortgage lien for the benefit of the PCRBs. Various properties are also subject to minor encumbrances which do not substantially impair the usefulness of the properties to the owning company.
The NU system companies' properties are well maintained and are in good operating condition.
TRANSMISSION AND DISTRIBUTION SYSTEM
At December 31, 2002, the NU system companies owned 105 transmission and 351 distribution substations that had an aggregate transformer capacity of 17,221,990 kilovoltamperes (kVa) and 9,077,962 kVa, respectively; 3,075 circuit miles of overhead transmission lines ranging from 69 kilovolt (kV) to 345 kV, and 196 cable miles of underground transmission lines ranging from 69 kV to 138 kV; 33,334 pole miles of overhead and 2,331 conduit bank miles of underground distribution lines; and 433,588 line transformers in service with an aggregate capacity of 18,990,000 kVa.
ELECTRIC GENERATING PLANTS
As of December 31, 2002, the electric generating plants of the NU system companies and the NU system companies' entitlement in the generating plant of VYNPC were as follows (See "Item 1. Business - Nuclear Generation" for information on ownership and operating results for the year):
Claimed
Year Capability*
Owner Name of Plant (Location) Type Installed (kilowatts)
----- ------------------------ ---- --------- -----------
PSNH Total - Fossil-Steam Plants (6 units) 1952-74 986,805
Total - Hydro-Conventional (20 units) 1917-83 67,690
Total - Internal Combustion (5 units) 1968-70 102,792
---------
Total PSNH Generating Plant (31 units) 1,157,287
=========
HWP Total - Fossil-Steam Plants (1 unit) 1960 147,000
=========
NGC Total - Hydro-Conventional (36 units) 1903-55 157,930
Total - Hydro-Pumped (7 units) 1928-73 1,109,000
Storage
Total - Internal Combustion (1 unit) 1969 20,800
---------
Total NGC Generating Plant (44 units) 1,287,730
=========
NU System Total - Fossil-Steam Plants (7 units) 1952-74 1,133,805
Total - Hydro-Conventional (56 units) 1903-83 225,620
Total - Hydro-Pumped (7 units) 1928-73 1,109,000
Storage
Total - Internal Combustion (6 units) 1968-70 123,592
---------
Total NU System Generating Plant (76 units) 2,592,017
=========
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*Claimed capability represents winter ratings as of December 31, 2002.
FRANCHISES
CL&P. Subject to the power of alteration, amendment or repeal by the General Assembly of Connecticut and subject to certain approvals, permits and consents of public authority and others prescribed by statute, CL&P has, subject to certain exceptions not deemed material, valid franchises free from burdensome restrictions to provide electric transmission and distribution services in the respective areas in which it is now supplying such service.
In addition to the right to provide electric transmission and distribution services as set forth above, the franchises of CL&P include, among others, limited rights and powers, as set forth in Title 16 of the Connecticut General Statutes and the special acts of the General Assembly constituting its charter, to manufacture, generate, purchase and sell electricity at retail, including to provide standard offer, backup, and default service, to sell electricity at wholesale to other utility companies and municipalities and to erect and maintain certain facilities on public highways and grounds, all subject to such consents and approvals of public authority and others as may be required by law. The franchises of CL&P include the power of eminent domain.
PSNH. The NHPUC, pursuant to statutory requirement, has issued orders granting PSNH exclusive franchises free from burdensome restrictions to distribute electricity in the respective areas in which it is now supplying such service.
In addition to the right to distribute electricity as set forth above, the franchises of PSNH include, among others, rights and powers to manufacture, generate, purchase, and transmit electricity, to sell electricity at wholesale to other utility companies and municipalities and to erect and maintain certain facilities on certain public highways and grounds, all subject to such consents and approvals of public authority and others as may be required by law. The franchises of PSNH include the power of eminent domain.
NNECO. Subject to the power of alteration, amendment or repeal by the General Assembly of Connecticut and subject to certain approvals, permits and consents of public authority and others prescribed by statute, NNECO has a valid franchise free from burdensome restrictions to sell electricity to utility companies doing an electric business in Connecticut and other states.
In addition to the right to sell electricity as set forth above, the franchise of NNECO includes, among others, rights and powers to manufacture, generate and transmit electricity, and to erect and maintain facilities on certain public highways and grounds, all subject to such consents and approvals of public authority and others as may be required by law. With the sale of the Millstone in 2001, NNECO is inactive except for minor transactions associated with post-sale matters.
WMECO. WMECO is authorized by its charter to conduct its electric business in the territories served by it, and has locations in the public highways for transmission and distribution lines. Such locations are granted pursuant to the laws of Massachusetts by the Department of Public Works of Massachusetts or local municipal authorities and are of unlimited duration, but the rights thereby granted are not vested. Such locations are for specific lines only, and, for extensions of lines in public highways, further similar locations must be obtained from the Department of Public Works of Massachusetts or the local municipal authorities. In addition, WMECO has been granted easements for its lines in the Massachusetts Turnpike by the Massachusetts Turnpike Authority.
Pursuant to the Massachusetts restructuring legislation, the DTE is required to define service territories for each distribution company, including WMECO, based on the service territories actually served on July 1, 1997, and following municipal boundaries to the extent possible. The DTE has not yet defined service territories. After these service territories are established by the DTE, until they are terminated by effect of law or otherwise, the distribution company shall have the exclusive obligation to provide distribution service to all retail customers within its service territory, and no other person shall provide distribution service within such service territory without the written consent of such distribution company.
HWP and Holyoke Power and Electric Company (HP&E). HWP, and its wholly owned subsidiary HP&E, are authorized by their charters to conduct their businesses in the territories served by them. HWP's electric business is subject to the restriction that sales be made by written contract in amounts of not less than 100 horsepower to purchasers who use the electricity in their own business in the counties of Hampden or Hampshire, Massachusetts and cities and towns in these counties, and customers who occupy property in which HWP has a financial interest, by ownership or purchase money mortgage. The two companies have locations in the public highways for their transmission and distribution lines. Such locations are granted pursuant to the laws of Massachusetts by the Department of Public Works of Massachusetts or local municipal authorities and are of unlimited duration, but the rights thereby granted are not vested. Such locations are for specific lines only and, for extensions of lines in public highways, further similar locations must be obtained from the Department of Public Works of Massachusetts or the local municipal authorities. HP&E has no retail service territory area and sells electric power exclusively at wholesale. In connection with the sale of certain of HWP's and HP&E's assets to the city of Holyoke Gas and Electric Department (HG&E) effective December 2001, HWP agreed to cause the charters of HWP and HP&E to be amended to eliminate their rights to distribute electricity at retail in Holyoke and surrounding towns unless other sellers can legally compete with HG&E, and not to exercise such rights prior to such amendment.
NGC. NGC is an exempt wholesale generator and, as it currently operates its business, is not regulated by the DPUC or the DTE. FERC's authorization for exempt wholesale generators such as NGC (EWG) to sell wholesale electric power at market-based rates typically contains an exemption from much of the traditional public utility company rate regulation. As an EWG, NGC is a "public utility" subject to the Federal Power Act. The market-based rate authorization that NGC has received from FERC exempts NGC from some, but not all, of Federal Power Act regulations, including traditional cost-based rate regulation. However, NGC is required to file summary information concerning its power transactions on a quarterly basis with FERC.
Yankee Gas. Yankee Gas and its predecessors in interest hold valid franchises to sell gas in the areas in which Yankee Gas supplies gas service. Generally, Yankee Gas holds franchises to serve customers throughout Connecticut, so long as the area is not served by another gas utility. Such franchises are perpetual but remain subject to the power of alteration, amendment or repeal by the General Assembly of the State of Connecticut, the power of revocation by the DPUC and certain approvals, permits and consents of public authorities and others prescribed by statute. Yankee Gas' franchises include, among other rights and powers, rights and powers to manufacture, generate, purchase, transmit and distribute gas, to sell gas at wholesale to other utility companies and municipalities and to erect and maintain certain facilities on public highways and grounds, all subject to such consents and approvals of public authorities and others as may be required by law. The franchises include the power of eminent domain.
ITEM 3. LEGAL PROCEEDINGS
1. Con Edison, Inc. v. NU - Merger Appeals and Related Litigation
On October 13, 1999, Consolidated Edison, Inc. (Con Edison) and NU entered into an Agreement and Plan of Merger (as amended and restated as of January 11, 2001, the Merger Agreement), providing for the acquisition of NU by Con Edison, subject to the approval of various state and federal regulatory agencies.
On March 5, 2001, Con Edison advised NU that it was unwilling to close its merger with NU on the terms set forth in the Merger Agreement. That same day, NU notified Con Edison that it would treat Con Edison's refusal to proceed with the merger as a repudiation and breach of the Merger Agreement and would file suit to obtain the benefits of the transaction for NU shareholders. On March 6, 2001, Con Edison filed suit in the United States District Court for the Southern District of New York (the District Court) seeking a declaratory judgment that it had been relieved of its obligation to proceed with the merger due to, among other things, NU's alleged breach of the Merger Agreement and the alleged occurrence of a "Material Adverse Change" with respect to NU, as that term is defined in the Merger Agreement. On March 12, 2001, NU filed suit against Con Edison in the District Court seeking to recover monetary damages arising from Con Edison's breach of the Merger Agreement including, but not limited to, the amount of the acquisition premium (estimated to be $1.2 billion) together with interest at the rate established by law (9 percent).
On May 11, 2001, in accordance with a stipulation of the parties and order of the District Court, Con Edison filed an amended complaint in which it added claims seeking damages for breach of contract, fraudulent inducement and negligent misrepresentation. Con Edison has claimed that it is entitled to recover 82 percent of the synergy savings estimated by the parties to have been achievable over ten years following consummation of the merger. Con Edison contends that these estimated synergies totaled $1.754 billion and have a present value of $707 million. NU contends that Con Edison is not entitled to any damages as a matter of law.
On June 1, 2001, NU answered Con Edison's amended complaint, denying all of its material allegations and asserting affirmative defenses, and asserted a counterclaim seeking to recover monetary damages as described above against Con Edison for breach of the Merger Agreement. NU subsequently dismissed its March 12 complaint, without prejudice, since it was duplicative of the June 1 counterclaim. On June 8, 2001, Con Edison answered NU's counterclaim, denying its material allegations and asserting affirmative defenses.
In addition, separate petitions were filed with the DPUC asking that its merger approval be rescinded or reversed. The DPUC reopened its docket approving the merger and asked parties to comment on the question of whether a date certain should be imposed for consummation of the merger and whether that date should be January 31, 2002. On January 30, 2002, the DPUC issued a decision establishing January 31, 2002 as the deadline for merger consummation.
The companies completed discovery in the litigation and submitted cross motions for summary judgment. The District Court has denied Con Edison's motion in its entirety, leaving intact NU's claim for breach of the Merger Agreement and has partially granted NU's motion for summary judgment by eliminating Con Edison's claims against NU for fraud and negligent misrepresentation. No trial date has been set. At this stage of the litigation, management can predict neither the outcome of this matter nor its ultimate effect on NU.
2. Millstone - Damage to Fish Population Lawsuits
On April 20, 2000, two fishermen, Aldred Madeira, Jr. and Timothy F. Madieros, brought a lawsuit against NNECO and NUSCO in New London Superior Court alleging two counts: common law nuisance and tortious interference with a business expectancy. DNCI has since been added as an additional defendant. The lawsuit alleges that Millstone has engaged in various actions, including entrainment of winter flounder, that have caused the two fishermen to suffer damages. The suit initially sought temporary and permanent injunctions to suspend Millstone operations during the winter flounder spawning season, conversion of Millstone to a closed-cooling system, or in the alternative, permanent shutdown, as well as compensatory and punitive damages. However, the injunctive relief claims were dismissed by the Court on March 11, 2002.
On August 23, 2001, two additional fishermen, James Engelmann and Michael Stepski, brought a lawsuit similar to the Madeira and Madieros action against NNECO, NUSCO and DNCI in Superior Court alleging two counts: common law nuisance and tortious interference with a business expectancy. Like the earlier suit, plaintiffs' injunctive relief claims have been dismissed.
On December 16, 2002, the court heard argument on defendants' motion to strike both counts of the second revised complaint. A decision is pending. On February 24, 2003, the court denied plaintiffs' motion to amend the complaint to add a claim for violation of the Connecticut Unfair Trade Purchase Act.
On April 26, 2000, another lawsuit was filed in Connecticut Superior Court against NUSCO, NNECO and the Commissioner of the CDEP challenging the validity of previously issued CDEP emergency and temporary authorizations allowing Millstone to discharge wastewater not expressly authorized by the facility's NPDES permit. The suit sought a temporary and permanent injunction against operations at Millstone 1, 2 and 3. On August 30, 2000, NNECO filed a motion to dismiss, and on October 16, 2000, NNECO's motion was granted. On November 22, 2000, the Connecticut Coalition Against Millstone (CCAM) and the Long Island Coalition Against Millstone filed an appeal with the Connecticut Appellate Court. Subsequently, on May 3, 2002, NNECO and NUSCO filed a motion to dismiss the appeal on the grounds of mootness. On June 26, 2002, this motion was granted and the appeal dismissed. On November 6, 2002, plantiffs' petition to the Connecticut Supreme Court for certification to appeal this matter further was denied. This matter is now considered closed.
3. Sale of Millstone to DNCI
On February 20, 2001, the CCAM filed in Connecticut Superior Court an appeal of the DPUC's decision approving the sale of Millstone to DNCI. CCAM alleges that the final decision violates the Connecticut general statutes on multiple grounds and requests that the decision be reversed and vacated. On March 26, 2001, CCAM's appeal was dismissed. On April 16, 2001, plaintiffs filed an appeal with the Connecticut Appellate Court. On February 21, 2002, the court dismissed CCAM's appeal.
On March 8, 2001, CCAM and other parties also filed a lawsuit in Connecticut Superior Court against the CDEP, NNECO and DNCI challenging (1) the validity of Millstone's NPDES permit (Permit) and a previously issued CDEP emergency authorization allowing Millstone to discharge wastewater not expressly authorized by the facility's Permit, and (2) CDEP's authority to transfer both Millstone's permit and emergency authorization to DNCI. On March 29, 2001, CCAM's request for a temporary restraining order enjoining CDEP from transferring both the Permit and emergency authorization to DNCI prior to a full hearing was denied. Subsequently, on July 19, 2001, the entire matter was dismissed. On September 20, 2002, the Connecticut Supreme Court assigned the matter to itself. The suit has not yet been scheduled for oral argument.
4. FERC - Installed Capability (ICAP) Deficiency Charge
In July 2001, NU filed an appeal of the FERC orders imposing a $0.17 per kilowatt-month ICAP charge rate from August 1, 2000 to April 1, 2001. In December 2001, FERC denied rehearing its order allowing the $0.17 rate during the court stay period, April through August 2001. NU appealed this decision to the First Circuit Court of Appeals (First Circuit) and on October 4, 2002, the First Circuit denied the appeal.
In its December 3, 2001 report on alternatives to the ICAP requirement, ISO-New England proposed an interim advance ICAP purchase requirement but indicated that other ICAP improvements would be implemented with SMD (scheduled for late 2002 or early 2003) and that it intended to develop a forward reserves market thereafter. The ISO's interim advance purchase requirement proposal was filed with FERC in late December 2001. Subsequently, ISO-New England published the results of its study on the cost of new peaking units in New England which suggests that the level of a cost based ICAP deficiency charge would be $6.15 rather than $4.87.
5. Retirement Plan Litigation
This matter involves four separate but related federal court lawsuits by nineteen former employees of NUSCO, WMECO and CL&P who retired between 1991 and 1994. The complaints generally allege that the Company breached its fiduciary duties to the plaintiffs by making affirmative misrepresentations that caused them to retire prematurely, since as a result of these alleged misrepresentations they came to believe incorrectly that no particular future enhancement of employee benefits was being seriously considered at the time by the Company.
The cases were tried together in a summary bench trial in the United States District Court in Hartford, Connecticut in April-May 2002; post-trial briefs have been filed and the parties are awaiting the judge's decision.
6. HP&E
In July of 1998, HP&E entered into a contract with Bridgeport Energy, LLC (Bridgeport), a subsidiary of Duke Energy, to purchase ICAP at a rate of $3.125 per kilowatt per month through April 30, 2004. This contract was subsequently assigned to Select Energy. The contract contains a clause that allowed either party to terminate the contract upon 30 days prior notice if FERC, NEPOOL or ISO-New England (1) eliminates ICAP or (2) makes material changes to ICAP that materially adversely affect the parties and such changes can't be resolved through negotiation.
When ISO-New England filed with FERC in May 2000 to eliminate the ICAP product, Select Energy sought to terminate the contract. Pending the resolution of the ICAP issues at FERC and in court, the parties entered into a series of agreements to preserve their rights to argue whether the contract should be terminated, during which time Bridgeport continued to supply, and Select Energy continued to pay for, the ICAP. In June 2001, Select Energy discontinued purchasing the ICAP from Bridgeport. In July 2001, Select Energy filed a complaint in Connecticut Superior Court, requesting the court to declare that the contract was terminated as of June 2000, asking for an order that the contract was effectively terminated in June 2000 and requesting damages for the above-market portion of its payment. Bridgeport filed a complaint in Connecticut Superior Court shortly thereafter, alleging that Select Energy is in default under the contract and owes damages from June of 2000 through the remainder of the term of the contract. A settlement in this matter was reached on November 12, 2002.
7. Wisvest-Connecticut, LLC (Wisvest) v. Select Energy
Wisvest filed suit in July 2002 against Select Energy in the Superior Court at New Britain, Connecticut. In its complaint, Wisvest alleges that Select Energy breached its Load Asset Contract for Electrical Load dated November 23, 1999 (the Agreement) by unilaterally reducing the amount of electricity it proposed to purchase from Wisvest. Wisvest alleged that the Agreement obligated Select Energy to purchase from Wisvest 11.5 percent of the CL&P Standard Offer Service Load (Load) during the term of the Agreement, but that in February 2002 it unilaterally announced that it would thereafter purchase only 9.4 percent of the CL&P Load. The complaint seeks monetary damages and a declaratory judgment declaring that Select Energy has no right to unilaterally alter its obligation to receive and purchase 11.5 percent of the CL&P Load.
Select Energy has filed an Answer to the complaint, denying any liability. It has also filed several special defenses and counterclaims. No trial date has been set.
8. NRG - Credit Rating Status
Recent changes in the credit status of NRG have impacted the contractual relationships between NRG and CL&P, Yankee Gas and Select Energy. On July 26 and 29, 2002, the three major ratings agencies lowered the ratings of NRG to below investment grade. Concurrently, the potential, but now postponed, deactivation of NRG owned generating units in the state of Connecticut further called into question NRG's financial viability and the long term availability of power to serve CL&P's standard offer customers. On September 16, 2002, NRG announced its failure to meet a September 13, 2002 deadline by which it was to post collateral in excess of $1 billion and that it had not made payments on certain debt issues dues on September 16, 2002. On November 22, 2002, an involuntary bankruptcy case was filed against NRG by seven former NRG executives. A proposed settlement between NRG and the former executives is scheduled for hearing on March 27, 2003 and objections to the dismissal of the case pursuant to the settlement must be filed on or before March 20, 2003. In addition, on February 27, 2003, lenders under a revolving credit agreement accelerated the repayment of $1 billion of NRG debt. On February 28, 2003, two NRG creditors filed to join the pending involuntary case.
Yankee Gas
On November 12, 2002, NRG affiliate Meriden Gas Turbines, LLC (MGT) filed suit against Yankee Gas in Superior Court in Meriden, Connecticut. MGT claims, among other things, that Yankee Gas breached its obligations under a transportation, construction and interconnection service agreement (MGT Agreement) entered into in December 2001 in connection with a Meriden power plant project. MGT seeks a declaratory ruling from the court that Yankee Gas was not entitled to draw down a $16 million letter of credit issued in its favor in connection with the MGT Agreement. Yankee Gas intends to defend this case vigorously and will file a response to the complaint early in 2003.
CL&P
On December 20, 2002, FERC issued an order in connection with a dispute between CL&P and NRG concerning the provision of station service to Connecticut generating plants purchased from CL&P by NRG affiliates in December 1999. CL&P filed a complaint at FERC seeking interpretation of a FERC-filed interconnection agreement in which NRG agreed to pay CL&P's applicable retail rates for station service power (if procured from CL&P) and delivery of such power (whether procured from CL&P or a third party supplier). FERC further affirmed the language in its Order 888 concerning state jurisdiction over the delivery of power to end users, even in the absence of distribution facilities, and the state's authority to impose certain charges on end users, such as those associated with stranded cost recovery. CL&P has made a demand upon NRG for payment of $13.3 million in station service charges through January 2003 and is preparing to take any steps necessary to collect the unpaid balance.
Select Energy
Select Energy, also concerned about NRG's solvency and ability to continue to meet the terms of its contracts, terminated its contractual relationships with NRG and its affiliates on August 15, 2002 as a result of NRG's failure to provide adequate financial assurances. Subsequent to this date, Select Energy calculated its damages and forwarded final payment to NRG. On November 1, 2002, Select Energy received NRG's protest to Select Energy's calculation of damages, to which Select Energy responded that its calculations were in accord with the underlying contracts.
9. Enron Power Marketing, Inc. (Enron)/Select Energy
On January 13, 2003, Select Energy received notice from the United States Bankruptcy Court of an adverse proceeding filed by Enron against Select Energy for approximately $2.5 million. In its complaint, Enron alleges that Select Energy improperly set off pre-petition debt arising from the termination of transactions entered into under a power purchase agreement between Select Energy and Enron against post-petition amounts owed for deliveries of power under transactions entered into under the same agreement. On February 19, 2003, in substitution of an answer to the complaint, Select Energy filed a motion for relief from the automatic stay and to compel arbitration, or, alternatively, to dismiss. On March 4, 2003, the Court issued an order directing mediation of all adversary proceedings involving trading agreements, including those of Select Energy, and further stayed all pending motions seeking to modify the automatic stay in order to seek arbitration. In accordance with the Court's Order, Select Energy filed a brief summary of the essential issues in its proceedings with the mediation judge and subsequently participated in the initial mediation conference on March 12, 2003.
10. Hawkins, Delafield & Wood (Hawkins) v. NU, NUSCO and CL&P
On December 12, 2002, Hawkins, a New York law firm sued by the Connecticut Resources Recovery Authority (CRRA) as a result of the Enron bankruptcy, brought an apportionment complaint against a number of former Enron officers, directors and outside accountants. In addition to the Enron defendants, Hawkins also named as defendants in its complaint NU, NUSCO and CL&P. Hawkins asserts in its complaint that in the event it is found liable to CRRA, then the apportionment defendants, including NU, NUSCO and CL&P, are responsible for some or all of the $220 million claimed as damages. The NU defendants will file their appearance in the case by January 28, 2003, and will file a response to the complaint, in the form of a pre-answer dispositive motion, on or before February 27, 2003.
The case is proceeding along three broad tracks: (a) an attempt by various defendants to persuade the Multi-District Litigation (MDL) Judicial Panel to transfer the case to the United States District Court for the Southern District of Texas; (b) an attempt to consolidate this case with a case now pending, which itself is subject to a conditional order of the MDL Panel transferring it to the Southern District of Texas; and (c) an attempt to remand this case to Connecticut's state court. No further action in this case is anticipated until the MDL Panel rules, as the United States District Court judge has stayed all proceedings pending such ruling. The NU defendants had not yet responded to the apportionment complaint at the time the proceedings were stayed.
11. Environmental Litigation
On September 25, 2002, NUSCO, among other defendants, was sued by the Joseph A. Schiavone Corporation (Schiavone) under the Comprehensive Environmental Response, Compensation and Liability Act of 1980 for the costs associated with the investigation and remediation of a commercial property owned by Schiavone in North Haven, Connecticut. Schiavone alleges that from 1968 through 1978, NUSCO sold transformers containing PCBs to a company named H. Kasden & Sons, a co-defendant, which owned the property before Schiavone and operated a scrap yard at the site. The property is currently involved in an EPA and CDEP monitored investigation and remediation of PCB contamination and related costs are estimated at approximately $4 million.
NUSCO has answered the complaint denying the material allegations. Discovery will commence in January. After a status conference held on February 13, 2003, a United States Magistrate entered a case management plan and ordered the parties to report back by March 13, 2003 regarding settlement potential.
12. Other Legal Proceedings
The following sections of Item 1, "Business" discuss additional legal proceedings: See "Rates and Electric Industry Restructuring" for information about various state restructuring proceedings and civil lawsuits related thereto and the implementation of SMD; "Regulated Electric Operations" and "Regulated Gas Operations" for information about proceedings relating to power, transmission and pricing issues; "Regulated Electric Operations - Nuclear Generation" for information related to nuclear plant performance, nuclear fuel enrichment pricing, high-level and low-level radioactive waste disposal, decommissioning matters, and NRC regulation; "Other Regulatory and Environmental Matters" for information about proceedings involving surface water and air quality, toxic substances and hazardous waste, EMF, licensing of hydroelectric projects, and other matters.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No event that would be described in response to this item occurred with respect to NU, PSNH or WMECO.
CL&P. In a written Consent in Lieu of a Special Meeting of Stockholders of CL&P (Company) (Consent) dated October 25, 2002, the stockholders voted to sell the Company's ownership interest in the Seabrook Nuclear Power Station (Seabrook) pursuant to that Purchase and Sale Agreement dated April 13, 2002 (Agreement) by and among the Company, certain other owners of Seabrook, North Atlantic Energy Service Corporation, and the buyer, FPL Energy Seabrook, LLC (Buyer), in consideration of the total purchase price of $836,610,000, subject to adjustment as provided in the Agreement. The vote authorizing the sale was 6,035,205 shares in favor, representing 100 percent of the issued and outstanding shares of common stock of CL&P.
PART II
ITEM 5. MARKET FOR THE REGISTRANTS' COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS
NU. The common shares of NU are listed on the New York Stock Exchange. The ticker symbol is "NU," although it is frequently presented as "Noeast Util" and/or "NE Util" in various financial publications. The high and low closing sales prices for the past two years, by quarters, are shown below.
Year Quarter High Low
---- ------- ---- ---
2002 First $19.87 $17.61
Second 20.57 18.05
Third 18.45 13.84
Fourth 16.97 13.20
2001 First $23.56 $16.80
Second 20.75 17.35
Third 20.79 18.30
Fourth 19.25 16.95
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As of January 31, 2003, there were 65,176 common shareholders of record of NU. As of the same date, there were a total of 131,161,040 common shares issued, including 3,755,714 unallocated Employee Stock Ownership Plan (ESOP) shares held in the ESOP trust.
On January 13, 2003, the NU Board of Trustees approved the payment of a 13.75 cent per share dividend, payable on March 31, 2003, to shareholders of record as of March 1, 2003.
On January 8, 2002, the NU Board of Trustees approved the payment of a 12.5 cent per share dividend, payable on March 29, 2002, to shareholders of record as of March 1, 2002.
On April 19, 2002, the NU Board of Trustees approved the payment of a 12.5 cent per share dividend, payable on June 28, 2002, to shareholders of record as of June 1, 2002.
On May 14, 2002, the NU Board of Trustees approved the payment of a 13.75 cent per share dividend, payable on September 30, 2002, to shareholders of record as of September 1, 2002.
On October 8, 2002, the NU Board of Trustees approved the payment of a 13.75 cent per share dividend, payable on December 31, 2002, to shareholders of record as of December 1, 2002.
On January 9, 2001, the NU Board of Trustees approved the payment of a 10 cent per share dividend, payable on March 31, 2001, to shareholders of record as of March 1, 2001.
On April 9, 2001, the NU Board of Trustees approved the payment of a 10 cent per share dividend, payable on June 29, 2001, to shareholders of record as of June 1, 2001.
On June 28, 2001, the NU Board of Trustees approved the payment of a 12.5 cent per share dividend, payable on September 28, 2001, to shareholders of record as of September 1, 2001.
On October 9, 2001, the NU Board of Trustees approved the payment of a 12.5 cent per share dividend, payable on December 31, 2001, to shareholders of record as of December 1, 2001.
Information with respect to dividend restrictions for NU and its subsidiaries is contained in Item 1. Business under the caption "Financing Program - Financing Limitations" and in Note (a) to the "Consolidated Statements of Shareholders' Equity" on page 37 of NU's 2002 Annual Report to Shareholders, which information is incorporated herein by reference.
CL&P, PSNH and WMECO. There is no established public trading market for the common stock of CL&P, PSNH and WMECO. The common stock of CL&P, PSNH and WMECO is held solely by NU.
During 2002 and 2001, CL&P approved and paid approximately $60.1 million of common stock dividends to NU.
During 2002 and 2001, PSNH approved and paid approximately $45 million and $27 million of common stock dividends, respectively, to NU.
During 2002 and 2001, WMECO approved and paid approximately $16 million and $22 million of common stock dividends, respectively, to NU.
ITEM 6. SELECTED FINANCIAL DATA
NU. Reference is made to information under the heading "Selected Consolidated Financial Data" contained on page 63 of NU's 2002 Annual Report to Shareholders, which information is incorporated herein by reference.
CL&P. Reference is made to information under the heading "Selected Consolidated Financial Data" contained on page 25 of CL&P's 2002 Annual Report, which information is incorporated herein by reference.
PSNH. Reference is made to information under the heading "Selected Consolidated Financial Data" contained on page 24 of PSNH's 2002 Annual Report, which information is incorporated herein by reference.
WMECO. Reference is made to information under the heading "Selected Consolidated Financial Data" contained on page 22 of WMECO's 2002 Annual Report, which information is incorporated herein by reference.
ITEM 7. 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 on pages 15 through 31 and pages 47 through 49, respectively, of NU's 2002 Annual Report to Shareholders, which information is incorporated herein by reference.
CL&P. Reference is made to information under the heading "Management's Discussion and Analysis of Financial Condition and Results of Operations" contained on pages 1 through 8 of CL&P's 2002 Annual Report, which information is incorporated herein by reference.
PSNH. Reference is made to information under the heading "Management's Discussion and Analysis of Financial Condition and Results of Operations" contained on pages 1 through 7 of PSNH's 2002 Annual Report, which information is incorporated herein by reference.
WMECO. Reference is made to information under the heading "Management's Discussion and Analysis of Financial Condition and Results of Operations" contained on pages 1 through 6 of WMECO's 2002 Annual Report, which information is incorporated herein by reference.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
NU. Reference is made to information under the headings "Company Report," "Independent Auditor's Report," "Report of Independent Public Accountants," "Consolidated Balance Sheets," "Consolidated Statements of Income," "Consolidated Statements of Comprehensive Income," "Consolidated Statements of Shareholders' Equity," "Consolidated Statements of Cash Flows," "Consolidated Statements of Capitalization," "Consolidated Statements of Income Taxes," "Notes to Consolidated Financial Statements," and "Consolidated Statements of Quarterly Financial Data" contained on pages 32 through 62 of NU's 2002 Annual Report to Shareholders, which information is incorporated herein by reference.
CL&P. Reference is made to information under the headings "Independent Auditor's Report," "Report of Independent Public Accountants," "Consolidated Balance Sheets," "Consolidated Statements of Income," "Consolidated Statements of Comprehensive Income," "Consolidated Statements of Common Stockholder's Equity," "Consolidated Statements of Cash Flows," "Notes to Consolidated Financial Statements," and "Consolidated Quarterly Financial Data" contained on pages 9 through 25 of CL&P's 2002 Annual Report, which information is incorporated herein by reference.
PSNH. Reference is made to information under the headings "Independent Auditor's Report," "Report of Independent Public Accountants," "Consolidated Balance Sheets," "Consolidated Statements of Income," "Consolidated Statements of Comprehensive Income," "Consolidated Statements of Common Stockholder's Equity," "Consolidated Statements of Cash Flows," "Notes to Consolidated Financial Statements," and "Consolidated Quarterly Financial Data" contained on pages 8 through 24 of PSNH's 2002 Annual Report, which information is incorporated herein by reference.
WMECO. Reference is made to information under the headings "Independent Auditor's Report," "Report of Independent Public Accountants," "Consolidated Balance Sheets," "Consolidated Statements of Income," "Consolidated Statements of Comprehensive Income," "Consolidated Statements of Common Stockholder's Equity," "Consolidated Statements of Cash Flows," "Notes to Consolidated Financial Statements," and "Consolidated Quarterly Financial Data" contained on pages 7 through 22 of WMECO's 2002 Annual Report, which information is incorporated herein by reference.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
No unreported event that would be described in response to this item has occurred with respect to NU, CL&P, PSNH or WMECO.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS
NU.
In addition to the information provided below concerning the executive officers of NU, incorporated herein by reference is the information contained in the sections "Proxy Statement", "Election of Trustees", "Board Committees and Responsibilities", and "Section 16(a) Beneficial Ownership Reporting Compliance", of the definitive proxy statement for solicitation of proxies by NU's Board of Trustees, dated March 27, 2003, which will be filed with the Commission pursuant to Rule 14a-6 under the Securities Exchange Act of 1934.
Positions
Name Held
------------------------ ---------
Gregory B. Butler (*) VP, SEC, GC
John H. Forsgren (*) EVP, CFO, VC, T
Cheryl W. Grise (*) P
Bruce D. Kenyon (*)(**) P
Michael G. Morris (*) CHB, P, CEO, T
Charles W. Shivery (*) P
|
CL&P.
Positions
Name Held
------------------------ ---------
David H. Boguslawski VP, D
Gregory B. Butler (*) OTH
John H. Forsgren (*) OTH
Cheryl W. Grise (*) CEO, D
Michael G. Morris (*) OTH
Leon J. Olivier (*) P, COO, D
|
PSNH.
Positions
Name Held
------------------------ ---------
David H. Boguslawski VP, D
Gregory B. Butler (*) OTH
John C. Collins (***) D
John H. Forsgren (*) OTH, D
Cheryl W. Grise (*) CEO, D
Gerald Letendre (***) D
Gary A. Long (*) P, COO, D
Michael G. Morris (*) CH, D
Jane E. Newman (***) D
|
WMECO.
Positions
Name Held
------------------------ ---------
David H. Boguslawski VP, D
Gregory B. Butler (*) OTH
James E. Byrne (***) D
John H. Forsgren (*) OTH, D
Cheryl W. Grise (*) CEO, D
Kerry J. Kuhlman (*) P, COO, D
Paul J. McDonald (***) D
Michael G. Morris (*) CH, D
Melinda M. Phelps (***) D
|
* Executive Officer ** Retired as of the close of business on December 31, 2002. *** Resigned as of the close of business on December 31, 2002.
Key:
CEO - Chief Executive Officer OTH - Executive Officer of
CFO - Chief Financial Officer Registrant because of policy-
CH - Chairman making function for NU system
CHB - Chairman of the Board P - President
COO - Chief Operating Officer SEC - Secretary
D - Director SVP - Senior Vice President
EVP - Executive Vice President T - Trustee
GC - General Counsel VP - Vice President
VC - Vice Chairman
Name Age Business Experience During Past 5 Years
----------------------- --- ---------------------------------------
David H. Boguslawski 48 Vice President - Transmission Business of
CL&P, PSNH and WMECO since May 1, 2001 and a
Director of CL&P, PSNH and WMECO since June 30,
1999; previously Vice President - Energy Delivery
of CL&P, PSNH and WMECO from September 1996 to
May 2001.
Gregory B. Butler 45 Vice President, Secretary and General
Counsel of NU since May 1, 2001 and a Director of
Northeast Utilities Foundation, Inc. since
December 1, 2002; previously Vice President-
Governmental Affairs of NUSCO from January 1997
to May 2001; Vice President of Federal Affairs at
New England Electric System from January 1995 to
December 1996; and senior counsel for Niagara
Mohawk Power Corporation from December 1992 to
January 1995.
James E. Byrne 48 Partner, Finneran, Byrne & Dreshsler,
L.L.P., since 1982. Director of WMECO from
September 1999 through December 2002.
John C. Collins (1) 57 Chief Executive Officer, Dartmouth-
Hitchcock Clinic, Dartmouth-Hitchcock Medical
Center since 1977. Director of PSNH from October
1992 through December 2002.
John H. Forsgren (2) 56 Vice Chairman of NU since May 1, 2001;
Executive Vice President and Chief Financial
Officer of NU since February 1, 1996; Executive
Vice President and Chief Financial Officer of
CL&P, PSNH, and WMECO since February 27, 2003 and
from February 1996 to June 1999; Director of
WMECO since June 10, 1996 and of PSNH since
August 5, 1996 and a Director of Northeast
Utilities Foundation, Inc. since September 23,
1998; Director of CL&P from June 1996 to June
1999.
Cheryl W. Grise (3) 50 President - Utility Group of NU since
May 2001, Chief Executive Officer of CL&P, PSNH
and WMECO since September 10, 2002 a Director of
CL&P since May 1, 2001, PSNH since May 14, 2001
and WMECO since June 2001, and a Director of
Northeast Utilities Foundation, Inc. since
September 23, 1998; previously President of CL&P
from May 2001 to September 2001, Senior Vice
President, Secretary and General Counsel of NU
from July 1998 to May 2001, Senior Vice
President, Secretary and General Counsel of CL&P,
and PSNH and Senior Vice President, Secretary,
Assistant Clerk and General Counsel of WMECO from
July 1998 to June 1999 and Senior Vice President,
Secretary and General Counsel of NGC from January
1999 to June 1999; previously Director of CL&P
and WMECO (January 1994 through November 1997)
and PSNH (February 1995 through November 1997);
Senior Vice President and Chief Administrative
Officer of CL&P and PSNH, and Senior Vice
President of WMECO from 1995 to 1998.
Bruce D. Kenyon 60 Retired January 1, 2003; previously
President-Generation Group of NU from March 1999
through December 2002 and a Director of Northeast
Utilities Foundation, Inc. from September 1998
through December 2002; President-Generation Group
of CL&P, PSNH and WMECO from March 1999 to June
1999; President-Nuclear Group of NU, CL&P, PSNH
and WMECO from September 1996 to March 1999, a
Director of CL&P and WMECO from September 1996 to
June 1999, and a Director of PSNH from November
1997 to June 1999.
Kerry J. Kuhlman 52 President and Chief Operating Officer
and a Director of WMECO since April 1999;
previously Vice President-Customer
Operations of WMECO from October 1998 to April
1999; Vice President-Central Region of CL&P from
August 1997 to October 1998; and Vice President-
Eastern Region of CL&P from July 1994 to August
1997.
Gerald Letendre (4) 61 President, Diamond Casting & Machine Co.,
Inc. since 1972. Director of PSNH from October
1992 through December 2002.
Gary A. Long 51 President and Chief Operating Officer
and a Director of PSNH since July 1, 2000;
previously Senior Vice President-PSNH of PSNH
from February 2000 through June 2000 and Vice
President-Customer Service and Economic
Development of PSNH from January 1994 to February
2000.
Paul J. McDonald (5) 59 Advisor to the Board of Directors, Friendly
Ice Cream Corporation since January 2000;
Director of WMECO from September 1999 through
December 2002; previously Senior Executive Vice
President and Chief Financial Officer, Friendly
Ice Cream Corporation from 1986 to 1999.
Michael G. Morris (6) 56 Chairman of the Board, President and Chief
Executive Officer and a Trustee of NU and
Chairman and a Director of PSNH and WMECO since
August 19, 1997 and a Director of Northeast
Utilities Foundation, Inc. since September 23,
1998; previously Chief Executive Officer of PSNH
from August 19, 1997 through March 1, 2000 and
from July 1, 2000 through September 10, 2002;
Chief Executive Officer of WMECO from June 30,
1999 to September 10, 2002; Chairman and a
Director of CL&P from August 1997 to June 1999;
and President and Chief Executive Officer of
Consumers Power Company from 1994 to 1997.
Jane E. Newman (7) 57 Executive Dean, Harvard University's
John F. Kennedy School of Government since July
2000; Director of PSNH from October 1992 through
December 2002. Previously Managing Director, The
CommerceGroup, LLC, a strategic communications
company, from January 1999 to July 2000; and
Dean, Whittemore School of Business and Economics
of the University of New Hampshire from January
1998 to January 1999; Executive Vice President
and Director of Exeter Trust Company from 1995 to
1997.
Leon J. Olivier 54 President and Chief Operating Officer
and a Director of CL&P since September 2001;
previously Senior Vice President of Entergy
Nuclear Corp. from April 2001 to September 2001;
Senior Vice President and Chief Nuclear Officer
of Northeast Nuclear Energy Company from October
1998 to May 2001; and Senior Vice President,
Nuclear of Boston Edison Company from 1997 to
October 1998.
Melinda M. Phelps 46 Partner, Bulkley, Richardson & Gelinas,
LLP since January 1, 2001; Director of WMECO from
September 1999 through December 2002. Previously
of counsel to Bulkley, Richardson & Gelinas, LLP,
from May 2000 through December 2000 and partner,
Keyes and Donnellan, P.C., from 1992 to 2000.
Charles W. Shivery 57 President-Competitive Group of NU and
President and Chief Executive Officer of NU
Enterprises, Inc., since June 2002; previously Co-
President of Constellation Energy Group, Inc.
from October 2000 to February 2002; President and
Chief Executive Officer of Constellation Power
Source Holdings, Inc., from July 2000 to February
2002; Chief Executive Officer and President of
Constellation Enterprises, Inc. from 1998 to
February 2002; and Chairman of the Board,
President and Chief Executive Officer of
Constellation Power Source, Inc., from 1997 to
February 2002.
|
(1) Mr. Collins is a Director of Blue Cross and Blue Shield of Vermont, The
Vermont Health Plan, and Hamden Assurance Company Limited.
(2) Mr. Forsgren is a Director of NEON Communications, Inc. and CuraGen
Corporation, and a member of the Board of Regents of Georgetown
University.
(3) Mrs. Grise is a Director of Dana Corporation, University of Connecticut
Foundation and American Red Cross, Greater Hartford Chapter.
(4) Mr. Letendre is a Director of the National Association of Manufacturers
(Washington, DC).
(5) Mr. McDonald is a Director of CIGNA Investments Inc. and Polytainer's, LLC
(Toronto, Canada).
(6) Mr. Morris is a Director of the Edison Electric Institute, the American
Gas Association, Nuclear Electric Insurance Limited, St. Francis Care,
Inc., Connecticut Business & Industry Association, the Webster Financial
Corporation, and the Spinnaker Exploration Co. Mr. Morris is also a
Regent of Eastern Michigan University.
(7) Ms. Newman is a Director of Citizens Advisors.
There are no family relationships between any director or executive officer and any other director or executive officer of NU, CL&P, PSNH or WMECO.
ITEM 11. EXECUTIVE COMPENSATION
NU
Incorporated herein by reference is the information contained in the sections "Executive Compensation," "Long-Term Incentive Plans - Awards in Last Fiscal Year," "Pension Benefits," "Trustee Compensation," "Employment Contracts and Termination of Employment Arrangements," "Compensation Committee Report on Executive Compensation" and "Share Performance Chart" of the definitive proxy statement for solicitation of proxies by NU's Board of Trustees, dated March 27, 2003, which will be filed with the Commission pursuant to Rule 14a-6 under the Securities Exchange Act of 1934.
SUMMARY COMPENSATION TABLE
CL&P, PSNH, WMECO
The following tables present the cash and non-cash compensation received by the Chief Executive Officer and the next four highest paid executive officers of CL&P, PSNH, and WMECO accordance with rules of the SEC:
---------------------------------------------------------------------------------------------------------------
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 Compensation ($) Appreciation Payouts sation ($)
Principal Position Year ($) Bonus ($) ($) (Note 1) (Note 2) Rights (#) ($) (Note 3)
---------------------------------------------------------------------------------------------------------------
Michael G. Morris 2002 915,385 558,000 209,883 - 630,600 - 27,462
Chairman of the
Board, President 2001 900,000 869,805 238,924 - 220,000 - 27,000
and Chief Executive
Officer of NU and 2000 830,770 1,200,000 196,964 - 140,000 - 27,326
Chairman of
PSNH and WMECO
John H. Forsgren 2002 556,154 165,000 - - 54,400 - 179,674
Executive Vice
President and 2001 524,423 200,000 - - 98,000 - 5,100
Chief Financial
Officer and Vice 2000 444,615 450,000 - - 36,000 - 5,100
Chairman of NU
Cheryl W. Grise 2002 409,231 280,000 - - 39,600 - 180,523
President -
Utility Group of NU 2001 338,654 180,000 - - 76,000 - 10,119
and Chief Executive
Officer of CL&P, 2000 279,616 290,000 - - 23,000 - 8,795
PSNH and WMECO
Gregory B. Butler 2002 206,154 70,000 - - 13,200 - 6,000
Vice President,
Secretary and 2001 189,269 70,000 - - 7,600 - 5,100
General Counsel of
NU and NUSCO 2000 174,462 105,000 - - 9,000 72,995 5,100
Leon J. Olivier 2002 303,908 138,000 - - 9,900 9,117
President and Chief
Operating Officer 2001 194,232 123,000 - 100,009 22,500 -
of CL&P
(CL&P Table Only) 2000 274,462 165,000 - - 13,000 9,261
Gary A. Long 2002 178,154 70,000 - - 8,100 6,000
President and Chief
Operating Officer 2001 171,846 55,000 - - 6,750 5,100
of PSNH
(PSNH Table Only) 2000 152,137 91,000 - - 6,500 4,564
Kerry J. Kuhlman 2002 173,093 62,000 - - 7,900 5,193
President and Chief
Operating Officer 2001 166,846 45,000 - - 6,200 5,005
of WMECO
(WMECO Table Only) 2000 161,539 90,000 - - 7,500 4,846
|
<CAPTION
OPTION/SAR GRANTS IN LAST FISCAL YEAR
-----------------------------------------------------------------------------------------------------------
Individual Grants Grand Date Value
----------------- ----------------
Number of % of Total
Securities Options/SARs
Underlying Granted to Exercise or Grant Date
Options/SARs Employees Base Price Expiration Present
Name Granted (#) in Fiscal Year ($/sh) Date Value ($)
-----------------------------------------------------------------------------------------------------------
Michael G. Morris 130,600 9.77 18.58 2/25/2012 797,966 (Note 4)
500,000 37.39 16.55 8/20/2012 1,985,000 (Note 5)
John H. Forsgren 54,400 4.07 18.58 2/25/2012 332,384 (Note 4)
Cheryl W. Grise 39,600 2.96 18.58 2/25/2012 241,956 (Note 4)
Gregory B. Butler 13,200 0.99 18.58 2/25/2012 80,652 (Note 4)
Leon J. Olivier 9,900 0.74 18.58 2/25/2012 60,489 (Note 4)
Gary A. Long 8,100 0.61 18.58 2/25/2012 49,491 (Note 4)
Kerry J. Kuhlman 7,900 0.59 18.58 2/25/2012 48,269 (Note 4)
|
AGGREGATED OPTIONS/SAR EXERCISES IN LAST
FISCAL YEAR AND FY-END OPTION/SAR VALUES
-------------------------------------------------------------------------------------------------------
Shares With
Respect to Number of Securities Value of Unexercised
Which Underlying Unexercised In-the-Money
Options Were Value Options/SARs Options/SARs
Exercised Realized at Fiscal Year End (#) at Fiscal Year End ($)
Name (#) ($) Exercisable Unexercisable Exercisable Unexercisable
-------------------------------------------------------------------------------------------------------
Michael G. Morris - - 849,591 823,935 2,794,204 -
John H. Forsgren 60,116 258,198 102,584 131,735 - -
Cheryl W. Grise - - 73,292 97,936 4,583 -
Gregory B. Butler - - 24,249 21,267 1,986 -
Leon J. Olivier - - 3,334 19,900 - -
Gary A. Long - - 13,282 14,768 891 -
Kerry J. Kuhlman - - 14,329 14,535 955 -
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Notes to Summary Compensation and Option/SAR Grants Tables:
1. Other annual compensation for Mr. Morris includes personal use of the Company's airplane, having a cost to the Company of $180,886 in 2002, $219,088 in 2001, and $173,357 in 2000.
2. At December 31, 2002, the aggregate restricted stock holdings by the individuals named in the table were 36,978 shares with a value of $560,956. No restricted shares were awarded as incentive compensation to these individuals in 2002; payment of 50 percent of the 2001 annual bonus of each of Mr. Morris, Mr. Forsgren, and Mrs. Grise was made on February 25, 2002 in the form of restricted shares vesting one-third on February 25, 2003, February 25, 2004, and February 25, 2005. Dividends on restricted stock are paid out.
3. "All Other Compensation" for 2002 consists of employer matching contributions under the Northeast Utilities Service Company 401k Plan, generally available to all eligible employees (each of Messrs. Morris, Forsgren, Butler and Mrs. Grise - $6,000, Mr. Long - $5,345 and Ms. Kuhlman - $5,193) and matching contributions under the Deferred Compensation Plan for Executives (Mr. Morris - $21,462, Mrs. Grise - $6,277 and Mr. Olivier - $9,117). For Mr. Forsgren and Mrs. Grise, it also includes vested deferred compensation paid out on June 28, 2002 of $173,674 and $168,246 respectively (See Employment Contracts and Termination of Employment and Change in Control Arrangements, Below).
4. These options were granted on February 25, 2002 under the Northeast Utilities Incentive Plan (Incentive Plan). All options granted vest one-third on February 25, 2003, one-third on February 25, 2004 and one-third on February 25, 2005. Valued using the Black-Scholes option pricing model, discounted by 5.88% to reflect the risk of forfeiture, with the following assumptions: Volatility: 24.33 percent (36 months of monthly data); Risk-free rate: 5.18 percent; Dividend yield: 1.82 percent; Exercise date: February 25, 2012.
5. These options were granted on November 1, 2002 under the Incentive
Plan. All options granted vest one-third on November 1, 2003, one-
third on November 1, 2004 and one-third on November 1, 2005. Valued
using the Black-Scholes option pricing model, discounted by 14.13% to
reflect the risk of forfeiture, with the following assumptions:
Volatility: 23.09 percent (36 months of monthly data); Risk-free
rate: 4.47 percent; Dividend yield: 2.44 percent; Exercise date:
November 1, 2012.
LONG-TERM INCENTIVE PLANS - AWARDS IN LAST FISCAL YEAR
Grants of performance units were made during 2002 under the Incentive Plan to the Company's officers. Payments will be made in cash following the close of the performance period. Threshold, target, and maximum payouts will be determined based on average annual rate of growth in net earnings over the performance period. Grants to the executive officers named in the Summary Compensation Table were as follows:
Estimated Future Payouts
Under Non-Stock Price-Based Plans
---------------------------------
(a) (b) (c) (d) (e) (f)
Number of Performance
Shares, or Other
Units or Period Until
Other Maturation
Rights Or Payout Threshold Target Maximum
Name (#) ($) ($) ($)
---- -------- ------------------- --------- ------ -------
Michael G. Morris 9,900 1/1/2002-12/31/2004 396,000 990,000 1,386,000
John H. Forsgren 4,125 1/1/2002-12/31/2004 165,000 412,500 577,500
Cheryl W. Grise 3,000 1/1/2002-12/31/2004 120,000 300,000 420,000
Gregory B. Butler 1,000 1/1/2002-12/31/2004 40,000 100,000 140,000
Leon J. Olivier 750 1/1/2002-12/31/2004 30,000 75,000 105,000
Gary A. Long 616 1/1/2002-12/31/2004 24,640 61,600 86,240
Kerry J. Kuhlman 599 1/1/2002-12/31/2004 23,960 59,900 83,860
|
PENSION BENEFITS
The tables on the following pages show the estimated annual retirement benefits payable to an executive officer of Northeast Utilities upon retirement, assuming that retirement occurs at age 65 and that the officer is at that time not only eligible for a pension benefit under the Northeast Utilities Service Company Retirement Plan (the Retirement Plan) but also eligible for either the make-whole benefit or the make-whole benefit plus the target benefit under the Supplemental Executive Retirement Plan for Officers of Northeast Utilities System Companies (the Supplemental Plan). The Supplemental Plan is a non-qualified pension plan providing supplemental retirement income to system officers. The make-whole benefit under the Supplemental Plan, available to all officers, makes up for benefits lost through application of certain tax code limitations on the benefits that may be provided under the Retirement Plan, and includes as "compensation" awards under the executive incentive plans and deferred compensation (as earned). The target benefit further supplements these benefits and is available to officers at the Senior Vice President level and higher who are selected by the Board of Trustees to participate in the target benefit and who remain in the employ of Northeast Utilities companies until at least age 60 (unless the Board of Trustees sets an earlier age).
Mr. Morris's Employment Agreement provides that upon retirement (or upon disability or termination or following a change of control, as defined) he will be entitled to receive a special retirement benefit calculated by applying the benefit formula of the CMS Energy/Consumers Energy Company (CMS) Supplemental Executive Retirement Plan to all compensation earned from the Company and to all service rendered to the Company and CMS. If Mr. Morris retires after age 60, his special retirement benefit will be no less than that which he would have received had he been eligible for a make-whole benefit plus a target benefit under the Supplemental Plan.
Mr. Forsgren and Mrs. Grise are currently eligible for a make-whole plus a target benefit. Messrs. Butler, Olivier and Long and Mrs. Kuhlman are eligible for the make-whole benefit but not the target benefit.
Mr. Forsgren's Employment Agreement provides for supplemental pension benefits based on crediting up to ten years additional service and providing payments equal to 25 percent of final average compensation (not to exceed 170 percent of highest average base compensation received in any 36 month period) for up to 15 years following retirement, reduced by four percentage points for each year that his age is less than 65 years at retirement. In addition, if Mr. Forsgren retires after age 58, he will be eligible for a make-whole plus a target benefit under the Supplemental Plan based on crediting three extra years of service, unreduced for early commencement.
ANNUAL BENEFIT FOR OFFICERS ELIGIBLE FOR MAKE-WHOLE BENEFIT
Final Years of Credited Service
Average
Compensation
15 20 25 30 35
$200,000 $43,521 $58,028 $72,535 $87,042 $101,549
$250,000 $54,771 $73,028 $91,285 $109,542 $127,799
$300,000 $66,021 $88,028 $110,035 $132,042 $154,049
$350,000 $77,271 $103,028 $128,785 $154,542 $180,299
$400,000 $88,521 $118,028 $147,535 $177,042 $206,549
$450,000 $99,771 $133,028 $166,285 $199,542 $232,799
$500,000 $111,021 $148,028 $185,035 $222,042 $259,049
$600,000 $133,521 $178,028 $222,535 $267,042 $311,549
$700,000 $156,021 $208,028 $260,035 $312,042 $364,049
$800,000 $178,521 $238,028 $297,535 $357,042 $416,549
$900,000 $201,021 $268,028 $335,035 $402,042 $469,049
$1,000,000 $223,521 $298,028 $372,535 $447,042 $521,549
$1,100,000 $246,021 $328,028 $410,035 $492,042 $574,049
$1,200,000 $268,521 $358,028 $447,535 $537,042 $626,549
|
ANNUAL BENEFIT FOR OFFICERS ELIGIBLE FOR
MAKE-WHOLE PLUS TARGET BENEFIT
Final Years of Credited Service Average Compensation 15 20 25 30 35 $ 200,000 $ 72,000 $ 96,000 $120,000 $120,000 $120,000 250,000 90,000 120,000 150,000 150,000 150,000 300,000 108,000 144,000 180,000 180,000 180,000 350,000 126,000 168,000 210,000 210,000 210,000 400,000 144,000 192,000 240,000 240,000 240,000 450,000 162,000 216,000 270,000 270,000 270,000 500,000 180,000 240,000 300,000 300,000 300,000 600,000 216,000 288,000 360,000 360,000 360,000 700,000 252,000 336,000 420,000 420,000 420,000 800,000 288,000 384,000 480,000 480,000 480,000 900,000 324,000 432,000 540,000 540,000 540,000 1,000,000 360,000 480,000 600,000 600,000 600,000 1,100,000 396,000 528,000 660,000 660,000 660,000 1,200,000 432,000 576,000 720,000 720,000 720,000 |
The benefits presented in the tables above are based on a straight life annuity beginning at age 65 and do not take into account any reduction for joint and survivorship annuity payments. Final average compensation for purposes of calculating the target benefit is the highest average annual compensation of the participant during any 36 consecutive months compensation was earned. Final average compensation for purposes of calculating the make- whole benefit is the highest average annual compensation of the participant during any 60 consecutive months compensation was earned. Compensation for these benefits includes the annual salary and bonus shown in the Summary Compensation Table and, for officers hired before November 1, 2001, an amount that represents the annual value of long term incentive compensation. Compensation for purposes of these benefits does not include employer matching contributions under the 401k Plan. In the event that an officer's employment terminates because of disability, the retirement benefits shown above would be offset by the amount of any disability benefits payable to the recipient that are attributable to contributions made by Northeast Utilities and its subsidiaries under long term disability plans and policies.
Mr. Morris is not eligible to participate in the Supplemental Plan, but he does participate in the Retirement Plan. The amount of his annual compensation covered by the Retirement Plan was limited by the IRS to $200,000 for 2002. The compensation covered by the Supplemental Plan in 2002 for Mr. Forsgren, Mrs. Grise, Mr. Butler, Mr. Olivier, Mr. Long, and Mrs. Kuhlman was $933,084, $826,155, $307,699, $484,360, $270,840, and $258,191, respectively.
As of December 31, 2002, the executive officers named in the Summary
Compensation Table had approximately the following years of credited service
for purposes of the Supplemental Plan: Mr. Kenyon - 8, Mr. Forsgren - 6, Mrs.
Grise - 22, Mr. Butler - 6, -Mr. Olivier - 4, Mr. Long - 27, and Mrs. Kuhlman
- 22. Mr. Morris had 24 years of service for purpose of his special
retirement benefit. In addition, Mr. Forsgren had 12 years of service for
purposes of his supplemental pension benefit and would have 25 years of
service for such purpose if he were to retire at age 65.
COMPENSATION OF DIRECTORS
During 2002 each non-employee Director of PSNH and WMECO was compensated at an annual rate of $10,000 cash, and received $500 for each meeting attended of the Board of Directors or, in the case of PSNH, its committees. A non-employee Director who participates in a meeting of the Board of Directors or any of its committees by conference telephone receives $300 per meeting. Also, committee chairs were compensated at an additional annual rate of $1,500.
EMPLOYMENT CONTRACTS AND TERMINATION OF EMPLOYMENT ARRANGEMENTS
Northeast Utilities has entered into an employment agreement with Mr. Morris and NUSCO has entered into employment agreements with Mr. Forsgren and Mrs. Grise; each of the other named executive officers participates in the Special Severance Program for Officers of Northeast Utilities Companies. The agreements and the Special Severance Program are also binding on Northeast Utilities and on each majority-owned subsidiary of Northeast Utilities.
Each agreement obligates the officer to perform such duties as may be directed by the NUSCO Board of Directors or the Northeast Utilities Board of Trustees, protect the Company's confidential information, and refrain, while employed by the Company and for a period of time thereafter, from competing with the Company in a specified geographic area. Each agreement provides that the officer's base salary will not be reduced below certain levels without the consent of the officer, and that the officer will participate in specified benefits under the Supplemental Executive Retirement Plan or other supplemental retirement programs (see Pension Benefits, above) and/or in certain executive incentive programs at specified incentive opportunity levels.
Each agreement provides for a specified employment term and for automatic one-year extensions of the employment term unless at least six months' notice of non-renewal is given by either party. The employment term may also be ended by the Company for "cause", as defined, at any time (in which case no supplemental retirement benefit, if any, shall be due), or by the officer on thirty days' prior written notice for any reason. Absent "cause", the Company may remove the officer from his or her position on sixty days' prior written notice, but in the event the officer is so removed and signs a release of all claims against the Company, the officer will receive one or two years' base salary and annual incentive payments, specified employee welfare and pension benefits, and vesting of stock appreciation rights, options and restricted stock.
Under the terms of the agreements and the Special Severance Program, upon any termination of employment following a change of control, as defined, between (a) the earlier of the date shareholders approve a change of control transaction or a change of control transaction occurs and (b) the earlier of the date, if any, on which the Board of Trustees abandons the transaction or the date two years following the change of control, if the officer signs a release of all claims against the Company, the officer will be entitled to certain payments including a multiple (not to exceed three) of annual base salary, annual incentive payments, specified employee welfare and pension benefits, and vesting of stock appreciation rights, options and restricted stock. Certain of the change of control provisions may be modified by the Board of Trustees prior to a change of control, on at least two years' notice to the affected officer(s).
Besides the terms described above, the agreements of Messrs. Morris and Forsgren provide for a specified salary, cash, restricted stock and/or stock options upon employment, special incentive programs and/or special retirement benefits. See Pension Benefits, above, for further description of these provisions. The agreements of Mr. Forsgren and Mrs. Grise were supplemented during 2001 to provide for special deferred compensation of $520,000 and $500,000, respectively, vesting in even installments (adjusted to reflect investment performance) on June 28, 2002, 2003 and 2004, so long as such officer remains in the employ of Northeast Utilities Service Company, and vesting sooner in the event of a change of control of the Company or involuntary termination without cause.
Letter agreements reflecting the terms of employment of Messrs. Butler, Boguslawski, and Olivier provide for specified salary, cash, restricted stock, stock options or other benefits upon employment.
The descriptions of the various agreements set forth above are for purpose of disclosure in accordance with the proxy and other disclosure rules of the SEC and shall not be controlling on any party; the actual terms of the agreements themselves determine the rights and obligations of the parties.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
NU.
Incorporated herein by reference is the information contained in the sections "Common Stock Ownership of Certain Beneficial Owners", "Common Stock Ownership of Management", and "Securities Authorized for Issuance Under Equity Compensation Plans" of the definitive proxy statement for solicitation of proxies by NU's Board of Trustees, dated March 27, 2003, which will be filed with the Commission pursuant to Rule 14a-6 under the Securities Exchange Act of 1934.
CL&P, PSNH, and WMECO.
NU owns 100% of the outstanding common stock of registrants CL&P, PSNH, and WMECO. As of March 14, 2003, the Directors and Executive Officers of CL&P, PSNH, and WMECO beneficially owned the number of shares of each class of equity securities of NU listed below. No equity securities of CL&P, PSNH, or WMECO are owned by the Directors and Executive Officers of CL&P, PSNH, and WMECO. Unless otherwise noted, each Director and Executive Officer of CL&P, PSNH, and WMECO has sole voting and investment power with respect to the listed shares.
Title of Amount and Nature of Percent of Class Name Beneficial Ownership Class NU Common David H. Boguslawski (1) 34,373 (2) NU Common Gregory B. Butler (3) 49,018 (2) NU Common John H. Forsgren (4) 187,567 (2) NU Common Cheryl W. Grise (5) 128,135 (2) NU Common Kerry J. Kuhlman (6) 32,555 (2) NU Common Gary A. Long (7) 30,871 (2) NU Common Michael G. Morris (8) 1,067,100 (2) NU Common Leon J. Olivier (9) 16,683 (2) |
Amount beneficially owned by Directors and Executive Officers as a group:
Amount and Nature of Percent of
Company Number of Persons Beneficial Ownership Outstanding
CL&P 6 1,482,876 (2)
PSNH 6 1,497,064 (2)
WMECO 6 1,498,748 (2)
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(1) Includes 23,704 shares that could be acquired by Mr. Boguslawski pursuant to currently exercisable options and 5,304 restricted shares, as to which Mr. Boguslawski has sole voting and no dispositive power.
(2) As of March 14, 2003, there were 130,383,840 common shares of NU outstanding. The percentage of such shares beneficially owned by any Director or Executive Officer of CL&P, PSNH, or WMECO and by all of the Directors and Executive Officers of each of CL&P, PSNH and WMECO does not exceed one percent.
(3) Includes 34,182 shares that could be acquired by Mr. Butler pursuant to currently exercisable options and 7,779 restricted shares as to which Mr. Butler has sole voting and no dispositive power.
(4) Includes 143,718 shares that could be acquired by Mr. Forsgren pursuant to currently exercisable options and 39,631 restricted shares as to which Mr. Forsgren has sole voting and no dispositive power.
(5) Includes 73,292 shares that could be acquired by Mrs. Grise pursuant to currently exercisable options, 36,072 restricted as to which Mrs. Grise has sole voting and no dispositive power, and 265 shares held by Mrs. Grise's husband as custodian for her children, with whom she shares voting and dispositive power.
(6) Includes 21,529 shares that could be acquired by Ms. Kuhlman pursuant to currently exercisable options and 4,420 restricted shares, as to which Ms. Kuhlman has sole voting and no dispositive power.
(7) Includes 20,399 shares that could be acquired by Mr. Long pursuant to currently exercisable options and 4,597 restricted shares, as to which Mr. Long has sole voting and no dispositive power.
(8) Includes 979,792 shares that could be acquired by Mr. Morris pursuant to currently exercisable options and 31,732 restricted shares as to which Mr. Morris has sole voting and no dispositive power.
(9) Includes 6,634 shares that could be acquired by Mr. Olivier pursuant to currently exercisable options and 5,552 restricted shares, as to which Mr. Olivier has sole voting and no dispositive power.
SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS
The following table sets forth the number of Common Shares of Northeast Utilities issuable under the equity compensation plans of the Northeast Utilities System, as well as their weighted exercise price, in accordance with the rules of the SEC:
-------------------------------------------------------------------------------------------------
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
compensation
plans approved by
security holders 3,956,137 $16.73 See Note 1
-------------------------------------------------------------------------------------------------
Equity
compensation
plans not
approved by
security holders 500,000 $9.625 None
-------------------------------------------------------------------------------------------------
Total 4,456,137 $15.93 See Note 1
-------------------------------------------------------------------------------------------------
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Notes to table:
1. Under the Incentive Plan, 3,873,851 shares were available for issuance as of December 31, 2002. In addition, an amount equal to one percent of the outstanding shares as of the end of each year becomes available for issuance under the Incentive Plan the following year. Under the Northeast Utilities Employee Share Purchase Plan II, 7,438,295 additional shares are available for issuance. Each such plan expires in 2008.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Incorporated herein by reference is the information contained in the section "Certain Relationships and Related Transactions" of the definitive proxy statement for solicitation of proxies by NU's Board of Trustees, dated March 27, 2003, which will be filed with the Commission pursuant to Rule 14a- 6 under the Securities Exchange Act of 1934.
ITEM 14. CONTROLS AND PROCEDURES
NU, CL&P, PSNH and WMECO (collectively, the companies) evaluated the design and operation of their disclosure controls and procedures to determine whether they are effective in ensuring that the disclosure of required information is timely made in accordance with the Exchange Act and the rules and forms of the SEC. These evaluations were made under the supervision and with the participation of management, including the companies' principal executive officer and principal financial officer, within the 90-day period prior to the filing of this Annual Report on Form 10-K. The principal executive officer and principal financial officer have concluded, based on their review, that the companies' disclosure controls and procedures, as defined at Exchange Act Rules 13a-14(c) and 15(d)-14(c), are effective to ensure that information required to be disclosed by the companies in reports that it files under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms. No significant changes were made to the companies' internal controls or other factors that could significantly affect these controls subsequent to the date of their evaluation.
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) 1. Financial Statements:
The Report of Independent Public Accountants and financial statements of CL&P, PSNH and WMECO are hereby incorporated by reference and made a part of this report (see "Item 8. Financial Statements and Supplementary Data").
Independent Auditors' Report S-1
Independent Auditors' Consent S-2
2. Schedules:
Financial Statement Schedules for NU (Parent),
NU and Subsidiaries, CL&P and Subsidiaries,
PSNH and Subsidiaries, and WMECO and Subsidiary
are listed in the Index to Financial
Statements Schedules S-3
3. Exhibits Index E-1
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(b) Reports on Form 8-K:
NU filed a current report on Form 8-K dated January 22, 2002, disclosing:
o NU's earnings press release for the fourth quarter and full year 2001.
NU and PSNH filed current reports on Form 8-K dated January 30, 2002, disclosing:
o The closing on the sale of $50 million of RRBs through PSNH's subsidiary, PSNH Funding LLC 2.
NU, CL&P, PSNH, and WMECO filed current reports on Form 8-K dated March 15, 2002, disclosing:
o NU's change in its certifying accountant.
NU filed a current report on Form 8-K/A dated March 15, 2002, disclosing:
o An amendment to NU's current report on Form 8-K dated March 15, 2002, disclosing NU's change in its certifying accountant.
NU and CL&P filed current reports on Form 8-K dated June 17, 2002, disclosing:
o NU's lowering of its earnings estimates for 2002 and CL&P's criticism of the DPUC's decision on standard offer generation rates.
NU filed a current report on Form 8-K dated August 2, 2002, disclosing:
o NU's submission to the SEC of Statements under Oath of the Principal Executive Officer and Principal Financial Officer in accordance with the SEC's June 27, 2002 Order requiring the filing of sworn statements pursuant to Section 21(a)(1) of the Securities and Exchange Act of 1934.
NU filed a current report on Form 8-K dated August 14, 2002, disclosing:
o NU's submission to the SEC of certain Statements under Oath of the Principal Executive Officer and Principal Financial Officer in accordance with the SEC's June 27, 2002 Order requiring the filing of sworn statements pursuant to Section 21(a)(1) of the Securities and Exchange Act of 1934.
NU, CL&P, PSNH and WMECO filed current reports on Form 8-K dated November 26, 2002, disclosing:
o An increase in the estimated decommissioning costs associated with various nuclear units.
NU, CL&P, PSNH and WMECO filed current reports on Form 8-K/A dated November 26, 2002, providing:
o An amendment to their respective current reports on Form 8-K dated November 26, 2002, disclosing an increase in the estimated decommissioning costs associated with various nuclear units.
NU filed a current report on Form 8-K dated January 28, 2003, disclosing:
o NU's earnings press release for the fourth quarter and full year 2002.
NORTHEAST UTILITIES
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Date: March 21, 2003 By /s/ Michael G. Morris
-------------- ---------------------
Michael G. Morris
Chairman of the Board,
President and
Chief Executive Officer
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Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
Date Title Signature
---- ----- ---------
March 21, 2003 Chairman of the Board, /s/ Michael G. Morris
-------------- President and -----------------------------
Chief Executive Officer Michael G. Morris
and a Trustee
March 21, 2003 Vice Chairman, /s/ John H. Forsgren
-------------- Executive Vice ----------------------------
President and Chief John H. Forsgren
Financial Officer
and a Trustee
March 21, 2003 Vice President - /s/ John P. Stack
-------------- Accounting and ----------------------------
Controller John P. Stack
March 21, 2003 Trustee /s/ Richard H. Booth
-------------- ----------------------------
Richard H. Booth
March 21, 2003 Trustee /s/ Cotton M. Cleveland
-------------- ----------------------------
Cotton M. Cleveland
March 21, 2003 Trustee /s/ Sanford Cloud, Jr.
-------------- ----------------------------
Sanford Cloud, Jr.
March 21, 2003 Trustee /s/ James F. Cordes
-------------- ----------------------------
James F. Cordes
March 21, 2003 Trustee /s/ E. Gail de Planque
-------------- ----------------------------
E. Gail de Planque
March 21, 2003 Trustee /s/ Elizabeth T. Kennan
-------------- ----------------------------
Elizabeth T. Kennan
March 21, 2003 Trustee /s/ Robert E. Patricelli
-------------- ----------------------------
Robert E. Patricelli
March 21, 2003 Trustee /s/ John F. Swope
-------------- ----------------------------
John F. Swope
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CERTIFICATION PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, Michael G. Morris, Chairman, President and Chief Executive Officer of Northeast Utilities (the Company), certify that:
1. I have reviewed this annual report on Form 10-K of the Company;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the Evaluation Date); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: March 21, 2003
/s/ Michael G. Morris
(Signature)
Michael G. Morris
Chairman, President and Chief Executive Officer
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CERTIFICATION PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, John H. Forsgren, Vice Chairman, Executive Vice President and Chief Financial Officer of Northeast Utilities (the Company), certify that:
1. I have reviewed this annual report on Form 10-K of the Company;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the Evaluation Date); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: March 21, 2003
/s/ John H. Forsgren
(Signature)
John H. Forsgren
Vice Chairman, Executive
Vice President and Chief
Financial Officer
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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 21, 2003 By /s/ Cheryl W. Grise
-------------- ---------------------------
Cheryl W. Grise
Chief Executive Officer
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Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
Date Title Signature
---- ----- ---------
March 21, 2003 President and /s/ Leon J. Olivier
-------------- Chief Operating ----------------------------
Officer and Leon J. Olivier
a Director
March 21, 2003 Chief Executive /s/ Cheryl W. Grise
-------------- Officer and ----------------------------
a Director Cheryl W. Grise
March 21, 2003 Executive Vice /s/ John H. Forsgren
-------------- President and ----------------------------
Chief Financial John H. Forsgren
Officer
March 21, 2003 Vice President - /s/ John P. Stack
-------------- Accounting and ----------------------------
Controller John P. Stack
March 21, 2003 Director /s/ David H. Boguslawski
-------------- ----------------------------
David H. Boguslawski
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CERTIFICATION PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, Cheryl W. Grise, Chief Executive Officer of The Connecticut Light and Power Company (the Company), certify that:
1. I have reviewed this annual report on Form 10-K of the Company;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the Evaluation Date); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: March 21, 2003
/s/ Cheryl W. Grise
(Signature)
Cheryl W. Grise
Chief Executive Officer
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CERTIFICATION PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, John H. Forsgren, Executive Vice President and Chief Financial Officer of The Connecticut Light and Power Company (the Company), certify that:
1. I have reviewed this annual report on Form 10-K of the Company;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the Evaluation Date); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: March 21, 2003
/s/ John H. Forsgren
(Signature)
John H. Forsgren
Executive Vice President and
Chief Financial Officer
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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 21, 2003 By /s/ Cheryl W. Grise
-------------- ---------------------------
Cheryl W. Grise
Chief Executive Officer
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Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
Date Title Signature
---- ----- ---------
March 21, 2003 Chairman /s/ Michael G. Morris
-------------- and a Director ----------------------------
Michael G. Morris
March 21, 2003 Chief Executive /s/ Cheryl W. Grise
-------------- Officer and ----------------------------
a Director Cheryl W. Grise
March 21, 2003 President and /s/ Gary A. Long
-------------- Chief Operating ----------------------------
Officer and Gary A. Long
a Director
March 21, 2003 Executive Vice /s/ John H. Forsgren
-------------- President and ----------------------------
Chief Financial John H. Forsgren
Officer and
a Director
March 21, 2003 Vice President - /s/ John P. Stack
-------------- Accounting and ----------------------------
Controller John P. Stack
March 21, 2003 Director /s/ David H. Boguslawski
-------------- ----------------------------
David H. Boguslawski
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CERTIFICATION PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, Cheryl W. Grise, Chief Executive Officer of Public Service Company of New Hampshire (the Company), certify that:
1. I have reviewed this annual report on Form 10-K of the Company;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the Evaluation Date); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: March 21, 2003
/s/ Cheryl W. Grise
(Signature)
Cheryl W. Grise
Chief Executive Officer
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CERTIFICATION PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, John H. Forsgren, Executive Vice President and Chief Financial Officer of Public Service Company of New Hampshire (the Company), certify that:
1. I have reviewed this annual report on Form 10-K of the Company;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the Evaluation Date); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: March 21, 2003
/s/ John H. Forsgren
(Signature)
John H. Forsgren
Executive Vice President and
Chief Financial Officer
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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 21, 2003 By /s/ Cheryl W. Grise
-------------- -----------------------------
Cheryl W. Grise
Chief Executive Officer
|
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
Date Title Signature
---- ----- ---------
March 21, 2003 Chairman /s/ Michael G. Morris
-------------- and a Director ----------------------------
Michael G. Morris
March 21, 2003 Chief Executive /s/ Cheryl W. Grise
-------------- Officer and ----------------------------
a Director Cheryl W. Grise
March 21, 2003 President and /s/ Kerry J. Kuhlman
-------------- Chief Operating ----------------------------
Officer and Kerry J. Kuhlman
a Director
March 21, 2003 Executive Vice /s/ John H. Forsgren
-------------- President and ----------------------------
Chief Financial John H. Forsgren
Officer and
a Director
March 21, 2003 Vice President - /s/ John P. Stack
-------------- Accounting and ----------------------------
Controller John P. Stack
March 21, 2003 Director /s/ David H. Boguslawski
-------------- ----------------------------
David H. Boguslawski
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CERTIFICATION PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, Cheryl W. Grise, Chief Executive Officer of Western Massachusetts Electric Company (the Company), certify that:
1. I have reviewed this annual report on Form 10-K of the Company;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the Evaluation Date); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: March 21, 2003
/s/ Cheryl W. Grise
(Signature)
Cheryl W. Grise
Chief Executive Officer
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CERTIFICATION PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
I, John H. Forsgren, Executive Vice President and Chief Financial Officer of Western Massachusetts Electric Company (the Company), certify that:
1. I have reviewed this annual report on Form 10-K of the Company;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the Evaluation Date); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: March 21, 2003
/s/ John H. Forsgren
(Signature)
John H. Forsgren
Executive Vice President and
Chief Financial Officer
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INDEPENDENT AUDITORS' REPORT
To the Board of Trustees and Shareholders of Northeast Utilities and the Boards of Directors of The Connecticut Light and Power Company, Public Service Company of New Hampshire and Western Massachusetts Electric Company:
We have audited the consolidated financial statements of Northeast Utilities and subsidiaries (the "Company") and The Connecticut Light and Power Company ("CL&P") as of December 31, 2002 and 2001 and for the years then ended, and the consolidated financial statements of Public Service Company of New Hampshire ("PSNH") and Western Massachusetts Electric Company ("WMECO") as of and for the year ended December 31, 2002 (collectively "the Companies"), and have issued our reports thereon dated January 28, 2003 (February 27, 2003 as to Note 8A) for the Company, January 28, 2003 (February 27, 2003 as to Note 6A) for CL&P, and January 28, 2003 for PSNH and WMECO; such financial statements and reports are included in Northeast Utilities' 2002 Annual Report to Shareholders and in CL&P 's, PSNH's and WMECO's 2002 annual reports, all of which are incorporated herein by reference. Our report on the consolidated financial statements of Northeast Utilities expresses an unqualified opinion and includes an explanatory paragraph with respect to the Company's adoption of Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended, effective January 1, 2001, and its adoption in 2002 of Emerging Issues Task Force Issue 02-3, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities," and SFAS No. 142, "Goodwill and Other Intangible Assets." Our report also includes an additional paragraph regarding the audit procedures we applied to certain adjustments made to the Company's 2000 consolidated financial statements for the transitional disclosures required by SFAS No. 142. We do not express an opinion or any form of assurance on the 2000 financial statements taken as a whole.
Our audits also included the 2002 and 2001 financial statement schedules of Northeast Utilities and CL&P and the 2002 financial statement schedules of PSNH and WMECO, listed in Item 15. The 2000 consolidated financial statements and financial statement schedules of Northeast Utilities and CL&P and the 2001 and 2000 financial statements and financial statement schedules of PSNH and WMECO were audited by other auditors who have ceased operations. Those auditors expressed an unqualified opinion on those financial statements and financial statement schedules in their reports dated January 22, 2002. These financial statement schedules are the responsibility of the Companies' management. Our responsibility is to express an opinion based on our audits. In our opinion, such financial statement schedules audited by us, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects the information set forth therein.
/s/ Deloitte & Touche LLP
Deloitte & Touche LLP
Hartford, Connecticut
January 28, 2003
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INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration Statement Nos. 33-34622, 333-55142 and 33-40156 on Forms S-3 and Nos. 33-44814, 33-63023, 333-52413 and 333-52415 on Forms S-8 of Northeast Utilities (the Company) of our reports dated January 28, 2003 (February 27, 2003 as to Note 8A), appearing in and incorporated by reference in this Annual Report on Form 10-K of Northeast Utilities for the year ended December 31, 2002 (which express an unqualified opinion and include explanatory paragraphs with respect to the Company's adoption of Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended, effective January 1, 2001, and its adoption in 2002 of Emerging Issues Task Force Issue 02-3, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities" and SFAS No. 142, "Goodwill and Other Intangible Assets"). Our reports also include an additional paragraph regarding the audit procedures we applied to certain adjustments made to the Company's 2000 consolidated financial statements for the transitional disclosures required by SFAS No. 142. We do not express an opinion or any form of assurance on the 2000 consolidated financial statements taken as a whole.
/s/ Deloitte & Touche LLP
Deloitte & Touche LLP
Hartford, Connecticut
March 21, 2003
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INDEX TO FINANCIAL STATEMENTS SCHEDULES
Schedule
I. Financial Information of Registrant:
Northeast Utilities (Parent) Balance
Sheets at December 31, 2002 and 2001 S-4
Northeast Utilities (Parent) Statements
of Income for the Years Ended December 31,
2002, 2001, and 2000 S-5
Northeast Utilities (Parent) Statements
of Cash Flows for the Years Ended December 31,
2002, 2001, and 2000 S-6
II. Valuation and Qualifying Accounts and Reserves
for 2002, 2001, and 2000:
Northeast Utilities and Subsidiaries S-7 - S-9
The Connecticut Light and Power Company
and Subsidiaries S-10 - S-12
Public Service Company of New Hampshire
and Subsidiaries S-13 - S-15
Western Massachusetts Electric Company
and Subsidiary S-16 - S-18
|
All other schedules of the companies' for which provision is made in the applicable regulations of the SEC are not required under the related instructions or are not applicable, and therefore have been omitted.
SCHEDULE I
NORTHEAST UTILITIES (PARENT)
FINANCIAL INFORMATION OF REGISTRANT
BALANCE SHEETS
AT DECEMBER 31, 2002 AND 2001
(Thousands of Dollars)
2002 2001
---------- ----------
ASSETS
------
Current Assets:
Cash..................................................... $ 625 $ 13,183
Notes receivable from affiliated companies............... 289,100 124,800
Notes and accounts receivable............................ 551 555
Receivables from affiliated companies.................... 2,620 21,713
Prepayments.............................................. 73 1,093
---------- ----------
292,969 161,344
---------- ----------
Deferred Debits and Other Assets:
Investments in subsidiary companies, at equity........... 2,322,902 2,392,884
Other.................................................... 18,159 17,856
---------- ----------
2,341,061 2,410,740
---------- ----------
Total Assets............................................... $2,634,030 $2,572,084
========== ==========
LIABILITIES AND CAPITALIZATION
------------------------------
Current Liabilities:
Notes payable to banks................................... $ 49,000 $ 40,000
Long-term debt - current portion......................... 23,000 23,000
Accounts payable......................................... 2,285 146
Accounts payable to affiliated companies................. 290 26,626
Accrued taxes............................................ 2,460 249
Accrued interest......................................... 5,883 2,492
Other.................................................... 363 19
---------- ----------
83,281 92,532
---------- ----------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes........................ 6,087 4,742
Other.................................................... 141 170
---------- ----------
6,228 4,912
---------- ----------
Capitalization:
Long-Term Debt........................................... 334,000 357,000
---------- ----------
Common Shareholders' Equity:
Common shares, $5 par value - authorized
225,000,000 shares; 149,375,847 shares issued and
127,562,031 shares outstanding in 2002 and
148,890,640 shares issued and
130,132,136 outstanding in 2001........................ 746,879 744,453
Capital surplus, paid in................................. 1,108,338 1,107,609
Deferred contribution plan - employee stock
stock ownership plan................................... (87,746) (101,809)
Retained earnings........................................ 765,611 678,460
Accumulated other comprehensive income/(loss)............ 14,927 (32,470)
Treasury stock........................................... (337,488) (278,603)
---------- ----------
Common Shareholders' Equity.............................. 2,210,521 2,117,640
---------- ----------
Total Capitalization....................................... 2,544,521 2,474,640
---------- ----------
Total Liabilities and Capitalization....................... $2,634,030 $2,572,084
========== ==========
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SCHEDULE I
NORTHEAST UTILITIES (PARENT)
FINANCIAL INFORMATION OF REGISTRANT
STATEMENTS OF INCOME
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
(Thousands of Dollars, Except Share Information)
2002 2001 2000
----------- ------------ ------------
Operating Revenues............................................... $ - $ - $ -
------------ ------------ ------------
Operating Expenses:
Other.......................................................... 12,787 11,917 15,335
------------ ------------ ------------
Operating Loss................................................... (12,787) (11,917) (15,335)
------------ ------------ ------------
Interest Expense................................................. 30,630 32,696 47,819
------------ ------------ ------------
Other Income/(Loss):
Equity in earnings of subsidiaries............................. 158,191 188,783 23,553
Gain related to sale of nuclear plants......................... 14,255 147,935 -
Loss on share repurchase contracts............................. - (35,394) -
Other, net..................................................... 13,002 10,863 11,687
------------ ------------ ------------
Other Income, Net................................................ 185,448 312,187 35,240
------------ ------------ ------------
Income/(Loss) Before Income Tax (Benefit)/Expense................ 142,031 267,574 (27,914)
Income Tax (Benefit)/Expense..................................... (10,078) 24,064 672
------------ ------------ ------------
Earnings/(Loss) for Common Shares................................ $ 152,109 $ 243,510 $ (28,586)
============ =========== ============
Basic Earnings/(Loss)
Per Common Share............................................... $ 1.18 $ 1.80 $ (0.20)
=========== ============ ============
Fully Diluted Earnings/(Loss)
Per Common Share............................................... $ 1.18 $ 1.79 $ (0.20)
=========== ============ ============
Basic Common Shares
Outstanding (average)........................................... 129,150,549 135,632,126 141,549,860
=========== =========== ===========
Fully Diluted Common Shares
Outstanding (average)........................................... 129,341,360 135,917,423 141,967,216
=========== =========== ===========
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SCHEDULE I
NORTHEAST UTILITIES (PARENT)
FINANCIAL INFORMATION OF REGISTRANT
STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
(Thousands of Dollars)
2002 2001 2000
------------ ------------ ------------
Operating Activities:
Net earnings/(loss) for common shares.......................... $ 152,109 $ 243,510 $ (28,586)
Adjustments to reconcile to net cash flows
provided by operating activities:
Equity in earnings of subsidiary companies................... (158,191) (188,783) (23,553)
Cash dividends received from subsidiary companies............ 126,154 120,072 183,016
Deferred income taxes........................................ (565) (233) (276)
Net other sources of cash.................................... 11,493 36,522 3,031
Changes in working capital:
Receivables, net............................................. 19,097 (24,295) 4,200
Accounts payable............................................. (24,197) 25,788 (7,475)
Accrued taxes................................................ 2,211 (886) 1,135
Other working capital (excludes cash)........................ 52,152 (36,058) (2,756)
----------- ----------- -----------
Net cash flows provided by operating activities.................. 180,263 175,637 128,736
----------- ----------- -----------
Investing Activities:
Investment in NU system Money Pool............................. (164,300) (30,400) (49,100)
Investment in subsidiaries..................................... 102,019 396,257 (117,631)
Payment for acquisitions, net of cash acquired................. - (25,823) (260,347)
Other investment activities, net............................... 1,595 1,415 1,489
----------- ----------- -----------
Net cash flows (used in)/provided by investing activities........ (60,686) 341,449 (425,589)
----------- ----------- -----------
Financing Activities:
Issuance of common shares...................................... 7,458 1,751 4,269
Issuance of long-term debt..................................... 263,000 263,000 -
Repurchase of common shares.................................... (57,800) (291,789) -
Net increase/(decrease) in short-term debt..................... 9,000 (396,000) 371,000
Reacquisitions and retirements of long-term debt............... (286,000) (21,000) (20,000)
Cash dividends on common shares................................ (67,793) (60,923) (57,358)
----------- ----------- -----------
Net cash flows (used in)/provided by financing activities........ (132,135) (504,961) 297,911
----------- ----------- -----------
Net (decrease)/increase in cash.................................. (12,558) 12,125 1,058
Cash - beginning of year......................................... 13,183 1,058 -
----------- ----------- -----------
Cash - end of year............................................... $ 625 $ 13,183 $ 1,058
=========== =========== ===========
Supplemental Cash Flow Information:
Cash paid/(refunded) during the year for:
Interest, net of amounts capitalized........................... $ 25,213 $ 35,453 $ 39,099
=========== =========== ===========
Income taxes................................................... $ (10,677) $ 32,126 $ 1,430
=========== =========== ===========
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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.
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NORTHEAST UTILITIES AND SUBSIDIARIES SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 2000
(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 $ 4,895 $26,740 $ 130 (c) $19,265 (a) $12,500
======= ======= ======= ======= =======
RESERVES NOT APPLIED AGAINST ASSETS:
Operating reserves $44,995 $22,573 $37,680 (c) $25,967 (b) $79,281
======= ======= ======= ======= =======
(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.
(c) Amounts represent activity related to the acquisition of Yankee on March 1, 2000.
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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.
|
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 2000
(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 $ 9,270 $ - $ 9,270 (a) $ 300
======= ======= ======= ======= =======
RESERVES NOT APPLIED AGAINST ASSETS:
Operating reserves $16,069 $ 7,488 $ - $ 9,897 (b) $13,660
======= ======= ======= ======= =======
(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, 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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PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 2000
(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 $ 1,359 $ 2,220 $ - $ 1,710 (a) $ 1,869
======= ======= ======= ======= =======
RESERVES NOT APPLIED AGAINST ASSETS:
Operating reserves $11,405 $ 9,855 $ - $ 9,610 (b) $11,650
======= ======= ======= ======= =======
(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, 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 (c)
======= ======= ======= ======= =======
(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.
(c) Reduction in 2002 operating reserves primarily relates to a reduction in
operating reserves related to environmental remediation during 2002.
|
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.
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WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEAR ENDED DECEMBER 31, 2000
(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 $ 1,640 $ 2,416 $ - $ 2,170 (a) $ 1,886
======= ======= ======= ======= =======
RESERVES NOT APPLIED AGAINST ASSETS:
Operating reserves $ 7,188 $ 1,130 $ - $ 1,558 (b) $ 6,760
======= ======= ======= ======= =======
(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 of the SEC, unless the reference to the document is marked as follows:
* - Filed with the 2002 Annual Report on Form 10-K for NU and herein incorporated by reference from the 2002 NU Form 10-K, File No. 1-5324 into the 2002 Annual Reports on Form 10-K for CL&P, PSNH and WMECO.
# - Filed with the 2002 Annual Report on Form 10-K for NU and herein incorporated by reference from the 2002 NU Form 10-K, File No. 1-5324 into the 2002 Annual Report on Form 10-K for CL&P.
@ - Filed with the 2002 Annual Report on Form 10-K for NU and herein incorporated by reference from the 2002 NU Form 10-K, File No. 1-5324 into the 2002 Annual Report on Form 10-K for PSNH.
** - Filed with the 2002 Annual Report on Form 10-K for NU and herein incorporated by reference from the 2002 NU Form 10-K, File No. 1-5324 into the 2002 Annual Report on Form 10-K for WMECO.
Exhibit
Number Description
2 Plan of acquisition, reorganization, arrangement, liquidation or succession
2.1 Amended and Restated Agreement and Plan of Merger (Exhibit 1 to NU's Current Report on Form 8-K dated December 2, 1999, File No. 1- 5324).
2.2 Purchase and Sale Agreement for the Seabrook Nuclear Power Station dated April 13, 2002 (Exhibit 10.63 to NU Form 10-Q for the quarter ended March 31, 2002, File No. 1-5324)
3 Articles of Incorporation and By-Laws
3.1 Northeast Utilities
3.1.1 Declaration of Trust of NU, as amended through
May 24, 1988. (Exhibit 3.1.1, 1988 NU Form 10-K, File No.
1-5324)
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3.2 The Connecticut Light and Power Company
3.2.1 Certificate of Incorporation of CL&P, restated to
March 22, 1994. (Exhibit 3.2.1, 1993 NU Form 10-K, File
No. 1-5324)
3.2.2 Certificate of Amendment to Certificate of
Incorporation of CL&P, dated December 26, 1996. (Exhibit
3.2.2, 1996 NU Form 10-K, File No. 1-5324)
3.2.3 Certificate of Amendment to Certificate of
Incorporation of CL&P, dated April 27, 1998. (Exhibit
3.2.3, 1998 NU Form 10-K, File No. 1-5324)
3.2.4 By-laws of CL&P, as amended to January 1, 1997.
(Exhibit 3.2.3, 1996 NU Form 10-K, File No. 1-5324)
|
3.3 Public Service Company of New Hampshire
3.3.1 Articles of Incorporation, as amended to May 16, 1991.
(Exhibit 3.3.1, 1993 NU Form 10-K, File No. 1-5324)
3.3.2 By-laws of PSNH, as amended to November 1, 1993.
(Exhibit 3.3.2, 1993 NU Form 10-K, File No. 1-5324)
|
3.4 Western Massachusetts Electric Company
3.4.1 Articles of Organization of WMECO, restated to
February 23, 1995. (Exhibit 3.4.1, 1994 NU Form 10-K,
File No. 1-5324)
3.4.2 By-laws of WMECO, as amended to April 1, 1999. (Exhibit
3.1, 1999 NU Form 10-Q for the Quarter Ended June 30,
1999, File No. 1-5324)
3.4.3 By-laws of WMECO, as further amended to May 1,
2000. (Exhibit 3.1, 2000 NU Form 10-Q for the Quarter
Ended June 30, 2000, File No. 1-5324)
|
4 Instruments defining the rights of security holders, including indentures
4.1 Northeast Utilities
4.1.1 Indenture dated as of December 1, 1991 between Northeast
Utilities and IBJ Schroder Bank & Trust Company, with
respect to the issuance of Debt Securities. (Exhibit
4.1.1, 1991 NU Form 10-K, File No. 1-5324)
4.1.1.1 First Supplemental Indenture dated as of December 1,
1991 between Northeast Utilities and IBJ Schroder
Bank & Trust Company, with respect to the issuance
of Series A Notes. (Exhibit 4.1.2, 1991 NU Form
10-K, File No. 1-5324)
4.1.1.2 Second Supplemental Indenture dated as of March 1,
1992 between Northeast Utilities and IBJ Schroder
Bank & Trust Company with respect to the issuance of
8.38% Amortizing Notes. (Exhibit 4.1.3, 1992 NU
Form 10-K, File No. 1-5324)
4.1.2 Rights Agreement dated as of February 23, 1999, between
Northeast Utilities and Northeast Utilities Service
Company, as Rights Agent. (Exhibit 1 to NU's
Registration Statement on Form 8-A, filed on April 12,
1999, File No. 001-05324).
4.1.2.1 Amendment to Rights Agreement. (Exhibit 3 to NU's
Current Report on Form 8-K dated October 13, 1999,
File No. 1-5324).
4.1.2.2 Second Amendment to Rights Agreement. (Exhibit 3 to
NU Form 8-A-12B-A dated February 1, 2002, File No.
001-05324 and Exhibit B-3 to NU Rule 35-CERT, dated
February 1, 2002, File No. 070-09463).
4.1.3 Indenture dated as of April 1, 2002, between NU and the
Bank of New York as Trustee. (Exhibit A-3 to NU 35-CERT
filed April 9, 2002, File No. 70-9535)
4.1.3.1 First Supplemental Indenture dated as of April 1,
2002, between NU and the Bank of New York as
Trustee, relating to $263M of Senior Notes,
Series A, due 2012. (Exhibit A-4 to NU 35-CERT
filed April 9 2002, File No. 70-9535)
4.1.4 Revolving Credit Agreement among NU and the Banks named
therein, dated November 12, 2002. (Exhibit B-3 to NU 35-
CERT filed November 21, 2002, File No. 70-9755)
|
4.2 The Connecticut Light and Power Company
4.2.1 Indenture of Mortgage and Deed of Trust between CL&P and
Bankers Trust Company, Trustee, dated as of May 1, 1921.
(Composite including all twenty-four amendments to May 1,
1967.) (Exhibit 4.1.1, 1989 NU Form 10-K, File No. 1-
5324)
Supplemental Indentures to the Composite May 1, 1921
Indenture of Mortgage and Deed of Trust between CL&P and
Bankers Trust Company, dated as of:
4.2.1.1 June 1, 1994. (Exhibit 4.2.15,
1994 NU Form 10-K, File No. 1-5324)
4.2.1.2 October 1, 1994. (Exhibit 4.2.16, 1994 NU Form
10-K, File No. 1-5324)
4.2.2 Financing Agreement between Industrial Development
Authority of the State of New Hampshire and CL&P
(Pollution Control Bonds, 1986 Series) dated as of
December 1, 1986. (Exhibit C.1.47, 1986 NU Form U5S,
File No. 30-246)
4.2.3 Financing Agreement between Industrial Development
Authority of the State of New Hampshire and
CL&P (Pollution Control Bonds, 1988 Series) dated as of
October 1, 1988. (Exhibit C.1.55, 1988 NU Form U5S, File
No. 30-246)
4.2.4 Loan and Trust Agreement among Business Finance Authority
of the State of New Hampshire, CL&P and the Trustee
(Pollution Control Bonds, 1992 Series A) dated as of
December 1, 1992. (Exhibit C.2.33, 1992 NU Form U5S,
File No. 30-246)
4.2.5 Loan Agreement between Connecticut Development Authority
and CL&P (Pollution Control Bonds - Series A, Tax Exempt
Refunding) dated as of September 1, 1993. (Exhibit
4.2.21, 1993 NU Form 10-K, File No. 1-5324)
4.2.6 Loan Agreement between Connecticut Development Authority
and CL&P (Pollution Control Bonds - Series B, Tax Exempt
Refunding) dated as of September 1, 1993. (Exhibit
4.2.22, 1993 NU Form 10-K, File No. 1-5324)
4.2.7 Amended and Restated Loan Agreement between Connecticut
Development Authority and CL&P (Pollution Control Revenue
Bond - 1996A Series) dated as of May 1, 1996 and Amended
and Restated as of January 1, 1997. (Exhibit 4.2.24,
1996 NU Form 10-K, File No. 1-5324)
4.2.7.1 Amended and Restated Indenture of Trust
between Connecticut Development Authority
and the Trustee (CL&P Pollution Control Revenue
Bond-1996A Series), dated as of May 1, 1996 and
Amended and Restated as of January 1, 1997.
(Exhibit 4.2.24.1, 1996 NU Form 10-K, File No.
1-5324)
4.2.7.2 Standby Bond Purchase Agreement
among CL&P, Bank of New York as Purchasing
Agent and the Banks Named therein, dated
October 24, 2000. (Exhibit 4.2.24.2 of 2000 NU
Form 10-K, File No. 1-5324)
4.2.7.3 AMBAC Municipal Bond Insurance
Policy issued by the Connecticut Development
Authority (CL&P Pollution Control Revenue Bond-
1996A Series), effective January 23, 1997.
(Exhibit 4.2.24.3, 1996 NU Form 10-K, File No.
1-5324)
4.2.7.4 Amendment No. 2 to the Standby Bond
Purchase Agreement dated as of September 9,
2002, among CL&P, The Bank of New York, and
the Participating Banks referred to therein.
(Exhibit 4.2.7.4, 2002 NU Form 10-Q for the
Quarter Ended September 30, 2002, File No. 1-
5324)
4.2.8 Amended and Restated Receivables Purchase and Sale
Agreement dated as of March 30, 2001 (CL&P and CL&P
Receivables Corporation (CRC)). (Exhibit 10.1, 2001 NU
10-Q for the Quarter Ended September 30, 2001 (File No. 1-
5324)
#4.2.8.1 Amendment No. 2 to the Purchase and Sale
Agreement dated as of July 10, 2002 (CL&P and
CRC).
4.2.9 Purchase and Contribution Agreement (CL&P and CRC), dated
as of September 30, 1997 (Exhibit 10.49.1, 1997 NU Form
10-K, File No. 1-5324)
#4.2.9.1 Amendment No. 2 to the Purchase and
Contribution Agreement between CL&P and CRC
dated as of March 30, 2001.
4.2.10 Revolving Credit Agreement among WMECO, CL&P, PSNH and
Yankee and the banks named therein, dated November 12,
2002. (Exhibit B-4 to 35-CERT filed November 21, 2002,
File No. 70-9755)
|
4.3 Public Service Company of New Hampshire
4.3.1 First Mortgage Indenture dated as of August 15, 1978
between PSNH and First Fidelity Bank, National
Association, New Jersey, now First Union National Bank,
Trustee, (Composite including all amendments to May 16,
1991). (Exhibit 4.4.1, 1992 NU Form 10-K, File No.
1-5324)
4.3.1.1 Tenth Supplemental Indenture dated as of May 1,
1991 between PSNH and First Fidelity Bank,
National Association, now First Union National
Bank. (Exhibit 4.1, PSNH Current Report on
Form 8-K dated February 10, 1992, File No. 1-
6392)
4.3.1.2 Twelfth Supplemental Indenture dated as of
December 1, 2001 between PSNH and First Union
National Bank. (Exhibit 4.3.1.2, 2001 NU Form
10-K, File No. 1-5324)
4.3.2 Series D (Tax Exempt Refunding) Amended and Restated
PCRB Loan and Trust Agreement dated as of April 1, 1999.
(Exhibit 4.3.6, 1999 NU Form 10-K, File No. 1-5324)
4.3.3 Series E (Tax Exempt Refunding) Amended & Restated
PCRB Loan and Trust Agreement dated as of April 1, 1999.
(Exhibit 4.3.7, 1999 NU Form 10-K, File No. 1-5324)
4.3.4 Series A Loan and Trust Agreement among Business Finance
Authority of the State of New Hampshire and PSNH and
State Street Bank and Trust Company, as Trustee (Tax
Exempt Pollution Control Bonds) dated as of October 1,
2001. (Exhibit 4.3.4, 2001 NU Form 10-K, File No. 1-
5324)
4.3.5 Series B Loan and Trust Agreement among Business Finance
Authority of the State of New Hampshire and PSNH and
State Street Bank and Trust Company, as Trustee (Tax
Exempt Pollution Control Bonds) dated as of October 1,
2001. (Exhibit 4.3.5, 2001 NU Form 10-K, File No. 1-
5324)
4.3.6 Series C Loan and Trust Agreement among Business Finance
Authority of the State of New Hampshire and PSNH and
State Street Bank and Trust Company, as Trustee (Tax
Exempt Pollution Control Bonds) dated as of October1,
2001. (Exhibit 4.3.6, 2001 NU Form 10-K, File No. 1-5324)
4.3.7 Revolving Credit Agreement among WMECO, CL&P, PSNH and
Yankee and the banks named therein, dated November 12,
2002. (Exhibit B-4 to 35-CERT filed November 21, 2002,
File No. 70-9755)
|
4.4 Western Massachusetts Electric Company
4.4.1 Loan Agreement between Connecticut Development Authority
and WMECO, (Pollution Control Bonds - Series A, Tax
Exempt Refunding) dated as of September 1, 1993. (Exhibit
4.4.13, 1993 NU Form 10-K, File No. 1-5324)
4.4.2 Revolving Credit Agreement among WMECO, CL&P, PSNH and
Yankee and the banks named therein, dated November 12,
2002. (Exhibit B-4 to 35-CERT filed November 21, 2002,
File No. 70-9755)
|
10 Material Contracts
10.1 Stockholder Agreement dated as of July 1, 1964 among the stockholders of CYAPC. (Exhibit 10.1, 1994 NU Form 10-K, File No. 1-5324)
10.2 Form of Power Contract dated as of July 1, 1964 between CYAPC and each of CL&P, HELCO, PSNH and WMECO. (Exhibit 10.2, 1994 NU Form 10-K, File No. 1-5324)
10.2.1 Form of Additional Power Contract dated as of April 30,
1984, between CYAPC and each of CL&P, PSNH and WMECO.
(Exhibit 10.2.1, 1994 NU Form 10-K, File No. 1-5324)
10.2.2 Form of 1987 Supplementary Power Contract dated as of
April 1, 1987, between CYAPC and each of CL&P, PSNH and
WMECO. (Exhibit 10.2.6, 1987 NU Form 10-K, File No. 1-
5324)
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10.3 Capital Funds Agreement dated as of September 1, 1964 between CYAPC and CL&P, HELCO, PSNH and WMECO. (Exhibit 10.3, 1994 NU Form 10-K, File No. 1-5324)
10.4 Stockholder Agreement dated December 10, 1958 between YAEC and CL&P, HELCO, PSNH and WMECO. (Exhibit 10.4, 1993 NU Form 10-K, File No. 1-5324)
10.5 Form of Amendment No. 3, dated as of April 1, 1985, to Power Contract between YAEC and each of CL&P, PSNH and WMECO, including a composite restatement of original Power Contract dated June 30, 1959 and Amendment No. 1 dated April 1, 1975 and Amendment No. 2 dated October 1, 1980. (Exhibit 10.5, 1988 NU Form 10-K, File No. 1-
5324.)
10.5.1 Form of Amendment No. 4 to Power Contract, dated May 6,
1988, between YAEC and each of CL&P, PSNH and WMECO.
(Exhibit 10.5.1, 1989 NU Form 10-K, File No. 1-5324)
10.5.2 Form of Amendment No. 5 to Power Contract, dated June 26,
1989, between YAEC and each of CL&P, PSNH and WMECO.
(Exhibit 10.5.2, 1989 NU Form 10-K, File No. 1-5324)
10.5.3 Form of Amendment No. 6 to Power Contract, dated July 1,
1989, between YAEC and each of CL&P, PSNH and WMECO.
(Exhibit 10.5.3, 1989 NU Form 10-K, File No. 1-5324)
10.5.4 Form of Amendment No. 7 to Power Contract, dated
February 1, 1992, between YAEC and each of CL&P, PSNH and
WMECO. (Exhibit 10.5.4, 1993 NU Form 10-K, File No. 1-
5324)
|
10.6 Stockholder Agreement dated as of May 20, 1968 among stockholders of MYAPC. (Exhibit 10.6, 1997 NU Form 10-K, File No. 1-5324)
10.7 Form of Power Contract dated as of May 20, 1968 between MYAPC and each of CL&P, HELCO, PSNH and WMECO. (Exhibit 10.7, 1997 Form 10-K, File No. 1-5324)
10.7.1 Form of Amendment No. 1 to Power Contract dated as of
March 1, 1983 between MYAPC and each of CL&P, PSNH and
WMECO. (Exhibit 10.7.1, 1993 NU Form 10-K, File No. 1-
5324)
10.7.2 Form of Amendment No. 2 to Power Contract dated as of
January 1, 1984 between MYAPC and each of CL&P, PSNH and
WMECO. (Exhibit 10.7.2, 1993 NU Form 10-K, File No. 1-
5324)
10.7.3 Form of Amendment No. 3 to Power Contract dated as of
October 1, 1984 between MYAPC and each of CL&P, PSNH and
WMECO. (Exhibit No. 10.7.3, 1994 NU Form 10-K, File No.
1-5324)
10.7.4 Form of Additional Power Contract dated as of February 1,
1984 between MYAPC and each of CL&P, PSNH and WMECO.
(Exhibit 10.7.4, 1993 NU Form 10-K, File No. 1-5324)
|
10.8 Capital Funds Agreement dated as of May 20, 1968 between MYAPC and CL&P, PSNH, HELCO and WMECO. (Exhibit 10.8, 1997 NU Form 10-K, File No. 1-5324)
10.8.1 Amendment No. 1 to Capital Funds Agreement, dated as of
August 1, 1985, between MYAPC, CL&P, PSNH and WMECO.
(Exhibit No. 10.8.1, 1994 NU Form 10-K, File No. 1-5324)
|
10.9 Sponsor Agreement dated as of August 1, 1968 among the sponsors of VYNPC. (Exhibit 10.9, 1997 NU Form 10-K, File No. 1-5324)
10.10 Form of Power Contract dated as of February 1, 1968 between VYNPC and each of CL&P, HELCO, PSNH and WMECO. (Exhibit 10.10, 1997 NU Form 10-K, File No. 1-5324)
10.10.1 Form of Amendment to Power Contract dated as of June 1,
1972 between VYNPC and each of CL&P, HELCO, PSNH and
WMECO. (Exhibit 5.22, File No. 2-47038)
10.10.2 Form of Second Amendment to Power Contract dated as of
April 15, 1983 between VYNPC and each of CL&P, PSNH and
WMECO. (Exhibit 10.10.2, 1993 NU Form 10-K, File No. 1-
5324)
10.10.3 Form of Third Amendment to Power Contract dated as of
April 24, 1985 between VYNPC and each of CL&P, PSNH and
WMECO. (Exhibit No. 10.10.3, 1994 NU Form 10-K, File No.
1-5324)
10.10.4 Form of Fourth Amendment to Power Contract
dated as of June 1, 1985 between VYNPC and each of CL&P,
PSNH and WMECO. (Exhibit No. 10.10.4, 1996 NU Form 10-K,
File No. 1-5324)
10.10.5 Form of Fifth Amendment to Power Contract dated as of
May 6, 1988 between VYNPC and each of CL&P, PSNH and
WMECO. (Exhibit 10.10.5, NU Form 10-K, File No. 1-
5324)
10.10.6 Form of Sixth Amendment to Power Contract dated as of
May 6, 1988 between VYNPC and each of CL&P, PSNH and
WMECO. (Exhibit 10.10.6, 1990 NU Form 10-K, File No. 1-
5324)
10.10.7 Form of Seventh Amendment to Power Contract dated as of
June 15, 1989 between VYNPC and each of CL&P, PSNH and
WMECO. (Exhibit 10.10.7, 1990 NU Form 10-K, File No. 1-
5324)
10.10.8 Form of Eighth Amendment to Power Contract dated as of
December 1, 1989 between VYNPC and each of CL&P, PSNH and
WMECO. (Exhibit 10.10.8, 1990 NU Form 10-K, File No. 1-
5324)
10.10.9 Form of Additional Power Contract dated as of February 1,
1984 between VYNPC and each of CL&P, PSNH and WMECO.
(Exhibit 10.10.9, 1993 NU Form 10-K, File No. 1-5324)
*10.10.10 Form of Amendatory Agreement, dated as of September 21,
2001 between VYNPC and each of CL&P, PSNH and WMECO.
10.11 Capital Funds Agreement dated as of February 1, 1968
between VYNPC and CL&P, HELCO, PSNH and WMECO. Exhibit 10.11,
1997 NU Form 10-K, File No. 1-5324)
10.11.1 Form of First Amendment to Capital Funds Agreement dated
as of March 12, 1968 between VYNPC and CL&P, HELCO, PSNH
and WMECO. (Exhibit 10.11.1, 1997 NU Form 10-K, File
No. 1-5324)
10.11.2 Form of Second Amendment to Capital Funds Agreement dated
as of September 1, 1993 between VYNPC and CL&P, HELCO,
PSNH and WMECO. (Exhibit 10.11.2, 1993 NU Form 10-K,
File No. 1-5324)
10.12 Agreement dated July 19, 1990, among NAESCO and Seabrook Joint
owners with respect to operation of Seabrook. (Exhibit 10.53,
1990 NU Form 10-K, File No. 1-5324)
10.13 Sharing Agreement between CL&P, WMECO, HP&E, HWP and PSNH dated
as of June 1, 1992. (Exhibit 10.17, 1992 NU Form 10-K, File No.
1-5324)
10.14 Rate Agreement by and between NUSCO, on behalf of NU, and the
Governor of the State of New Hampshire and the New Hampshire
Attorney General dated as of November 22, 1989. (Exhibit 10.44,
1989 NU Form 10-K, File No. 1-5324)
10.14.1 First Amendment to Rate Agreement dated as of
December 5, 1989. (Exhibit 10.16.1, 1995 NU Form 10-K,
File No. 1-5324)
10.14.2 Second Amendment to Rate Agreement dated as of
December 12, 1989. (Exhibit 10.16.2, 1995 NU Form 10-K,
File No. 1-5324)
10.14.3 Third Amendment to Rate Agreement dated as of
December 3, 1993. (Exhibit 10.16.3, 1995 NU Form 10-K,
File No. 1-5324)
10.14.4 Fourth Amendment to Rate Agreement dated as of
September 21, 1994. (Exhibit 10.16.4, 1995 NU Form 10-K,
File No. 1-5324)
10.14.5 Fifth Amendment to Rate Agreement dated as of
September 9, 1994. (Exhibit 10.16.5, 1995 NU Form 10-K,
File No. 1-5324)
10.15 Agreement to Settle PSNH Restructuring. (Exhibit 10.2, 1999 NU
Form 10-Q for the Quarter Ended June 30, 1999, File No. 1-5324)
10.15.1 Revised and Conformed Agreement to Settle PSNH
Restructuring, dated August 2, 1999, conformed June 23
and executed on September 22, 2000. (Exhibit 10.15.1,
2001 NU Form 10-K, File No. 1-5324)
10.16 Merger Settlement Agreement between NU, Con Edison and NHPUC dated
as of December 6, 2000. (Exhibit O.1, to NU's U-1 Application, File
No. 70-9711)
10.17 Form of Seabrook Power Contracts between PSNH and NAEC, as amended
and restated. (Exhibit 10.45, 1992 NU Form 10-K, File No. 1-5324)
10.18 Agreement (composite) for joint ownership, construction and
operation of New Hampshire nuclear unit, as amended through the
November 1, 1990 twenty-third amendment. (Exhibit No. 10.17, 1994
NU Form 10-K, File No. 1-5324)
10.18.1 Memorandum of Understanding dated November 7,
1988 between PSNH and Massachusetts Municipal Wholesale
Electric Company. (Exhibit 10.17, PSNH 1989 Form 10-K,
File No. 1-6392)
10.18.2 Agreement of Settlement among Joint Owners dated as of
January 13, 1989. (Exhibit 10.13.21, 1988 NU Form 10-K,
File No. 1-5324)
10.18.2.1 Supplement to Settlement Agreement,
dated as of February 7, 1989, between PSNH and
Central Maine Power Company. (Exhibit 10.18.1,
PSNH 1989 Form 10-K, File No. 1-6392)
10.19 Amended and Restated Agreement for Seabrook Project Disbursing
Agent dated as of November 1, 1990. (Exhibit 10.4.7, File No. 33-
35312)
10.19.1 Form of First Amendment to Exhibit 10.22.
(Exhibit 10.4.8, File No. 33-35312)
10.19.2 Form (Composite) of Second Amendment to Exhibit
10.22. (Exhibit 10.18.2, 1993 NU Form 10-K, File No. 1-
5324)
10.20 Agreement dated November 1, 1974 for Joint Ownership, Construction
and Operation of William F. Wyman Unit No. 4 among PSNH, Central
Maine Power Company and other utilities. (Exhibit 5.16, File No. 2-
52900)
10.20.1 Amendment to Exhibit 10.20 dated June 30, 1975.
(Exhibit 5.48, File No. 2-55458)
10.20.2 Amendment to Exhibit 10.20 dated as of
August 16, 1976. (Exhibit 5.19, File No. 2-58251)
10.20.3 Amendment to Exhibit 10.20 dated as of
December 31, 1978. (Exhibit 5.10.3, File No. 2-64294)
10.21 Form of Service Contract dated as of July 1, 1966 between each of
NU, CL&P and WMECO and NUSCO. (Exhibit 10.20, 1993 NU Form 10-K,
File No. 1-5324)
10.21.1 Service Contract dated as of June 5, 1992
between PSNH and NUSCO. (Exhibit 10.12.4, 1992 NU Form
10-K, File No. 1-5324)
10.21.2 Form of Annual Renewal of Service Contract.
(Exhibit 10.20.3, 1993 NU Form 10-K, File No. 1-5324)
10.22 Service Contract dated as of January 4,1999 between NUSCO and NGC.
(Exhibit 10.7 to NGC Registration Statement S-4 dated December 6,
2001, File No. 333-74636)
10.22.1 Form of Service Agreement Renewals, dated
December 31, 1999 and December 31, 2000, of Service
Contract, dated as of January 4, 1999, between NUSCO and
NGC. (Exhibit 10.7.1 to NGC Registration Statement S-4
dated December 6, 2001, File No. 333-74636)
10.23 Management and Operating Agreement, dated February 1, 2000, between
NGC and NGS. (Exhibit 10.6 to NGC Registration Statement S-4 dated
December 6, 2001, File No. 333-74636)
10.23.1 Amendment No. 1, dated March 1, 2000, to Management and
Operating Agreement, dated February 1, 2000, between NGC
and NGS. (Exhibit 10.6.1 to NGC Registration Statement
S-4 dated December 6, 2001, File No. 333-74636)
10.24 Memorandum of Understanding between CL&P, HELCO, HP&E, HWP and
WMECO dated as of June 1, 1970 with respect to pooling of
generation and transmission. (Exhibit 13.32, File No. 2-38177)
10.24.1 Amendment to Memorandum of Understanding
between CL&P, HELCO, HP&E, HWP and WMECO dated as of
February 2, 1982 with respect to pooling of generation
and transmission. (Exhibit 10.21.1, 1993 NU Form 10-K,
File No. 1-5324)
10.24.2 Amendment to Memorandum of Understanding between
CL&P, HELCO, HP&E, HWP and WMECO dated as of
January 1, 1984 with respect to pooling of generation and
transmission. (Exhibit 10.21.2, 1994 NU Form 10-K, File
No. 1-5324)
10.24.3 Second Amendment to Memorandum of Understanding between
CL&P, HELCO, HP&E, HWP and WMECO dated as of June 8, 1999
with respect to pooling of generation and transmission.
(Exhibit 10.23.3, 1999 NU Form 10-K, File No. 1-5324)
10.25 Restated NEPOOL Power Pool Agreement. (restated by the Sixty-Ninth
Agreement dated as of December 31, 2000, and includes the Restated
NEPOOL Open Access Transmission Tariff)
10.25.1 Form of Interim ISO Agreement (Attachment to
Thirty-Third Amendment to Exhibit 10.26 dated as of
December 31, 1996). (Exhibit 10.23.6, 1996 NU Form 10-K,
File No. 1-5324)
*10.25.1.1 Amendment No. 3 to Interim
ISO Agreement dated as of April 30, 2002.
10.25.2 Seventieth Agreement Amending NEPOOL Agreement (ISO
Capital Funding Tariff) (FERC Docket ER-01-1460-000)
dated as of February 2, 2001. (Exhibit 10.23.2, 2001 NU
Form 10-K, File No. 1-5324)
10.25.3 Seventy-First Agreement Amending NEPOOL Agreement (Late
Payment Fees) (FERC Docket ER-01-1460-000) dated as of
February 2, 2001. (Exhibit 10.23.3, 2001 NU Form 10-K,
File No. 1-5324)
10.25.4 Seventy-Second Agreement Amending NEPOOL Agreement (Net
Commitment Period Compensation "NCPC") (FERC Docket ER-01-
1891-000) dated as of April 6, 2001. (Exhibit 10.23.4,
2001 NU Form 10-K, File No. 1-5324)
10.25.5 Seventy-Third Agreement Amending NEPOOL Agreement
(Schedule 2 Changes) (FERC Docket ER-01-2161-000) dated
as of May 9, 2001. (Exhibit 10.23.5, 2001 NU Form 10-K,
File No. 1-5324)
10.25.6 Seventy-Fourth Agreement Amending NEPOOL Agreement
(Review Bond Amendment) (FERC Docket ER-01-2140-000)
dated as of May 9, 2001. (Exhibit 10.23.6, 2001 NU Form
10-K, File No. 1-5324)
10.25.7 Seventy-Sixth Agreement Amending NEPOOL Agreement
(Compliance with June 13, 2001 Orders) (FERC Dockets EL00-
62-004, et al. and ER-98-3853-005) dated as of June 29,
2001. (Exhibit 10.23.7, 2001 NU Form 10-K, File No. 1-
5324)
10.25.8 Seventy-Eighth Agreement Amending NEPOOL Agreement
(Revised Sections 18.4 and 18.5) (FERC Docket EL00-62-
036) dated as of September 24, 2001. (Exhibit 10.23.8,
2001 NU Form 10-K, File No. 1-5324)
10.25.9 Seventy-Ninth Agreement Amending NEPOOL Agreement (ICA
Compliance Amendment) (FERC Docket EL00-62-036) dated as
of September 24, 2001. (Exhibit 10.23.9, 2001 NU Form
10-K, File No. 1-5324)
10.25.10 Eightieth Agreement Amending NEPOOL Agreement (Generation
Information System "GIS" Agreement) dated as of
October 12, 2001. (Exhibit 10.23.10, 2001 NU Form 10-K,
File No. 1-5324)
10.25.11 Eighty-First Agreement Amending NEPOOL Agreement
(Restatement of Financial Assurance Policies) dated as of
December 7, 2001. (Exhibit 10.23.11, 2001 NU Form 10-K,
File No. 1-5324)
*10.25.12 Eighty-Second Agreement Amending NEPOOL Agreement
(Amendment to Schedule 16) dates as of January 18, 2002.
*10.25.13 Eighty-Third Agreement Amending NEPOOL (Financial
Assurance and Billing Policies) dated as of March 8,
2002.
*10.25.14 Eighty-Fourth Agreement Amending NEPOOL (Integration of
Merchant Transmission Facilities) dated as of April 5,
2002.
*10.25.15 Eighty-Fifth Agreement Amending NEPOOL (Non Participant
FTR Financial Assurance Policy) dated as of May 9, 2002.
*10.25.16 Eighty-Sixth Agreement Amending NEPOOL
(Interruptible/Dispatchable Loads for Objective
Capability) dated as of May 3, 2002.
*10.25.17 Eighty-Seventh Agreement Amending NEPOOL (Financial
Assurance Policies and Billing Procedures) dated as of
June 21, 2002.
*10.25.18 Eighty-Eighth Agreement Amending NEPOOL (Schedule 16
Amendment) dated as of October 4, 2002).
*10.25.19 Eighty-Ninth Agreement Amending NEPOOL (Technical
Committee Voting Changes) dated as of October 4, 2002.
*10.25.20 Ninetieth Agreement Amending NEPOOL (Excess Financial
Assurance) dated as of October 4, 2002.
*10.25.21 Ninety-First Agreement Amending NEPOOL (Demand Response
Provider Changes) dated as of November 1, 2002.
*10.25.22 Ninety-Second Agreement Amending NEPOOL (NEPOOL SMD -
Conforming RNA Changes) dated as of November 1, 2002.
*10.25.23 Ninety Third Agreement Amending NEPOOL (NEPOOL SMD -
Conforming Tariff Charges) dated as of November 1, 2002.
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10.26 Agreements among New England Utilities with respect to the Hydro-
Quebec interconnection projects. (See Exhibits 10(u) and 10(v);
10(w), 10(x), and 10(y), 1990 and 1988, respectively, Form 10-K of
New England Electric System, File No. 1-3446.)
10.27 Lease dated as of April 14, 1992 between RRR and NUSCO with respect to the Berlin, Connecticut headquarters (office lease). (Exhibit 10.29, 1992 NU Form 10-K, File No. 1-5324)
10.27.1 Lease dated as of April 14, 1992 between RRR
and NUSCO with respect to the Berlin, Connecticut
headquarters (project lease). (Exhibit 10.29.1, 1992 NU
Form 10-K, File No. 1-5324)
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10.28 Lease and Agreement, dated as of December 15, 1988, by and between WMECO and Bank of New England, N.A., with BNE Realty Leasing Corporation of North Carolina. (Exhibit 10.63, 1988 NU Form 10-K, File No. 1-5324.)
10.29 Note Agreement dated April 14, 1992, by and between RRR and Purchasers named therein (Connecticut General Life Insurance Company, Life Insurance Company of North America, INA Life Insurance Company of New York, Life Insurance Company of Georgia), with respect to RRR's sale of $15 million of guaranteed senior secured notes due 2007 and $28 million of guaranteed senior secured notes due 2017. (Exhibit 10.52, 1992 NU Form 10-K, File No. 1-
5324)
10.29.1 Amendment to Note Agreement, dated
September 26, 1997. (Exhibit 10.31.1, 1997 NU Form 10-K,
File No. 1-5324)
10.29.2 Note Guaranty dated April 14, 1992 by Northeast
Utilities pursuant to Note Agreement dated April 14, 1992
between RRR and Note Purchasers, for the benefit of The
Connecticut National Bank as Trustee, the Purchasers and
the owners of the notes. (Exhibit 10.52.1, 1992 NU Form
10-K, File No. 1-5324)
10.29.2.1 Extension of Note Guaranty, dated
September 26, 1997. (Exhibit 10.31.2.1, 1997
NU Form 10-K, File No. 1-5324)
10.29.3 Assignment of Leases, Rents and Profits,
Security Agreement and Negative Pledge, dated as of
April 14, 1992 among RRR, NUSCO and The Connecticut
National Bank as Trustee, securing notes sold by RRR
pursuant to April 14, 1992 Note Agreement. (Exhibit
10.52.2, 1997 NU Form 10-K, File No. 1-5324)
10.29.3.1 Modification of and Confirmation of
Assignment of Leases, Rents and Profits,
Security Agreement and Negative Pledge, dated
as of September 26, 1997. (Exhibit 10.31.3.1,
1997 NU Form 10-K, File No. 1-5324)
10.29.4 Purchase and Sale Agreement, dated July 28,
1997 by and between RRR and the Sellers and Purchasers
named therein. (Exhibit 10.31.4, 1997 NU Form 10-K, File
No. 1-5324)
10.29.5 Purchase and Sale Agreement, dated September 26, 1997
by and between RRR and the Purchaser named therein.
(Exhibit 10.31.5, 1992 NU Form 10-K, File No. 1-5324)
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10.30 NU Executive Incentive Plan, effective as of January 1, 1991.
(Exhibit 10.44, NU 1991 Form 10-K, File No. 1-5324)
10.31 Northeast Utilities Incentive Plan, effective as of January 1, 1998. (Exhibit 10.35.1, 1998 NU Form 10-K, File No. 1-5324)
10.31.1 Amendment to Northeast Utilities Incentive
Plan, effective as of February 23, 1999. (Exhibit
10.35.1.1, 1998 NU Form 10-K, File No. 1-5324)
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10.32 Supplemental Executive Retirement Plan for Officers of NU system Companies, Amended and Restated effective as of January 1, 1992. (Exhibit 10.45.1, NU Form 10-Q for the Quarter Ended June 30, 1992, File No. 1-5324)
10.32.1 Amendment 1 to Supplemental Executive
Retirement Plan, effective as of August 1, 1993.
(Exhibit 10.35.1, 1993 NU Form 10-K, File No. 1-5324)
10.32.2 Amendment 2 to Supplemental Executive
Retirement Plan, effective as of January 1, 1994.(Exhibit
10.35.2, 1993 NU Form 10-K, File No. 1-5324)
10.32.3 Amendment 3 to Supplemental Executive
Retirement Plan, effective as of January 1, 1996.
(Exhibit 10.36.3, 1995 NU Form 10-K, File No. 1-5324)
10.32.4 Amendment 4 to Supplemental Executive
Retirement Plan, effective as of February 26, 2002.
(Exhibit 10.35.4, 2001 NU Form 10-K, File No. 1-5324)
10.32.5 Amendment 5 to Supplemental Executive
Retirement Plan, effective as of November 1, 2001.
(Exhibit 10.35.5, 2001 NU Form 10-K, File No. 1-5324)
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*10.33 Trust under Supplemental Executive Retirement Plan dated May 2, 1994.
10.34 Special Severance Program for Officers of NU system companies, as adopted on July 15, 1998. (Exhibit 10.37, 1998 NU Form 10-K, File No. 1-5324)
10.34.1 Amendment to Special Severance Program, effective as of
February 23, 1999. (Exhibit 10.37.1, 1998 NU Form 10-K,
File No. 1-5324)
10.34.2 Amendment to Special Severance Program, effective as of
September 14, 1999. (Exhibit 10.3, 1999 NU Form 10-Q for
the Quarter Ended September 30, 1999, File No. 1-5324)
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10.35 Loan Agreement dated as of December 2, 1991, by and between NU and Mellon Bank, N.A., as Trustee, with respect to NU's loan of $175 million to an ESOP trust. (Exhibit 10.46, 1991 NU Form 10-K, File No. 1-5324)
10.35.1 First Amendment to Loan Agreement dated February 7, 1992.
(Exhibit 10.36.1, 1993 NU Form 10-K, File No. 1-5324)
10.35.2 Loan Agreement dated as of March 19, 1992 by and between
NU and Mellon Bank, N.A., as Trustee, with respect to NU's
loan of $75 million to the ESOP trust. (Exhibit 10.49.1,
1992 NU Form 10-K, File No. 1-5324)
10.35.3 Second Amendment to Loan Agreement dated April 9, 1992.
(Exhibit 10.36.3, 1993 NU Form 10-K, File No. 1-5324)
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10.36 Indenture Mortgage, dated as of October 18, 2001 between NGC and The Bank of New York, as trustee. (Exhibit 4.1 to NGC Registration Statement S-4 dated December 6, 2001, File No. 333-74636)
10.36.1 First Supplemental Indenture Mortgage, dated as of
October 18, 2001 between NGC and The Bank of New York, as
trustee. (Exhibit 4.2 to NGC Registration Statement S-4
dated December 6, 2001, File No. 333-74636)
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10.37 Employment Agreement with Michael G. Morris. (Exhibit 10.39, 1997 NU Form 10-K, File No. 1-5324)
10.37.1 Amendment to Morris Employment Agreement, dated as of
February 23, 1999. (Exhibit 10.39.1, 1998 NU Form 10-K,
File No. 1-5324)
10.37.2 Amendment to Morris Employment Agreement, dated as of
June 28, 2001. (Exhibit 10.41.2 to 2001 NU Form 10-Q for
the Quarter Ending September 30, 2001, File No. 1-5324)
10.37.3 Amendment to Morris Employment Agreement, dated as of
September 11, 2001. (Exhibit 10.41.3 to 2001 NU Form 10Q
for the Quarter Ending September 30, 2001, File No.
1-5324)
10.37.4 Employment Agreement with Michael G. Morris dated as of
August 20, 2002. (Exhibit 10.38.4 to 2002 NU Form 10-Q
for the Quarter Ending September 30, 2002, File No. 1-
5324)
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10.38 Arrangement with Michael G. Morris with Respect to Seabrook.
(Exhibit 10.38.4 to 2002 NU Form 10-Q for the Quarter Ending
September 30, 2002, File No. 1-5324)
10.39 Arrangement with Michael G. Morris with respect to use of corporate airplane.
10.40 Transition and Retirement Agreement with Bernard M. Fox. (Exhibit 10.39, 1996 NU Form 10-K, File No. 1-5324)
10.41 Employment Agreement with Bruce M. Kenyon. (Exhibit 10.40, 1996 NU Form 10-K, File No. 1-5324)
10.41.1 Amendment to Kenyon Employment Agreement, dated
as of January 13, 1998. (Exhibit 10.41.1, 1998 NU Form
10-K, File No. 1-5324)
10.41.2 Amendment to Kenyon Employment Agreement, dated
as of February 23, 1999. (Exhibit 10.41.2, 1998 NU Form
10-K, File No. 1-5324)
10.41.3 Amendment to Kenyon Employment Agreement, dated as of
May 14, 1999. (Exhibit 10.1, 1999 NU Form 10-Q for the
Quarter Ended March 31,1999, File No. 1-5324)
10.41.4 Amendment to Kenyon Employment Agreement, dated as of
March 21, 2000. (Exhibit 10.1, 2000 NU Form 10-Q for the
Quarter Ended March 31, 2000, File No. 1-5324)
10.41.5 Consulting Agreement with Bruce M. Kenyon, dated as of
December 21, 2002.
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10.42 Employment Agreement with John H. Forsgren. (Exhibit 10.41, 1996 NU Form 10-K, File No. 1-5324)
10.42.1 Amendment to Forsgren Employment Agreement Exhibit 10.43,
dated as of January 13, 1998. (Exhibit 10.42.1, 1998 NU
Form 10-K, File No. 1-5324)
10.42.2 Amendment to Forsgren Employment Agreement, dated as of
February 23, 1999. (Exhibit 10.42.2, 1998 NU Form 10-K,
File No. 1-5324)
10.42.3 Amendment to Forsgren Employment Agreement, dated as of
May 10, 1999. (Exhibit 10.1, 1999 NU Form 10-Q for the
Quarter Ended March 31, 1999, File No. 1-5324)
10.42.4 Amendment to Forsgren Employment Agreement,
dated as of September 14, 1999. (Exhibit 10.4, 1999 NU
Form 10-Q for the Quarter Ended September 30, 1999, File
No. 1-5324)
10.42.5 Amendment to Forsgren Employment Agreement, dated as of
September 19, 2001. (Exhibit 10.44.7 to 2001 NU Form
10-Q for the Quarter Ending September 30, 2001, File No.
1-5324).
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10.43 Supplemental Retirement Benefit with John H. Forsgren, dated as of August 8, 2001. (Exhibit 10.44.5, 2001 NU Form 10-Q for Quarter Ended September 30, 2001, File No. 1-5324)
10.44 Supplemental Compensation Arrangement with John J. Forsgren, dated as of September 5, 2001. (Exhibit 10.44.6, 2001 NU Form 10-Q for Quarter Ended September 30, 2001, File No. 1-5324).
10.45 Employment Agreement with Cheryl W. Grise. (Exhibit 10.44, 1998 NU Form 10-K, File No. 1-5324)
10.45.1 Amendment to Grise Employment Agreement, dated as of
January 13, 1998. (Exhibit 10.44.1, 1998 NU Form 10-K,
File No. 1-5324)
10.45.2 Amendment to Grise Employment Agreement, dated as of
February 23, 1999. (Exhibit 10.44.2, 1998 NU Form 10-K,
File No. 1-5324)
10.45.3 Amendment to Grise Employment Agreement, dated as of
September 14, 1999. (Exhibit 10.5, 1999 NU Form 10-Q for
the Quarter Ended September 30, 1999, File No. 1-5324)
10.45.4 Amendment to Grise Employment Agreement dated as of
September 19, 2001. (Exhibit 10.46.5 to 2001 NU Form
10-Q for the Quarter Ending September 30, 2001, File No.
1-5324)
10.45.5 Supplemental Compensation Arrangement with Cheryl W.
Grise, dated as of September 17, 2001. (Exhibit 10.46.4,
2001 NU Form 10-Q for Quarter Ended September 30, 2001,
File No. 1-5324)
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10.46 Agreement with Gary D. Simon dated March 16, 1998. (Exhibit 10.45, 2001 NU Form 10-K, File No. 1-5324)
10.47 Employment Agreement with Charles W. Shivery, dated as of June 1, 2002. (Exhibit 10.64 to NU Form 10-Q for the quarter ended June 30, 2002, File No. 1-5324)
10.48 Northeast Utilities Deferred Compensation Plan for Trustees, Amended and Restated December 13, 1994. (Exhibit 10.39, 1995 NU Form 10-K, File No. 1-5324)
10.48.1 Amendment to Deferred Compensation Plan, effective
November 5, 2001. (Exhibit 10.46.1, 2001 NU Form 10-K,
File No. 1-5324)
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10.49 Deferred Compensation Plan for Officers of Northeast Utilities System Companies adopted September 23, 1986. (Exhibit 10.40, 1995 NU Form 10-K, File No. 1-5324)
10.50 Northeast Utilities Deferred Compensation Plan for Executives, adopted January 13, 1998. (Exhibit A.5, File No. 70-09185)
10.51 Reciprocal Support Agreement Among NNECO, NAESCO, CYAPC, YAEC and NUSCO dated January 1, 1996. (Exhibit 10.41, 1995 NU Form 10-K, File No. 1-5324)
10.52 Indenture of Mortgage and Deed of Trust dated July 1, 1989 between Yankee Gas and the Connecticut National Bank, as Trustee (Exhibit 4.7, 1990 YES Form 10-K, File No. 0-10721)
10.53 Power Purchase and Sales Agreement, dated December 27, 1999 between NGC and Select Energy (Exhibit 10.1 to NGC Registration Statement S-4 dated December 6, 2001)
10.53.1 Consent and Agreement, dated as of October 18,
2001, among NU, Select Energy, The Bank of New York, as
trustee and NGC, dated as of October 18, 2001 between
NGC. (Exhibit 10.3 to NGC Registration Statement on Form
S-4 dated December 6, 2001)
10.53.2 Security Agreement, dated as of October 18,
2001, between NGC and The Bank of New York, as trustee.
(Exhibit 10.4 to NGC Registration Statement on Form S-4
dated December 6, 2001)
10.53.3 Form of Mortgage, Assignment of Leases and
Rents, Security Agreement and Fixture Filing, dated as of
October 18, 2001, by NGC in favor of The Bank of New
York, as Trustee. (Exhibit 10.5 to NGC Registration
Statement on Form S-4 dated December 6, 2001)
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10.54 CL&P Transition Property Purchase and Sale Agreement dated as of March 30, 2001. (Exhibit 10.55, 2001 CL&P Form 10-K, File No. 0- 11419)
10.55 CL&P Transition Property Servicing Agreement dated as of March 30, 2001. (Exhibit 10.56, 2001 NU Form 10-K, File No. 1-5324)
10.56 PSNH Purchase and Sale Agreement with PSNH Funding LLC dated as of April 25, 2001. (Exhibit 10.57, 2001 NU Form 10-K, File No. 1- 5324)
10.57 PSNH Servicing Agreement with PSNH Funding LLC dated as of April 25, 2001. (Exhibit 10.58, 2001 NU Form 10-K, File No. 1- 5324)
10.58 PSNH Purchase and Sale Agreement with PSNH Funding LLC2 dated as of January 30, 2002. (Exhibit 10.59 2001 NU Form 10-K, File No. 1- 5324)
10.59 PSNH Servicing Agreement with PSNH Funding LLC2 dated as of January 30, 2002. (Exhibit 10.60, 2001 NU Form 10-K, File No. 1- 5324)
10.60 WMECO Transition Property Purchase and Sale Agreement dated as of May 17, 2001. (Exhibit 10.61, 2001 NU Form 10-K, File No. 1-5324)
10.61 WMECO Transition Property Servicing Agreement dated as of May 17, 2001. (Exhibit 10.62, 2001 NU Form 10-K, File No. 1-5324)
12 Ratio of Earnings to Fixed Charges
13 Annual Report to Security Holders (Each of the Annual Reports is filed only with the Form 10-K of that respective registrant.)
13.1 Portions of the Annual Report to Shareholders of NU (pages 15 to 64) that have been incorporated by reference into this Form 10-K.
13.2 Annual Report of CL&P.
13.3 Annual Report of WMECO.
13.4 Annual Report of PSNH.
*21 Subsidiaries of the Registrant.
99.1 Certification of Michael G. Morris, Chairman, President and Chief
Executive Officer of Northeast Utilities and John H. Forsgren, Vice
Chairman, Executive Vice President and Chief Financial Officer of
Northeast Utilities, pursuant to 18 U.S.C. Section 1350 as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated
March 21, 2003
#99.2 Certification of Cheryl W. Grise, Chief Executive Officer of CL&P and
John H. Forsgren, Executive Vice President and Chief Financial
Officer of CL&P, pursuant to 18 U.S.C. Section 1350 as adopted
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated
March 21, 2003
@99.3 Certification of Cheryl W. Grise, Chief Executive Officer of PSNH and
John H. Forsgren, Executive Vice President and Chief Financial Officer
of PSNH, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002, dated March 21, 2003
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**99.4 Certification of Cheryl W. Grise, Chief Executive Officer of WMECO and
John H. Forsgren, Executive Vice President and Chief Financial Officer
of WMECO, pursuant to 18 U.S.C. Section 1350 as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002, dated March 21, 2003
EXHIBIT 13.1
ANNUAL REPORT OF NORTHEAST UTILITIES
Management's Discussion and Analysis
FINANCIAL CONDITION
Overview
Consolidated: Northeast Utilities and subsidiaries (NU or the company) reported
2002 earnings of $152.1 million, or $1.18 per share compared with earnings of
$243.5 million, or $1.79 per share in 2001 and a loss of $28.6 million, or $0.20
per share in 2000. In 2002 and 2001, the divestiture of nuclear generation
assets in which NU had a significant ownership interest had a material positive
impact on the company's financial results. All per share amounts are reported on
a fully diluted basis.
During 2002, NU recorded after-tax gains totaling $24.5 million, or $0.19 per share, associated with the sale of its ownership interest in the Seabrook nuclear units (Seabrook) and the elimination of reserves associated with its ownership share of Seabrook assets. During 2001, NU recorded a net after-tax gain of $115.6 million, or $0.85 per share, associated with the sale of its ownership interest in the Millstone nuclear units (Millstone).
During 2002 and 2001, NU recorded various other charges. During 2002, NU recorded an after-tax loss of $11 million, or $0.09 per share, primarily associated with the write-down of investments in NEON Communications, Inc. (NEON) and Acumentrics Corporation (Acumentrics). During 2001, NU recorded an after-tax loss of $22.4 million, or $0.17 per share, as a result of the adoption of Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended, and an after-tax loss of $35.4 million, or $0.26 per share, associated with an agreement with two financial institutions to repurchase NU common shares. Excluding the aforementioned nuclear generation asset divestitures and other charges, NU earned $138.6 million in 2002, compared with $185.7 million in 2001.
NU's revenues for 2002 decreased to $5.2 billion from revenues of $6 billion for 2001. The decrease in revenues is due to lower competitive energy subsidiary revenues and lower regulated subsidiary revenues. The decrease in the competitive energy subsidiaries' revenues is primarily due to lower wholesale marketing revenues from Select Energy, Inc. and subsidiary (Select Energy) full requirements contracts, primarily due to lower energy prices. The decrease in the regulated subsidiaries' revenues is due to lower regulated wholesale and retail revenues. Regulated wholesale revenues decreased primarily due to lower sales associated with purchase-power contracts, lower wholesale sales in New Hampshire and the 2001 revenue associated with the sale of Millstone output. The decrease in regulated retail revenue is primarily related to a rate decrease at Public Service Company of New Hampshire (PSNH), a decrease of the Western Massachusetts Electric Company (WMECO) standard offer rate and a decrease in Yankee Gas Services Company (Yankee Gas) revenues associated with lower gas sales and lower 2002 rates.
NU's earnings per share (EPS) continued to benefit from the company's ongoing share repurchase program. During 2002 NU repurchased 3.7 million shares at an average price of $15.78 in addition to the 14.3 million shares repurchased in 2001 at an average price of $20.34. The company had 127.6 million shares outstanding at December 31, 2002, compared to 130.1 million outstanding shares on December 31, 2001.
In January and February 2003, NU repurchased an additional 1.1 million shares at an average price of $14.44 and can repurchase an additional 6 million shares through June 30, 2003, under an existing resolution approved by the NU Board of Trustees.
The share repurchase program is part of a fundamental restructuring of NU's earnings base that has taken place since 1999. Over the past four years, NU's regulated subsidiaries have sold nearly 5,000 megawatts (MW) of New England electric generation to unaffiliated companies for approximately $2 billion and have securitized more than $2 billion of stranded costs. The proceeds from those sales and securitizations have allowed NU to reduce its combined level of debt and preferred stock by nearly 50 percent since the end of 1997. However, the reduction of NU's generation plant and lower level of regulatory assets also has significantly reduced the earnings power of NU's regulated electric businesses.
NU has partially offset that lower regulated earnings base by acquiring Yankee Energy System, Inc. (Yankee) in 2000, lowering debt and preferred stock levels, repurchasing common shares, making needed investments in its regulated electric distribution and transmission infrastructure, and expanding into the competitive energy business in the Northeast United States. To date, the success of those efforts has been mixed. The retirement of debt has significantly improved NU's consolidated balance sheets, and NU's credit ratings are higher than they have been in at least three decades. Share repurchases have been accretive, and Yankee has been well integrated into NU. NU is in the early stages of its regulated distribution and transmission investment program. As this program progresses, the regulated earnings base will increase over the next several years. However, NU's investment of more than $500 million of equity into its competitive energy businesses has not yet produced the long-term return on investment management requires. A key focus of management in 2003 will be to improve competitive business performance significantly.
Regulated Utilities: Performance among NU's five regulated subsidiaries varied in 2002 with three posting lower results than in 2001 and two posting stronger results. Net income before the payment of preferred dividends totaled $85.6 million at The Connecticut Light and Power Company (CL&P), compared with $109.8 million in 2001. The lower 2002 net income was largely attributable to an after-tax gain of $17.7 million CL&P recorded in 2001 associated with the sale of Millstone. Net income before the payment of preferred dividends at PSNH totaled $62.9 million in 2002, compared with $81.8 million in 2001. 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. Net income at Yankee totaled $15.9 million in 2002, compared with $25.8 million in 2001. The lower 2002 net income was primarily due to the mild first quarter of 2002, usually Yankee Gas' most profitable period of the year, and to the after-tax recognition of approximately $10 million in 2001 related to a favorable property tax settlement.
WMECO recorded net income before the payment of preferred dividends of $37.7 million in 2002, compared with $15 million in 2001. The improved 2002 results were largely due to the recognition of $13 million in investment tax credits and the elimination of $9 million of reserves, both in 2002, as a result of regulatory decisions. North Atlantic Energy Corporation (NAEC) earned $26.3 million in 2002, compared with $4.2 million in 2001. The improved 2002 results were largely due to the elimination of a Seabrook-related reserve during 2002. On November 1, 2002, NAEC sold its 35.98 percent share of Seabrook. Subsequently, a portion of NAEC's equity was repaid to NU. NAEC's operations will not have a material impact on NU's consolidated financial results in 2003 or thereafter.
Competitive Energy Subsidiaries: The decline in NU's 2002 earnings was primarily a result of disappointing results at NU's competitive energy subsidiaries. In 2002, those businesses lost $54.1 million, or $0.42 per share, compared with earnings prior to the charge associated with the adoption of SFAS No. 133 of $5 million, or $0.04 per share, in 2001 and a contribution towards NU's consolidated earnings of $13.6 million, or $0.10 per share, in 2000. Select Energy's wholesale marketing business was essentially break-even in 2002, following a loss of approximately $13 million in 2001. Those results include the performance of Northeast Generation Company (NGC) and Holyoke Water Power Company (HWP). Select Energy's retail marketing business experienced weaker performance during 2002, with losses of approximately $28 million, compared with 2001 losses of approximately $8 million, excluding the loss associated with the adoption of SFAS No. 133, as amended. Select Energy's trading business also lost approximately $24 million in 2002 compared with earnings of $19 million in 2001. NU's energy services businesses, including Northeast Generation Services Company (NGS) and Select Energy Services, Inc. (SESI), were essentially break-even in 2002. SESI earned $3 million while NGS lost $3.2 million. In 2001, SESI earned $2.4 million and NGS earned $4.6 million. In 2002, NU Enterprises, Inc. (NUEI) and the energy services subsidiaries of Yankee lost approximately $2 million.
Future Outlook
Consolidated: NU estimates that it will earn between $1.10 per share and $1.30
per share in 2003.
Regulated Utilities: The earnings range of between $1.10 and $1.30 per share includes earnings of between $1.05 per share and $1.15 per share at the regulated businesses, compared with aggregate earnings of $1.72 per share at the regulated businesses in 2002. The primary reason for the earnings reduction at the regulated businesses in 2003 is the sale of Seabrook in 2002 and the resulting elimination of operating earnings at NAEC in 2003, the recording of $13 million of tax credits at WMECO in 2002, and a significant reduction in the projected level of pension income in 2003 and forward.
NU recorded $73.4 million of pre-tax pension income in 2002, approximately 30 percent of which was capitalized and reflected as a reduction to the cost of capital expenditures with the remainder being recognized in the consolidated statements of income as reductions to operating expenses. In 2003, as a result of continued poor performance in the equity markets, NU is projecting the total level of pre-tax pension income to decline to approximately $31 million, with a similar percentage being reflected as a reduction to the cost of capital expenditures. Pension income is annually adjusted during the second quarter based upon updated actuarial valuations, and the 2003 estimate may be modified.
The lower pre-tax pension income will be partially offset by a reduction in workforce at NU. In 2002, NU reduced its workforce by approximately 200 employees and commenced an effort to reduce the number of non-employee vendors it currently employs by approximately 50 percent. Together these efforts are expected to reduce costs by approximately $20 million annually on a pre-tax basis. Management believes that most of the cost of the workforce reduction, which was approximately $13 million, is recoverable from ratepayers as a stranded cost related to industry restructuring.
Competitive Energy Subsidiaries: NU projects that the financial performance of its competitive energy subsidiaries will improve in 2003 and that those subsidiaries will earn between $0.15 per share and $0.25 per share. NU believes that its wholesale marketing business, including NGC and HWP, will be profitable. Management also projects that its retail marketing business will break-even and its trading business will be modestly profitable in 2003, and that financial performance at its energy services businesses, NGS and SESI, will also be profitable in the aggregate.
NU also projects that parent company expenses, primarily related to three long-term debt issuances, will cost the company approximately $0.10 per share in 2003.
Liquidity
Consolidated: The year 2002 represented the final year of a four-year process of
selling most of the regulated generation assets owned by NU. The sale of those
assets and the sale of more than $2.1 billion of rate reduction bonds and
certificates to securitize stranded costs resulted in the inflow of more than
$4.3 billion over a 40-month period ending with the sale of NU's 40.04 percent
ownership of Seabrook, 35.98 percent by NAEC and 4.06 percent by CL&P, on
November 1, 2002. NU received approximately $367 million of total cash proceeds
from the sale of Seabrook and another approximately $17 million from Baycorp
Holdings, Ltd. as a result of the sale of its 15 percent 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
will be used to pay approximately $95 million in taxes. The remaining proceeds
received by NAEC were refunded to PSNH through the Seabrook Power Contracts. As
a result, NU remained at a high level of liquidity during 2002, despite rising
capital investments in its regulated electric and gas segments. At December 31,
2002, NU had $2.4 billion of long-term and short-term debt and capital lease
obligations outstanding, excluding rate reduction bonds, compared with $2.7
billion of debt and capital lease obligations outstanding at December 31, 2001.
Aside from the rate reduction bonds outstanding, NU has a very modest level of sinking fund payments and debt maturities due between 2003 and 2011, averaging approximately $38 million annually and totaling $56.9 million in 2003. Most of the debt that must be repaid during that period of time was issued by NU parent, NGC and Yankee Gas. No CL&P, PSNH or WMECO debt issues mature during that nine-year period. Because of NU's current high level of liquidity and modest level of debt maturities in the coming years, management does not expect to experience the severe credit and refinancing issues that many other energy industry companies have faced in the past two years.
NU's net cash flows provided by operating activities increased to $612.6 million in 2002, compared with $328.6 million in 2001 and $599.8 million in 2000. Cash flows provided by operating activities increased primarily 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 because the taxes related to the sale of Seabrook will not be paid until March of 2003. The decrease in cash flows provided by operating activities in 2001 related primarily to increases in receivables and unbilled revenues associated with the sales growth of NU's competitive energy subsidiaries.
There was a lower level of investing and financing activities in 2002 as compared to 2001, primarily due to the issuance of long-term debt, issuance of rate reduction bonds and certificates and the buyout and buydown of independent power producer contracts in 2001. The level of common dividends totaled $67.8 million in 2002, compared with $60.9 million in 2001 and $57.4 million in 2000. The increase resulted from NU paying a $0.125 per share quarterly common dividend in the first two quarters of 2002 and a $0.1375 per share quarterly dividend in the last two quarters of 2002. The level of quarterly common dividend payments during 2001 was $0.10 per share during the first two quarters of 2001 and $0.125 during the last two quarters of 2001. The increase in the common dividend was partially offset by a decrease in outstanding shares.
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 the dividends are declared. On January 13, 2003, the NU Board of Trustees approved the payment of a $0.1375 per share dividend payable on March 31, 2003, to shareholders of record at March 1, 2003.
Despite the increase in the common dividend, NU parent ended the year with a high level of liquidity, all of which was loaned to subsidiaries through the NU Money Pool or through direct loans. The parent company's cash levels increased as a result of continued return of equity capital from its regulated subsidiaries, as well as their payment of common dividends to the parent. In 2002, CL&P paid $60.1 million of dividends to NU parent and returned another $100 million of equity capital through share repurchases. PSNH paid $45 million of dividends in 2002, in addition to the return of another $37 million of equity capital. As a result of the Seabrook sale, NAEC paid $5 million of dividends and returned another $35 million of equity capital to NU. WMECO paid $16 million of dividends and returned $14 million of equity capital to NU. The parent company also received another $10 million in dividends from NGC through its parent company, NUEI along with $3 million directly from NUEI. The parent company's liquidity is reinforced by no debt maturities, a modest common dividend, and minimal sinking fund payments of $23 million in 2003 and $24 million in 2004. Equity capital transactions between NU parent and its subsidiaries are eliminated in consolidation.
Regulated Utilities: NU's regulated utilities had a modest level of financings in 2002. In January 2002, PSNH issued an additional $50 million in rate reduction bonds and used the proceeds to repay short-term debt that was incurred to buyout a purchased-power contract in December 2001. In April 2002, NU issued $263 million of 7.25 percent senior unsecured notes due on April 1, 2012. Proceeds from the refinancing were used to redeem a similar amount of variable rate notes that were issued on February 28, 2001 related to the Yankee merger.
In November 2002, the regulated utilities renewed their $300 million credit line, under terms similar to the arrangement that expired in November 2002. A previous credit line had provided up to $350 million for the regulated companies. There were $7 million in borrowings on this credit line at December 31, 2002.
In addition to its revolving credit arrangement, CL&P can access up to $100 million by selling certain of its accounts receivable. At December 31, 2002, CL&P had $40 million outstanding under this arrangement. The current accounts receivable arrangement is expected to be renewed in July 2003.
Rate reduction bonds are included on the consolidated balance sheets of NU, CL&P, PSNH and WMECO, even though the debt is nonrecourse to these companies. At December 31, 2002, these companies had a total of $1.9 billion in rate reduction bonds outstanding, compared with $2 billion outstanding at December 31, 2001. All outstanding rate reduction bonds of CL&P are scheduled to amortize by December 30, 2010, with those of PSNH scheduled to fully amortize by May 1, 2013, and those of WMECO scheduled to fully amortize by June 1, 2013. Interest on the rate reduction bonds totaled $115.8 million in 2002, compared with $87.6 million in 2001. Amortization of the rate reduction bonds totaled $169 million in 2002, compared with $100 million in 2001. CL&P, PSNH and WMECO fully recovered the amortization and interest payments from customers in 2002 and the bonds had no impact on net income. Moreover, because the debt is nonrecourse to these companies, the three rating agencies that rate their debt and preferred stock securities do not include the revenues, expenses, or outstanding securities related to the rate reduction bonds in establishing the credit ratings of NU or its subsidiaries.
CL&P and Yankee Gas have embarked upon significant upgrade programs within their service territories. Over the past five years, CL&P has increased its annual level of investment in electric utility plant by approximately 50 percent. Much of the additional investment has been devoted to improving the reliability of CL&P's electric distribution system. Over the next several years, CL&P has proposed a significant expansion of its 345,000 volt electric transmission system into southwestern Connecticut at a cost that is likely to exceed $500 million. If Connecticut regulators approve the expansion, CL&P's construction expenditures are projected to exceed $350 million annually from 2004 through 2007. Such a program would exceed CL&P's projections for internally generated operating cash flows, and therefore, CL&P expects to access the capital markets for financing during this period. In 2003, CL&P is expected to generate enough cash internally to fund most, if not all, of its capital needs.
Yankee Gas, pursuant to the recommendations of the Connecticut Department of Public Utility Control (DPUC) when it approved NU's acquisition of Yankee, has embarked upon a significant expansion within its service territory. Yankee has not paid a common dividend since it merged with NU in 2000, using its internally generated cash to fund its expansion program. This expansion will likely require Yankee Gas to issue new debt. Although Yankee Gas' debt is not currently rated, management believes Yankee Gas would be able to attract capital at a reasonable cost due to its regulated activities and strong balance sheet. At December 31, 2002, Yankee Gas had $215.4 million of common equity, excluding common equity related to goodwill, and $151.4 million of long-term debt.
PSNH funded its capital expenditures through internally generated cash flows and through proceeds returned from NAEC as a result of the sale of Seabrook. PSNH returned $37 million of equity capital to NU in 2002. PSNH's capital expenditures are expected to total $116.3 million in 2003 and remain largely funded through internally generated cash flows.
WMECO has applied to the Massachusetts Department of Telecommunications and Energy (DTE) to refinance approximately $100 million of short-term and spent nuclear fuel obligations. A decision is expected in the first half of 2003. CL&P also is considering refinancing approximately $200 million of spent nuclear fuel obligations in 2003.
Competitive Energy Subsidiaries: In November 2002, NU renewed its $350 million credit line for the competitive energy subsidiaries, under terms similar to the arrangement that expired in November 2002. A previous credit line had provided up to $300 million for the competitive energy subsidiaries. There were $49 million in borrowings on this credit line at December 31, 2002, and Select Energy had approximately $6.7 million in letters of credit outstanding to provide credit assurance for wholesale power transactions.
NU's competitive businesses have minimal capital expenditures. NGC's capital expenditures totaled $16.4 million while HWP's totaled $1 million and other capital expenditures totaled $5.8 million in 2002. In July 2002, NU's competitive energy subsidiaries acquired certain assets and assumed certain liabilities of Woods Electrical Co., Inc. (Woods Electrical), an electrical services company, and Woods Network Services, Inc. (Woods Network), a network products and services company, for an aggregate adjusted purchase price of $16.3 million (collectively Woods). NU made no other business acquisitions in 2002.
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' October 13, 1999 Agreement and Plan of Merger, as amended and restated as of January 11, 2000 (the Merger Agreement). On March 12, 2001, NU filed suit against Con Edison in the United States District Court for the Southern District of New York (the District Court) seeking damages in excess of $1 billion arising from Con Edison's breach of the Merger Agreement.
On May 11, 2001, Con Edison filed an amended complaint seeking damages for breach of contract, fraudulent inducement and negligent misrepresentation. Con Edison has claimed that it is entitled to recover a portion of the merger synergy savings estimated to have a net present value of 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 have completed discovery in the litigation. Motions for summary judgment were argued before the District Court on February 4, 2003. 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.
For further information regarding this litigation, see NU's 2002 report on Form 10-K, Item 3, "Legal Proceedings."
Implementation of Standard Market Design On March 1, 2003, the New England independent system operator (ISO) implemented a new Standard Market Design (SMD). As part of this effort, locational marginal pricing (LMP) will be utilized to assign value and causation to transmission congestion. Transmission congestion costs will be assigned to the load zone in which the congestion occurs. Those costs are now spread across virtually all New England electric customers. In addition, the implementation of SMD will impact wholesale energy contracts with respect to the energy delivery points contained in those contracts.
Regulated Utilities: Connecticut has been designated a single load zone. Due to the transmission constraints and inadequate generation, Connecticut could experience significant additional congestion costs under SMD. The New England ISO estimates that the costs of transmission congestion for 2003 in New England under SMD will range between $50 million and $300 million. The New England ISO estimates that the majority of this congestion and its costs will be in Connecticut, where approximately 80 percent are expected to be paid by CL&P beginning on March 1, 2003. CL&P believes that under the terms of its standard offer service contracts with its standard offer suppliers these costs are its responsibility. The contracts with the standard offer suppliers expire on December 31, 2003. In addition, the determination of the energy delivery points associated with the standard offer service contracts under SMD could also produce significant costs for CL&P that management cannot determine at this time.
Another factor affecting the level of congestion costs is the designation of certain generating units by the New England ISO as units needed for system reliability. Some of the companies owning these units have applied to the Federal Energy Regulatory Commission (FERC) for "reliability must run" (RMR) treatment. RMR treatment allows these units to receive cost of service-based payments that recognize their reliability value. Prior to March 1, 2003, all RMR costs were spread across New England with all utilities being billed by the New England ISO based upon their share of New England's load. NU's regulated electric utilities were responsible for approximately 25 percent of these costs. Effective with the March 1, 2003 implementation of SMD by the New England ISO, RMR costs will be allocated to the load zone in which the RMR unit is located. At present, the only load zone that will experience a cost increase in which a NU regulated electric company operates is Connecticut. With respect to the Connecticut load zone, there are two generating units operating under a RMR contract with an additional contract pending before FERC. These contracts are for one year terms, and one contract contains an extension option. On a combined basis, these two RMR contracts will result in an annual cost of approximately $45 million to the Connecticut load zone. CL&P accounts for approximately 80 percent of the Connecticut load zone, and would be responsible for approximately $36 million of this cost. In the near future, it is probable that there will be significant new requests for RMR treatment in Connecticut which, if approved by FERC, would add significant additional costs to the total cost of energy in Connecticut. However, generating units operating under RMR contracts could potentially mitigate the overall level of congestion costs.
These unavoidable congestion and RMR costs are part of the prudent cost of providing regulated electric service in Connecticut. A DPUC regulatory proceeding is expected to be initiated soon to determine the appropriate recovery mechanism for these costs. If these costs are incurred before the final recovery mechanism is established by the DPUC, CL&P expects to record a regulatory asset for those costs incurred. See Critical Accounting Policies and Estimates - Regulatory Accounting and Assets included in management's discussion and analysis for further information.
Competitive Energy Subsidiaries: The implementation of SMD in New England will create challenges and opportunities for Select Energy. The impact of SMD on its wholesale marketing business could be significant. The determination of the energy delivery points in many wholesale marketing contracts and the location of sources of supply could have a significant effect. As more information regarding the timing and impact of SMD becomes available, there could be additional adverse effects that management cannot determine at this time.
Competitive Energy Subsidiaries
Subsidiaries: NU's competitive energy subsidiaries include HWP and NUEI, which
is the parent company of Select Energy and its subsidiary Select Energy New
York, Inc. (SENY), NGC, SESI, and NGS. Select Energy engages in wholesale and
retail energy marketing activities and energy trading activities.
NU's competitive energy subsidiaries own 1,438 MW of generation capacity, consisting of 1,291 MW at NGC and 147 MW at HWP, which are used to support Select Energy's wholesale marketing business.
SESI performs energy management services for large industrial, commercial and institutional facilities, including the United States Department of Defense, and engages in energy related construction services. NGS operates and maintains NGC's and HWP's generation assets and provides third-party electrical, mechanical, and engineering contracting services.
Outlook: NU is taking a number of steps to return the competitive energy businesses to profitability in 2003 from the loss of $54.1 million in 2002. NU has acquired additional energy services businesses and expects that after essentially break-even earnings in 2002, they will be profitable in 2003.
Select Energy engages in energy trading activities primarily for price discovery and risk management purposes. Select Energy has considerably reduced its speculative trading activities and the amount of capital at risk in the trading operation to a daily average of approximately $0.4 million from up to $6 million in early 2002, and projects that the after-tax loss of approximately $24 million in 2002 will turn into modest profits in 2003. The 2002 results were negatively impacted by an increase in natural gas prices during March and April 2002.
Significant contributing factors to the 2002 loss in the retail marketing business were unprofitable energy contracts and unusually mild weather which significantly reduced natural gas sales. Many of the unprofitable contracts expired in 2002. Select Energy plans to size the retail marketing organization to fit the expected level of business and expects to better manage volumetric risk, particularly in the winter heating months. As a result, management expects to break-even in the retail marketing business in 2003, compared with a loss of approximately $28 million in 2002. To achieve this result in 2003, Select Energy must obtain new retail business and successfully manage its portfolio of retail contracts.
In the wholesale marketing business, Select Energy, including NGC and HWP, expects to be profitable in 2003, compared with essentially break-even performance in 2002. Select Energy expects significant improvement to come from improved results on its contract with CL&P, improved management of power supply contracts, and a return to normal river conditions around NGC's conventional hydroelectric plants. Select Energy expects the CL&P contract to be between breakeven and a loss of $10 million in 2003 compared to a loss of $47 million in 2002. Near drought conditions in New England, particularly in the first three quarters of 2002, lowered pre-tax earnings by approximately $6 million in 2002. This earnings projection also assumes that Select Energy will be successful in securing a significant amount of new business at acceptable margins and managing its wholesale marketing portfolio. NGC owns 1,291 MW of primarily hydroelectric generation capacity in Massachusetts and Connecticut and earned $30.4 million in 2002 and $42.3 million in 2001. HWP owns a 147 megawatt coal-fired plant in Holyoke, Massachusetts and lost $0.9 million in 2002 following earnings of $4.4 million in 2001. Select Energy has wholesale contracts with NGC and HWP to purchase all of the output of their generation assets. Accordingly, the results of these companies are included in Select Energy's wholesale marketing business.
CL&P's standard offer service purchases from Select Energy represented approximately $501 million of total competitive energy subsidiaries' revenues for 2002, compared with approximately $497 million for 2001. Other transactions between CL&P and Select Energy amounted to approximately $130 million in revenues for Select Energy for 2002, compared with approximately $151 million in 2001. These amounts are eliminated in consolidation.
Additionally, WMECO's purchases from Select Energy represented approximately $14 million and $4 million of total competitive energy subsidiaries' revenues in 2002 and 2001, respectively.
In 2002, the competitive energy subsidiaries 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 remaining 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's operating expenses decreased by approximately $5.1 million in 2002 and are expected to decrease by approximately $9.4 million for 2003.
Competitive Energy Subsidiaries' Market and Other Risks Overview: NU's competitive energy subsidiaries are exposed to certain market risks inherent in their business activities. Certain competitive energy subsidiaries, primarily Select Energy, enter into contracts of varying lengths of time to buy and sell energy commodities, including electricity, natural gas and oil. Market risk represents the risk of loss that may impact Select Energy's financial results due to adverse changes in commodity market prices.
Risk management within the competitive energy subsidiaries, including Select Energy, is organized by management to address the market, credit and operational exposures arising from the company's primary business segments including wholesale marketing, retail marketing and trading. The framework and degree to which these risks are managed and controlled is consistent with the limitations imposed by NU's Board of Trustees as established and communicated in NU's overall risk management policies and procedures. As a means to monitor and control compliance with these policies and procedures, NU has formed a Risk Oversight Council (ROC) to monitor competitive energy risk management processes independently from the businesses that create or manage these risks. The ROC ensures that the polices 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.
Wholesale and Retail Marketing: A significant portion of Select Energy's wholesale marketing business is providing energy to full requirements customers, primarily regulated distribution companies. Under full requirements contract terms, Select Energy is required to provide the total energy requirement 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 is focused on managing the volume and price risks of full requirements contracts. These risks include significant fluctuations in 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 hedge these risks. While not classified as hedges for accounting purposes, 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. As discussed above, Select Energy's 2002 results were negatively impacted by weather patterns that resulted in contracted supply exceeding demand in the warmer than expected winter and purchasing supply during certain summer months at prices higher than those forecasted.
The competitive energy subsidiaries manage their portfolio of wholesale and retail marketing contracts and assets to maximize value while maintaining an acceptable level of risk. The lengths of contracts to buy and sell energy vary in duration from daily/hourly to several years. At any point in time, the wholesale and retail marketing portfolio may be long (purchases exceed sales) or short (sales exceed purchases). Portfolio and risk management disciplines with established policies and procedures are used to manage exposures to market risks. At forward market prices in effect at December 31, 2002, the wholesale marketing portfolio, which includes the CL&P standard offer service contract 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 is significant volatility in the energy commodities markets that will impact this position between now and when the contracts are settled. Portfolio volatility reflects fluctuations in value due to changes in energy prices in the region, new transactions entered into during the period and positions settling during the period. 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. The gross margin realized could be at a level that is not sufficient to cover Select Energy's other operating costs, including the cost of corporate overhead.
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 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 retail supply 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 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, 2002, Select Energy had hedging derivative assets of $22.8 million and hedging derivative liabilities of $2 million. At December 31, 2001, Select Energy had hedging derivative assets of $2.9 million and hedging derivative liabilities of $60.7 million. The change from hedging derivative liabilities at December 31, 2001 to hedging derivative assets at December 31, 2002 resulted primarily from increased natural gas prices and the maturity or termination of hedge instruments existing at December 31, 2001.
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 impact earnings. For information regarding changes in accounting for energy trading transactions, see Note 1C, "New Accounting Standards," to the consolidated financial statements.
At December 31, 2002, Select Energy had trading derivative assets of $102.9 million and trading derivative liabilities of $61.9 million on a counterparty-by-counterparty basis, for a net positive position of $41 million on the entire trading portfolio. At December 31, 2001, Select Energy had trading derivative assets of $147.2 million and trading derivative liabilities of $90.8 million on a counterparty-by-counterparty basis, for a net positive position of $56.4 million on the entire trading portfolio. These amounts are combined with other derivatives and are included in derivative assets and derivative liabilities on the accompanying consolidated balance sheets. Information regarding the other derivatives is included in Note 3, "Derivative Instruments, Market Risk and Risk Management," to the consolidated financial statements.
There can be no assurances that Select Energy will actually realize cash corresponding to the present positive net fair value of its trading portfolio. Numerous factors could either positively or negatively affect the realization in cash of the net fair value amount. 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 trading day. Controls are in place segregating responsibilities between 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, 2002 and 2001 below. 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 quotes; and 3) prices based on models or other valuation methods primarily include forwards and options and other transactions for which specific quotes are not available. These transactions are modeled using recognized option pricing models. The option component of a forward electricity purchase contract had a fair value of $4.5 million at December 31, 2002, and is the only amount included in this method of determining fair value. The fair value of this contract component at December 31, 2001 was not material. Broker quotes for electricity are available through the year 2005, and models are generally used for the years 2006 and thereafter. Select Energy has procured sourcing for the contracts with maturities in excess of four years. Accordingly, the value of these contracts and the related power supply contracts do not need to be determined with a model. Broker quotes for natural gas are available through 2013. The decrease in the number of counterparties participating in the market for long-term energy contracts continues to impact Select Energy's ability to determine the estimated fair value of its long-term energy contracts.
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 based on models or other methods for longer-term contracts are less certain. Accordingly, there is a risk that contracts will not be realized at the amounts recorded.
As of and for the years ended December 31, 2002 and 2001, respectively, 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.
(Millions of Dollars) Fair Value of Trading Contracts at December 31, 2002
--------------------------------------------------------------------------------
Maturity Maturity Maturity
Less Than of One to in Excess of Total
Sources of Fair Value One Year Four Years Four Years Fair Value
--------------------------------------------------------------------------------
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
--------------------------------------------------------------------------------
Totals $ 1.6 $24.8 $14.6 $41.0
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(Millions of Dollars) Fair Value of Trading Contracts at December 31, 2001
--------------------------------------------------------------------------------
Maturity Maturity Maturity
Less Than of One to in Excess of Total
Sources of Fair Value One Year Four Years Four Years Fair Value
--------------------------------------------------------------------------------
Prices actively quoted $ 6.5 $ 6.8 $ -- $13.3
Prices provided by
external sources 6.5 15.8 20.8 43.1
Prices based on models
or other valuation methods -- -- -- --
--------------------------------------------------------------------------------
Totals $13.0 $22.6 $ 20.8 $56.4
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As indicated in the tables, the fair value of energy trading contracts decreased $15.4 million from $56.4 million at December 31, 2001 to $41 million at December 31, 2002. This decrease, combined with the realized losses on positions taken and closed in 2002, is included in Select Energy's gross margin and, after it is tax affected, is reflected in the $24 million that Select Energy's trading business lost in 2002.
Years Ended December 31,
2002 2001
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(Millions of Dollars) Total Fair Value
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Fair value of trading contracts
outstanding at the beginning of the period $56.4 $13.8
Acquisition of SENY -- 10.9
Contracts realized or otherwise settled
during the period (4.0) (9.4)
Fair value of new contracts when entered
into during the period 13.7 58.6
Changes in fair values attributable to changes
in valuation techniques and assumptions (39.9) --
Changes in fair value of contracts 14.8 (17.5)
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Fair value of trading contracts outstanding
at the end of the period $41.0 $56.4
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During the first quarter of 2002, Select Energy terminated certain long-term energy contracts. Coincident with these contract terminations, new contracts were entered into with different terms and conditions. Select Energy also entered into several new contracts with existing counterparties. These new energy trading contracts are trading derivatives, and collectively they had a positive fair value of $13.7 million when entered into. In 2001, Select Energy entered into certain contracts with a fair value of $58.6 million when entered into.
Effective October 1, 2002, Select Energy adopted a consensus reached by the Emerging Issues Task Force (EITF) on October 25, 2002 in Issue No. 02-3, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities." Adopting this consensus required management to conduct a thorough review of contracts in the trading portfolio to determine if there were any contracts in the trading portfolio that were not derivatives, as defined. Management determined that there were no nonderivative contracts in the energy trading portfolio, and as such, there was no cumulative effect of an accounting change as of October 1, 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 business, 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 will be 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 SENY at acquisition that were determined to be held for nontrading 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 were revalued during the year based on the availability of market information, which added $6 million to the value of the trading portfolio.
Late in the fourth quarter of 2002, Select Energy began to receive reliable market information concerning the impact of LMP in New England with the implementation of SMD, which is currently scheduled for March 1, 2003. Select Energy began to use this market information in its valuation of contracts in the trading portfolio. The impact of using this information was to reduce the portfolio value by $10.3 million, which is reflected as a negative amount in changes in fair value of contracts.
Nontrading: Nontrading derivative contracts are for delivery of energy related to the competitive energy subsidiaries' retail and wholesale marketing activities. At December 31, 2002, Select Energy had nontrading derivative assets of $2.9 million and no nontrading derivative liabilities. At December 31, 2001, Select Energy had no nontrading derivative assets or liabilities.
Changing Market: The breadth and depth of the market for energy trading and marketing products in Select Energy's market has been 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, and participants are more often unable to meet Select Energy's credit standards without providing cash or letter of credit support. Select Energy is being adversely affected by these factors, and there could be a continuing adverse impact on Select Energy's business prospects.
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 are occurring within transmission regions. For example, the impact of the implementation of SMD on Select Energy's existing positions resulted in a decrease of $10.3 million in the fair value of Select Energy's trading portfolio. The impact of SMD on its wholesale marketing business is potentially more significant. The determination of the energy delivery points in many wholesale marketing contracts and the location of generation assets included in the wholesale marketing business could be significantly affected. As more information regarding the timing and impact of SMD becomes available, there could be additional adverse effects that management cannot determine at this time.
Counterparty Credit: Counterparty credit risk relates to the risk of loss that Select Energy would incur as a result 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 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 trading activities. 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, 2002, approximately 83 percent of Select Energy's counterparty credit exposure to wholesale marketing and trading counterparties is cash collateralized or rated BBB- or better. In excess of half of the remaining credit exposure is to unrated municipalities.
At December 31, 2002, two positions with counterparties collectively represented approximately 40 percent of the $102.9 million trading derivative assets. All other counterparties represented less than 10 percent of the trading derivative assets. Select Energy manages the credit risk of its trading portfolio in accordance with established credit risk management policies and procedures.
Select Energy 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 $140 million of collateral or letters of credit to various unaffiliated counterparties and approximately $80 million to several ISOs and unaffiliated local distribution companies, which NU, under present circumstances, would be able to provide from available sources. NU's ratings are currently stable, and management does not believe that at this time there is a significant risk of a ratings downgrade to sub-investment grade levels.
For further information regarding Select Energy's activities and risks see Note 3, "Derivative Instruments, Market Risk and Risk Management," and Note 11, "Accumulated Other Comprehensive Income/(Loss)," to the consolidated financial statements.
Business Development and Capital Expenditures Consolidated: NU anticipates that it will continue to increase its level of capital expenditures at its regulated subsidiaries to meet customers' increasing needs for additional and more reliable energy supplies. Investments in regulated utility plant, excluding nuclear fuel, totaled $468.8 million in 2002, compared with $428.3 million in 2001 and $345.6 million in 2000. NU expects that level to reach $640.2 million in 2003 and may be as high as $650 million in 2004, if CL&P's plans to expand its 345,000 volt transmission system are approved.
Regulated Utilities: CL&P's capital expenditures, excluding nuclear fuel, totaled $242.3 million in 2002, compared with $237.4 million in 2001 and $208.2 million in 2000. CL&P expects capital expenditures to increase to $326.9 million in 2003. CL&P spent $141.2 million related to its overhead and underground electric distribution system in 2002 and expects to spend a similar amount in 2003. CL&P spent $35.6 million to upgrade its transmission system in 2002, and expects its transmission capital expenditures to increase to $95 million in 2003, if its current construction plans receive regulatory approval. CL&P also spent $20 million on new meters and customer services, and $17 million on substations in 2002.
In 2001, CL&P announced plans for three transmission projects. In September 2002, the Connecticut Siting Council (CSC) approved the first project, a plan to replace an undersea electric transmission line between Norwalk, Connecticut and Northport - Long Island, New York, at an estimated cost of $80 million. CL&P owns 50 percent of the line with the Long Island Power Authority also owning 50 percent. The project still requires federal and New York state approvals. Given the approval process and the uncertainty created by the recent damage to the existing transmission line, the expected in-service date is currently under evaluation. At December 31, 2002, CL&P has capitalized approximately $4.8 million related to this project.
In early 2003, the CSC completed hearings on the second project, a $135 million proposal to build a new 345,000 volt transmission line between Norwalk, Connecticut and Bethel, Connecticut. A decision is expected in April 2003. The current cost estimate is based on building the entire transmission line aboveground. Alternative proposals have been made to build all or part of the line underground, which likely would result in significantly higher construction costs. CL&P hopes to have the new transmission line operational by the summer of 2005. At December 31, 2002, CL&P has capitalized approximately $8.8 million related to this project.
By mid-2003, CL&P expects to apply to the CSC for approval of a third project, the installation of another 345,000 volt transmission line between Norwalk, Connecticut and Middletown, Connecticut. Estimated construction costs of this overhead line are approximately $500 million. CL&P will jointly construct this project with United Illuminating with CL&P owning 80 percent or approximately $400 million of the project. At December 31, 2002, CL&P has capitalized approximately $2.4 million related to 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.
Yankee Gas has also proposed expansion of its gas distribution system in Connecticut. Yankee Gas' capital expenditures totaled $70.8 million in 2002, compared with $47.8 million in 2001 and $21.6 million in 2000. Yankee Gas expects capital expenditures to total $72.9 million in 2003 as it continues to expand its distribution system and expects to begin work on a liquefied natural gas storage facility proposed in Waterbury, Connecticut.
The expectation that PSNH will retain its generation assets, at least through 2004, will result in higher near-term capital expenditures at PSNH. PSNH's capital expenditures, excluding nuclear fuel, totaled $109.8 million in 2002, compared with $92.6 million in 2001 and $69.5 million in 2000. Capital expenditures are expected to total $116.3 million in 2003, as PSNH continues to upgrade and expand its distribution and transmission system and upgrade its generation plants.
On December 5, 2002, PSNH announced an agreement to acquire the franchise and electric system of Connecticut Valley Electric Company, Inc. (CVEC), a subsidiary of Central Vermont Public Service Corporation (CVPS) that serves approximately 10,000 customers in western New Hampshire. Under the agreement, PSNH will pay CVPS approximately $9 million for its assets and an additional $21 million to terminate a wholesale power contract between CVPS and CVEC. Customers of CVEC will become customers of PSNH, whose residential rates are now approximately 20 percent lower than those of CVEC. PSNH will be allowed to recover the $21 million payment with a return consistent with Part 3 stranded cost treatment under the "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. The sale agreement is supported by the New Hampshire Governor's Office, New Hampshire Public Utilities Commission (NHPUC) staff, the state Office of Consumer Advocate, the City of Claremont, and New Hampshire Legal Assistance. The FERC and the NHPUC must approve the sale, which is expected to become effective on January 1, 2004.
As a result of a lower projected growth rate and an adequately sized transmission system to meet near term needs, WMECO does not forecast significant changes in its construction program. WMECO's capital expenditures, excluding nuclear fuel, totaled $23.4 million in 2002, compared with $30.9 million in 2001 and $27.3 million in 2000. WMECO's capital expenditures are expected to total $28.1 million in 2003.
Competitive Energy Subsidiaries: Capital expenditures at NU's competitive generation subsidiaries, NGC and HWP, are expected to be modest in 2003, with $12.1 million at NGC and $3.8 million at HWP. In 2002, NGC's and HWP's capital expenditures totaled $16.4 million and $1 million, respectively.
In recent years, NU has considered several additional investments in the competitive energy business. In 2001, NU proposed constructing a completely new direct current cable between Norwalk, Connecticut and Long Island, New York to serve the merchant power market. However, because of growing financial distress in the merchant power industry, NU concluded that such a project was not feasible at the time and withdrew its proposal from the FERC in November 2002. NU also has considered investing in additional peaking or intermediate generation in the New York and the Mid-Atlantic states. However, NU concluded in 2002 that potential returns on such investments were not adequate given the likely purchase prices.
NU continues to examine niche acquisitions in the energy services business. In 2002, NU acquired Woods Electrical and Woods Network for an aggregate adjusted purchase price of $16.3 million. In 2001, NU acquired the E.S. Boulos Company (Boulos), a high-voltage electrical contractor based in Maine, and Niagara Mohawk Energy Marketing, Inc., an energy marketing company based in New York that was subsequently renamed SENY. Both Boulos and SENY were profitable, with Boulos earning $2.7 million and SENY earning $17.2 million for the year ended December 31, 2002. Since acquisition on July 1, 2002, Woods earned $0.1 million.
Regional Transmission Organization
The FERC has required all transmission owning utilities to voluntarily start
forming RTOs or to state why this process has not begun.
NU has been discussing with the other transmission owners in New England the potential to form an Independent Transmission Company (ITC). If formed, the ITC would be a for-profit entity and would perform certain transmission functions required by the FERC, including tariff control, system planning and system operations. The remaining functions required by the FERC would be performed by the ISO regarding the energy market and short-term reliability. Together, the ITC, if formed, and ISO would form the FERC-desired RTO.
In January 2002, the New York and New England ISOs announced their intention to form an RTO. On November 22, 2002, the two ISOs withdrew their joint petition to FERC. The New England ISO intends to make an RTO filing with the transmission owners in New England in 2003.
The agreements needed to create the RTO and to define the working relationships among the ISO and the transmission owners should be created in 2003, and will allow the RTO to begin operation shortly thereafter. The agreements are expected to include provisions for the future creation of one or more ITCs within the RTO. The creation of the RTO will require a FERC rate case, and the impact on NU's return on equity as a result of this rate case cannot be estimated at this time. At December 31, 2002, NU capitalized $1.3 million related to RTO formation activities.
Merchant Energy Company Counterparty Exposures Certain subsidiaries of NU, including CL&P, Yankee Gas, Select Energy, and NGS, have entered into various transactions with subsidiaries of NRG Energy, Inc. (NRG). NRG's credit rating has been downgraded to below investment grade by all three major rating agencies, and NRG is presently in default on debt service payments. Management does not expect that the resolution of the transactions with NRG will have a material adverse effect on NU's consolidated financial condition or results of operations. Additionally, NU does not have a significant level of exposure to other merchant energy companies. For further information regarding these transactions, see NU's 2002 report on Form 10-K, Item 1, "Business."
Restructuring and Rate Matters
Connecticut - CL&P: Since retail competition began in Connecticut in 2000, an
extremely small number of customers have opted to choose an alternate supplier.
At December 31, 2002, virtually all of CL&P's customers were procuring their
electricity through CL&P's standard offer service. In 2003, Select Energy will
continue to supply 50 percent of CL&P's standard offer supply service with NRG
Power Marketing, Inc. (NRG-PM), a subsidiary of NRG, contracted to supply 45
percent and a subsidiary of Duke Energy, Inc. contracted to supply the remaining
5 percent of service. On November 18, 2001, at NRG-PM's request, CL&P filed an
application with the DPUC to raise the standard offer rate from an average of
$0.0495 per kilowatt-hour (kWh) to $0.0595 per kWh to help promote competition
in advance of the January 1, 2004 termination of the standard offer period and
to provide financial relief to standard offer suppliers. In December 2001, the
DPUC rejected CL&P's request, but opened two new dockets to examine the absence
of effective retail competition in Connecticut and the financial condition of
the suppliers. The first docket culminated in a joint study report issued in a
DPUC decision on February 15, 2002, which provided the DPUC's and the Office of
Consumer Counsel's findings on how to best structure default service and other
issues related to electric industry restructuring. In the second docket, the
DPUC concluded on June 17, 2002, that it would not commence further proceedings.
On July 18, 2002, CL&P, concerned with NRG-PM's financial viability, filed a new proposal with the DPUC to maintain current total rates, but to shift $0.007 per kWh from being used to recover stranded costs to instead provide additional payments to NRG-PM and Select Energy to ensure electric reliability in southwestern Connecticut. On July 26, 2002, the DPUC denied the proposal.
CL&P continues to evaluate NRG-PM's ability to meet its obligations under the standard offer service contract. If CL&P is required to seek an alternate source of supply, CL&P would pursue recovery of any additional costs associated with obtaining such supply from NRG-PM pursuant to the contract and may be required to seek DPUC approval to flow through any such costs to customers. Management believes that recovery of these costs, should they be incurred, would be permitted under the provisions of Connecticut's electric utility restructuring legislation and with the DPUC's prior decisions. On February 21, 2003, Fitch Ratings lowered its rating outlook on CL&P to negative as a result of its concern over timely recovery of purchased-power costs if NRG-PM were to default on its CL&P standard offer obligations and CL&P needed to acquire replacement supply service at significantly higher prices.
On September 27, 2001, CL&P filed its application with the DPUC for approval of the disposition of the proceeds in the amount of approximately $1.2 billion from the sale of the Millstone units. This application described and requested DPUC approval for CL&P's treatment of its share of the proceeds from the sale. In accordance with Connecticut's electric utility industry restructuring legislation, CL&P was required to utilize any gains from the Millstone sale to offset stranded costs. The DPUC's final decision regarding this application was issued on February 27, 2003, and increased the amount of net proceeds used to reduce stranded costs by $26.9 million. The earnings impact of the final decision will be reflected in 2003 earnings and will result in an increase in first quarter net income of $2.6 million.
On November 1, 2002, CL&P sold its interest in Seabrook to a subsidiary of FPL Group, Inc. (FPL). The gain on the sale was used to reduce stranded costs.
CL&P continues to be subject to the earnings sharing mechanism implemented by the DPUC, under which CL&P's earnings in excess of a 10.3 percent return on equity will be shared equally by shareholders and ratepayers.
CL&P expects to file a distribution rate case with the DPUC in mid-2003 that would be effective January 1, 2004. Also in the second half of 2003, CL&P will need to secure bids for power supply contracts for 2004 to meet the needs of its customers. Management has not yet identified what level of rates it will request in 2004, but believes that several factors could combine to result in a significant increase in supply costs in 2004. The first is the expiration of current standard offer supply contracts. Another factor is the likely impact of LMP in New England with the implementation of SMD. Implementation of such pricing, which occurred on March 1, 2003, will force Connecticut electric customers to bear the significant additional costs of serving southwestern Connecticut with less efficient local generation because of insufficient transmission capacity to bring cheaper energy into the region. CL&P's completed and planned reliability improvements and transmission construction program will also impact the level of rates management will request in 2004.
Connecticut - Yankee Gas: Following rate proceedings that began in 2001, the DPUC ordered a $4 million rate decrease effective April 1, 2002. The decision endorsed Yankee Gas' distribution expansion plan, subject to annual reviews, and approved, with some conditions, its capital investment ratemaking recovery mechanism, the Infrastructure Expansion Rate Mechanism (IERM). The final decision also authorized an 11 percent return on equity for Yankee Gas and a sharing formula between shareholders and ratepayers for earnings above that level from 2002 through 2005.
On October 1, 2002, Yankee Gas filed supplemental testimony and exhibits to its original IERM filing with the DPUC on August 1, 2002. This filing reflected those 2001 through 2003 system expansion projects that Yankee Gas has undertaken or plans to undertake by December 31, 2003, and that meet certain financial criteria outlined by the DPUC. Yankee Gas is currently proposing no IERM charge for 2003 and that any over-collection for 2003 be carried forward to the 2004 IERM period. A final decision from the DPUC regarding this filing is expected in the first quarter of 2003.
A schedule has been set in Yankee Gas' proceeding before the DPUC to obtain rate approval to build a two billion cubic foot liquefied natural gas storage and production facility in Waterbury, Connecticut. The schedule includes hearings in March 2003 with a final decision in the second quarter of 2003. If approved, construction on the facility, which could cost approximately $60 million, could begin in the fourth quarter of 2003.
In December 2002, the DPUC opened a new docket concerning Yankee Gas overearnings. Hearings related to this docket are scheduled to be held in March 2003 with a final decision scheduled for May 2003, and management cannot determine the ultimate impact of this docket.
New Hampshire: In July 2001, the NHPUC opened a docket to review the fuel and purchased-power adjustment clause (FPPAC) costs incurred between August 2, 1999, and April 30, 2001. Under the Restructuring Settlement, FPPAC deferrals are recovered as a Part 3 stranded cost through the stranded cost recovery charge. On December 31, 2002, the NHPUC issued its final order allowing recovery of virtually all such costs.
On June 28, 2002, PSNH made its first stranded cost recovery charge reconciliation filing with the NHPUC for the period May 1, 2001, through December 31, 2001. This filing reconciles stranded cost revenues against actual stranded cost charges with any difference being credited against stranded costs or deferred for future recovery. Included in the stranded cost charges are the generation costs for the filing period. The generation costs included in this filing were subject to a prudence review by the NHPUC. In January 2003, PSNH entered into a settlement agreement with the Office of Consumer Advocate and the staff of the NHPUC that resolved all outstanding issues. In conjunction with the settlement agreement, the NHPUC staff recommended no disallowances resulting from their review of the outages at PSNH's generating plants. A final order approving the settlement agreement was issued by the NHPUC in February 2003. The NHPUC order approved PSNH's reconciliation of stranded costs as outlined within the Settlement Agreement and had no impact on PSNH's earnings.
On September 12, 2002, the NHPUC issued a final decision approving the auction results in the sale of Seabrook to FPL. On November 1, 2002, the sale was consummated. The proceeds received by NAEC, after NAEC repaid its outstanding debt, were refunded to PSNH through the Seabrook Power Contracts. PSNH used the proceeds received from NAEC to recover stranded costs and repay debt with the remaining proceeds to be returned to NU. As a result of the Seabrook sale, PSNH expects its wholesale electric sales to decline significantly in 2003. However, PSNH expects to generate most of the electricity it needs to serve retail customers from its own generating plants or purchased-power obligations and to purchase the remainder in the wholesale market.
On February 1, 2003, in accordance with the Restructuring Settlement, PSNH raised the transition service rate for residential and small commercial customers to $0.0460 per kWh from $0.0440 per kWh. On the same date, PSNH also raised its transition service rate for large commercial and industrial customers to $0.0467 per kWh from $0.0440 per kWh. PSNH expects these 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, those overrecoveries will be credited against PSNH's Part 3 stranded cost balance. If actual costs exceed those recoveries, PSNH will defer those costs for future recovery from customers through its Stranded Cost Recovery Charge.
PSNH's delivery rates are fixed until February 1, 2004. Under the Restructuring Settlement, PSNH must file a rate case by December 31, 2003, for the purpose of commencing a review of PSNH's delivery rates. Also, under New Hampshire electric industry restructuring statutes, PSNH cannot divest its nonnuclear generation assets until at least February 1, 2004. At this time, management does not expect PSNH to propose selling its 1,200 MW of generation assets.
Massachusetts: In December 2001, the DTE approved approximately a 14 percent reduction in WMECO's overall rates for standard offer service, primarily reflecting a reduction in WMECO's standard offer service supply costs in 2002 to approximately $0.048 per kWh from approximately $0.073 per kWh. In December 2002, the DTE approved an overall increase of approximately 1.8 percent in WMECO's non-contract standard offer rates, primarily reflecting slightly increased standard offer and default service costs as well as other inflationary factors. Select Energy won the bid to supply WMECO with standard offer service in 2003 at an average rate of approximately $0.050 per kWh. An unaffiliated company won a bid to serve WMECO with default service for the period of January 1, 2003, through June 30, 2003, at an average price of $0.051 per kWh.
On June 7, 2002, the DTE issued its decision on WMECO's 1998 through 1999 stranded cost reconciliation. The decision included, among other things, a conclusion that investment tax credits associated with generation assets that have been divested should not be returned to ratepayers. As a result, WMECO recognized approximately $13 million in tax credits during the second quarter of 2002.
On March 30, 2001, WMECO filed its second annual stranded cost reconciliation with the DTE for calendar year 2000. On March 29, 2002, WMECO filed its 2001 annual transition cost reconciliation with the DTE. This filing reconciled the recovery of stranded generation costs for calendar year 2001 and includes sales proceeds from WMECO's portion of the Millstone units, the impact of securitization and approximately a $13 million benefit to ratepayers from WMECO's nuclear performance-based ratemaking process.
Subsequently, WMECO and the office of the Massachusetts Attorney General reached a settlement resolving all transition charge issues for the 1998 through 2001 reconciliations. This settlement was filed for DTE review on December 3, 2002 and approved on December 27, 2002. The settlement had a positive impact of $9 million on WMECO 2002 pretax earnings.
For further information regarding commitments and contingencies related to restructuring, see Note 8A, "Commitments and Contingencies - Restructuring and Rate Matters," to the consolidated financial statements.
Nuclear Generation Asset Divestitures
Seabrook: On November 1, 2002, CL&P, NAEC, and certain other joint owners
consummated the sale of their ownership interest in Seabrook.
VYNPC: On July 31, 2002, Vermont Yankee Nuclear Power Corporation (VYNPC) consummated the sale of its nuclear generating unit. NU subsidiaries CL&P, PSNH, and WMECO combined own 17 percent of VYNPC.
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.
Under the terms of these asset divestitures, the purchasers agreed to assume responsibility for decommissioning their respective units. For further information regarding these divestitures and nuclear decommissioning, see Note 7, "Nuclear Generation Asset Divestitures," and Note 8F, "Nuclear Decommissioning and Plant Closure Costs," to the consolidated financial statements. For further information regarding spent nuclear fuel disposal costs, see Note 8C, "Commitments and Contingencies - Spent Nuclear Fuel Disposal Costs," to the consolidated financial statements.
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 condition of NU. The following describes 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 significant control is maintained and 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, VYNPC, two companies that transmit electricity imported from the Hydro-Quebec system, NEON, Acumentrics, and R.M. Services, Inc., which are classified as variable interest entities under Financial Accounting Standards Board Interpretation No. 46, "Consolidation of Variable Interest Entities," and for which NU was not classified as the primary beneficiary. As a result, management does not expect the adoption of Interpretation No. 46 to result in the consolidation of any currently unconsolidated entities or to have any other material impacts on NU's consolidated financial statements.
Revenue Recognition: Regulated utility revenues are based on rates approved by the state regulatory commissions. These regulated rates are applied to customers' accounts based on their use of energy. In general, rates can only be changed through formal proceedings with the state regulatory commissions.
The determination of the energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is estimated. This unbilled revenue is estimated each month based on generation volumes, estimated customer usage by class, line losses, and applicable customer rates.
Competitive energy subsidiary revenues are recognized at different times for the different businesses. 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.
Energy Trading and Derivative Accounting: On October 1, 2002, NU adopted EITF Issue No. 02-3. The consensuses in EITF Issue No. 02-3 require net reporting of trading revenues and expenses, and rescinded EITF Issue No. 98-10, "Accounting for Energy Trading and Risk Management Activities," which had allowed contracts to be marked-to-market based on trading intent. On July 1, 2002, NU adopted net reporting of trading revenues and expenses, as then allowed by EITF Issue No. 98-10. The rescission of EITF Issue No. 98-10 by EITF Issue No. 02-3 also required that contracts that are not derivatives as defined under SFAS No. 133 be removed from the consolidated balance sheets as a cumulative effect of accounting change and no longer recorded at fair value. The adoption of EITF Issue No. 02-3 did not have a material impact on NU's consolidated financial statements.
However, in implementing EITF Issue No. 02-3, Select Energy performed a review of all contracts previously recorded under EITF Issue No. 98-10. 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 business, 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 the normal purchases and sales 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 will be 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.
Select Energy uses derivative investments in its trading, wholesale, and retail
marketing businesses. The application of derivative accounting under SFAS No.
133 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 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 NU's consolidated net
income.
During 2002, approximately $7 million of transmission congestion contracts, which were included in Select Energy's marketing portfolio, were determined to be derivatives. These contracts were recorded at fair value using a valuation model and, at the same time, a valuation reserve on these contracts was recorded due to the lack of available market data. Management continues to believe the amount paid for the contracts best represents their market value. If these assumptions regarding the classification of the contracts change or if new accounting guidance is issued, there may be an impact on NU's consolidated financial statements.
Regulatory Accounting and Assets: 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." CL&P's, PSNH's and WMECO's transmission and distribution businesses 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 regulatory assets. Such a write-off could have a material impact on NU's consolidated financial statements.
The application of SFAS No. 71 results in the deferral of costs as regulatory assets that, in some cases, have not yet been approved for recovery by the applicable regulatory commission. Management must conclude that any costs deferred as regulatory assets are probable of future recovery in rates. However, regulatory commissions can reach different conclusions about the recovery of costs, which can have a material impact on NU's consolidated financial statements. Management believes it is probable that NU's regulated utility companies will recover their investments in long-lived assets, including regulatory assets.
Goodwill and Other Intangible Assets: On January 1, 2002, NU adopted SFAS No. 142, "Goodwill and Other Intangible Assets." SFAS No. 142 requires that management determine reporting units that carry goodwill. The determination of reporting units requires judgment based on how the business segments are managed. SFAS No. 142 also requires that goodwill and intangible assets deemed to have indefinite useful lives be reviewed for impairment upon adoption and at least annually thereafter by applying a fair value-based test. The fair value-based test involves estimating the fair value of the reporting units by using both discounted cash flow methodologies and an analysis of comparable companies or transactions. The discounted cash flow methodologies that are utilized involve critical assumptions and estimates made by management. If these assumptions are changed there could be a significant impact on NU's consolidated financial statements.
Pension and Postretirement Benefit Obligations: NU's subsidiaries participate in a uniform noncontributory defined benefit retirement plan (Plan) covering substantially all regular NU employees and also 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 resultant 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.
Pre-tax periodic pension income for the Plan, excluding settlements, curtailments, and special termination benefits, totaled $73.4 million and $101 million for the years ended December 31, 2002 and 2001, respectively. Pension income is calculated based upon a number of actuarial assumptions, including an expected long-term rate of return on Plan assets of 9.25 percent for 2002 and 9.5 percent for 2001. NU expects to use a long-term rate of return assumption of 8.75 percent for 2003. 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 of income and $2.6 million in expense for the years ended December 31, 2002 and 2001, respectively. Approximately 30 percent of net pension income is capitalized as a reduction to capital additions to utility plant.
In developing the expected long-term rate of return assumption, NU evaluated input from actuaries, consultants and economists as well as long-term inflation assumptions and NU's historical 20-year compounded return of 10.7 percent. NU's expected long-term rate of return on Plan assets is based on target asset allocation assumptions of 45 percent in United States equities and 14 percent in non-United States equities, both with an expected long-term rates of return of 9.25 percent, 3 percent in emerging market equities with an expected long-term return of 10.25 percent, 20 percent in fixed income securities with an expected long-term rate of return of 5.5 percent, 5 percent in high yield fixed income securities with expected long-term rates of return of 7.5 percent, 8 percent in private equities with expected long-term rates of return of 14.25 percent, and 5 percent in real estate with expected long-term rates of return of 7.5 percent. The combination of these target allocations and expected returns results in the overall assumed long-term rate of return of 8.75 percent for 2003. The actual asset allocation at December 31, 2002, was close to these target asset allocations, and NU regularly reviews the actual asset allocations and periodically rebalances the investments to the targeted allocation when appropriate. NU reduced the long-term rate of return assumption by 0.5 percent and 0.25 percent, respectively, each of the last two years due to lower rate of return assumptions for most asset classes. NU believes that 8.75 percent is a reasonable long-term rate of return on Plan assets for 2003. 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.
NU bases the actuarial determination of Plan pension income/expense on a market-related valuation of assets, which reduces year-to-year volatility. This market-related valuation 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 value of assets 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 Plan assets. At December 31, 2002, the Plan had cumulative unrecognized investment losses of $507.9 million, which will increase pension expense over the next four years by reducing the expected return on Plan assets. At December 31, 2002, the Plan also had cumulative unrecognized actuarial gains of $89 million, which will reduce pension expense over the expected future working lifetime of active Plan participants, or approximately 13 years. The combined total of unrecognized investment losses and actuarial gains at December 31, 2002 is $418.9 million. This amount impacts the actuarially determined prepaid pension amount recorded on the consolidated balance sheet but has no impact on expected Plan funding.
The discount rate that is utilized in determining future pension 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 Plan's longer duration 0.25 percent was added to this rating. The discount rate determined on this basis has decreased from 7.25 percent at December 31, 2001 to 6.75 percent at December 31, 2002.
Due to the effect of the unrecognized actuarial losses and based on an expected rate of return on Plan assets of 8.75 percent, a discount rate of 6.75 percent and various other assumptions, NU estimates that pension income/expense for the Plan will be approximately $31 million in income, approximately $7 million in expense and approximately $39 million in expense in 2003, 2004 and 2005, respectively. 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 plan.
The effect of lowering the expected long-term rate of return on Plan assets by 0.5 percent would have reduced pension income for 2002 by approximately $11 million. The effect of lowering the discount rate by 0.5 percent would have also reduced pension income for 2002 by approximately $11 million.
The compensation increase assumption used for 2002 was based on the expected increase in payroll for personnel covered by the Plan. The effect of lowering the compensation increase assumption by 0.5 percent would have increased pension income for 2002 by approximately $5 million.
The value of the Plan assets has decreased from $2 billion at December 31, 2001 to $1.6 billion at December 31, 2002. The investment performance returns and declining discount rates have reduced the funded status of the Plan on a projected benefit obligation (PBO) basis from an overfunded position of $302.8 million at December 31, 2001 to an underfunded position of $157.5 million at December 31, 2002. The PBO includes expectations of future employee service and compensation increases. The significant deterioration in the funded position of the Plan will likely result in Plan contributions sooner than previously expected. NU has not made contributions since 1991. This deterioration could also lead to the requirement under defined benefit plan accounting to record an additional minimum liability. The accumulated benefit obligation (ABO) of the Plan was $78 million less than Plan assets at December 31, 2002. The ABO is the obligation for employee service provided through December 31, 2002. If the ABO exceeds Plan assets, NU will record an additional minimum liability in 2003.
Income Taxes: Income tax expense is calculated in each of the jurisdictions in which NU operates for each period for which a statement of income is presented. 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 of expenses for tax and book accounting purposes. These differences result in deferred tax assets and liabilities, which are included in the consolidated balance sheets. NU must also assess the likelihood that the 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. This asset amounted to $331.9 million and $301.3 million at December 31, 2002 and 2001, respectively.
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.
Environmental Matters: At December 31, 2002, NU has recorded a reserve for various environmental liabilities. NU's environmental liabilities are based on the best estimate of the amounts to be incurred for the investigation, remediation and monitoring of the remediation sites. It is possible that future cost estimates will either increase or decrease as additional information becomes known. Changes in future cost estimates will have a smaller impact on NU's subsidiaries that have regulatory mechanisms to recover environmental remediation costs. These subsidiaries include PSNH and Yankee Gas. Yankee Gas recorded an environmental liability for former manufactured gas plant sites of $19.4 million and $22.9 million at December 31, 2002 and 2001, respectively.
Special Purpose Entities and Off-Balance Sheet Financing: NU has a total of seven special purpose entities (SPE), all of which are currently consolidated in the financial statements. 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 become involved in such bankruptcy proceedings.
The CL&P Receivables Corporation (CRC) is an SPE that was incorporated on September 5, 1997, and is a wholly owned subsidiary of CL&P. The CRC was established for the sole purpose of selling CL&P's accounts receivable and is included in the consolidation of NU's financial statements. On July 10, 2002 the CRC renewed its Receivables Purchase and Sale Agreement with CL&P and a subsidiary of Citigroup, Inc. (Citigroup). The agreement gives the CRC the right to sell and Citigroup the right to purchase up to $100 million in receivables through July 9, 2003. At December 31, 2002 there was $40 million outstanding under this facility. Sales of receivables to Citigroup under this arrangement meet the accounting criteria for derecognition from the consolidated balance sheets. Accordingly, the $40 million outstanding under this facility is not reflected as debt or included in the consolidated financial statements.
During 2001, SESI established an SPE, HEC/CJTS Energy Center LLC (HEC/CJTS), to provide a bankruptcy-remote entity in connection with an energy project constructed for the State of Connecticut (State). This SPE was established for financing purposes with cooperation from the State Treasurer. HEC/CJTS is limited in the transactions it may enter into and may not initiate an event of bankruptcy without a vote of its sole member and all directors, including independent directors. Pursuant to an engineering, procurement, and construction agreement with the State, SESI constructed a power plant to provide energy and heat to the Connecticut Juvenile Training School (Project), in return for the State entering into a 30-year lease. SESI assigned its interest in the lease with the State to HEC/CJTS in exchange for payments totaling $17.7 million.
During 2001, HEC/CJTS transferred its interest in the lease with the State to unaffiliated investors in exchange for the issuance of $19.2 million of Certificates of Participation (Certificates). This transfer was accounted for as a sale at the beginning of the lease term. HEC/CJTS is included in the accompanying consolidated financial statements, however, upon transfer of the interest in the lease, the debt of $19.2 million created upon issuance of the Certificates was derecognized. No gain or loss was recorded. Proceeds from the issuance of the Certificates, net of issuance costs and net construction interest, were transferred to SESI as payment for the Project construction.
During 1999, SESI established another SPE, HEC/Tobyhanna Energy Project, LLC (HEC/Tobyhanna), to provide a bankruptcy-remote entity 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 are limited to those related to the project and HEC/Tobyhanna, including the Certificates, is included in the accompanying consolidated financial statements.
For further information regarding these types of activities, 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," Note 6, "Sale of Customer Receivables," and Note 8B, "Commitments and Contingencies - Environmental Matters," to the consolidated financial statements.
Other Matters
Other Commitments and Contingencies: For further information regarding other
commitments and contingencies, see Note 8, "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, 2002, is summarized through 2007 as follows:
(Millions of Dollars) 2003 2004 2005 2006 2007 --------------------------------------------------------------------------------------------------------------------------------- Notes payable to banks $ 56.0 $ -- $ -- $ -- $ -- Long-term debt 56.9 61.7 88.7 26.6 8.3 Capital leases 3.1 3.0 2.8 2.7 2.6 Operating leases 23.1 20.6 18.4 16.2 9.8 Long-term contractual arrangements 567.8 551.3 533.0 517.1 364.2 Select Energy purchase agreements 3,302.0 612.6 290.1 68.7 69.2 --------------------------------------------------------------------------------------------------------------------------------- Totals $4,008.9 $1,249.2 $933.0 $631.3 $454.1 ================================================================================================================================= |
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 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 10, "Leases," and Note 8E, "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, 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.
RESULTS OF OPERATIONS
The components of significant income statement variances for the past two years are provided in the table below.
Income Statement Variances 2002 over/(under) 2001 2001 over/(under) 2000
---------------------- ----------------------
(Millions of Dollars) Amount Percent Amount Percent
-----------------------------------------------------------------------------------------------------------------------------------
Operating Revenues $(752) (13)% $ 92 2%
Operating Expenses:
Fuel, purchased and net interchange power (610) (17) 332 10
Other operation (21) (3) (93) (11)
Maintenance 5 2 3 1
Depreciation 4 2 (39) (16)
Amortization (521) (53) 706 (a)
Taxes other than income taxes 8 4 (19) (8)
Gain on sale of utility plant 455 71 (642) (100)
-----------------------------------------------------------------------------------------------------------------------------------
Total operating expenses (680) (13) 248 5
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Operating Income (72) (13) (156) (22)
-----------------------------------------------------------------------------------------------------------------------------------
Interest expense, net (9) (3) (19) (7)
Other income/(loss), net (144) (77) 202 (a)
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Income before tax expense (207) (46) 65 17
Income tax expense (92) (53) 12 8
Preferred dividends of subsidiaries (2) (23) (7) (49)
-----------------------------------------------------------------------------------------------------------------------------------
Income before extraordinary loss and accounting change (113) (43) 60 30
Extraordinary loss, net of tax benefit -- -- 234 100
Cumulative effect of accounting change, net of tax benefit 22 100 (22) (100)
-----------------------------------------------------------------------------------------------------------------------------------
Net income/(loss) $ (91) (38)% $ 272 (a)
===================================================================================================================================
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(a) Percent greater than 100.
Operating Revenues
Total revenues decreased by $752 million or 13 percent in the year 2002,
compared with the year 2001, primarily due to lower competitive energy revenues
($377 million after intercompany eliminations) and lower regulated subsidiaries
revenues due to lower wholesale and transmission revenues ($240 million after
intercompany eliminations), and lower regulated retail revenues ($135 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), lower PSNH wholesale sales ($94 million), primarily due to a reduction in prices and a lower volume of bilateral transactions and sales of excess capacity and energy, 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 ($22 million), and the 2002 decrease in the WMECO standard offer energy rate ($77 million), lower Yankee 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.
Total revenues increased by $92 million or 2 percent in the year 2001, compared with the year 2000, primarily due to higher revenues from the competitive energy subsidiaries ($164 million after intercompany eliminations), higher revenues from Yankee Gas ($127 million) and higher regulated retail electric revenues ($33 million), partially offset by lower wholesale regulated revenues ($190 million) and lower transmission revenues ($26 million). The competitive energy subsidiaries' increase is primarily due to higher revenues from Select Energy as a result of new wholesale energy contracts. The Yankee Gas increase was primarily due to a full year of revenue in 2001 versus ten months post merger in 2000. The regulated retail increase is primarily due to a 1.7 percent increase in sales ($41 million), the increase in WMECO's standard offer service rate ($59 million) and the recovery of previously deferred fuel costs for CL&P ($19 million), partially offset by the 5 and 11 percent rate decreases for PSNH that were effective October 1, 2000 and May 1, 2001, respectively ($89 million). Wholesale revenues were lower primarily due to the sale of Millstone at the end of the first quarter of 2001.
Fuel, Purchased and Net Interchange Power Fuel, purchased and net interchange power expense decreased by $610 million or 17 percent in the year 2002, primarily due to lower wholesale sales from the competitive businesses ($301 million after intercompany eliminations), lower Yankee expense primarily due to lower gas prices ($69 million), and lower purchased-power costs for the regulated subsidiaries ($240 million net of eliminations).
Fuel, purchased and net interchange power expense increased in 2001, primarily due to higher purchased energy and capacity costs as a result of higher sales for Select Energy ($347 million, which reflects eliminations of purchases from other NU subsidiaries), higher expense for Yankee primarily due to a full year in 2001 and higher gas prices ($83 million), and higher expense for WMECO primarily due to the increased cost of the standard offer supply ($70 million), partially offset by lower wholesale cost for CL&P and PSNH ($173 million, net of eliminations).
Other Operation and Maintenance
Other operation and maintenance expenses (O&M) decreased $16 million in 2002,
primarily due to lower expenses associated with the regulated businesses ($56
million), partially offset by higher competitive companies' expenses associated
with Select Energy's costs of goods sold and the expansion of new businesses
($42 million). The regulated O&M decrease is 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 ($55 million).
Other O&M expenses decreased $90 million in 2001, primarily due to lower nuclear expenses ($133 million) as a result of the sale of the Millstone units at the end of the first quarter of 2001, partially offset by higher O&M expenses for the competitive energy subsidiaries, primarily due to an acquisition made by NGS ($49 million).
Depreciation
Depreciation increased $4 million in 2002, primarily due to higher expense
resulting from higher regulated plant balances ($11 million), partially offset
by the Millstone unit decommissioning expenses recorded in 2001 ($8 million).
Depreciation expense decreased $39 million in 2001, primarily due to the elimination of decommissioning expenses as a result of the sale of the Millstone units at the end of the first quarter of 2001 ($25 million) and the buydown of the Seabrook Power Contracts ($14 million).
Amortization
Amortization decreased $521 million in 2002, primarily due to the amortization
in 2001 related to the gain on sale of the Millstone units ($642 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) and higher
amortization related to the regulated companies recovery of stranded costs ($23
million).
Amortization of regulatory assets, net increased in 2001, primarily due to the amortization in 2001 related to the gain on sale of the Millstone units by CL&P and WMECO ($642 million) and higher amortization related to restructuring.
Taxes Other Than Income Taxes
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).
Taxes other than income taxes decreased by $19 million in 2001, primarily due to the reduction in property tax for CL&P and WMECO due to the sale of the Millstone units ($16 million), the property tax settlement with the City of Meriden for CL&P and Yankee in 2001 ($15 million), and lower New Hampshire franchise tax ($5 million), partially offset by higher Connecticut gross earnings taxes ($14 million) on higher CL&P revenues.
Gain on Sale of Utility Plant
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 $9 million in 2002, primarily due to NAEC's
reduction of debt.
Interest charges, net decreased in 2001, primarily due to reacquisitions and retirements of long-term debt ($54 million) and higher short-term borrowings in 2000 associated with asset transfers and the Yankee merger ($54 million), partially offset by the interest expense associated with the issuance of rate reduction bonds in 2001 ($88 million).
Other Income/(Loss), Net
Other income/(loss), 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).
Other income/(loss), net increased primarily due to NU's recognition in 2001 of a gain in connection with the sale of the Millstone nuclear units to a subsidiary of Dominion Resources, Inc. (the pre-tax amount of $189 million is included in other income with an offsetting income tax expense impact of $73 million), higher interest and dividend income ($20 million), lower nuclear related costs in 2001 ($18 million), and lower environmental reserve expense in 2001 ($10 million), partially offset by the charge related to the forward purchase of 10.1 million NU common shares ($35 million).
Income Taxes
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 $92 million in 2002, primarily due to the recognition of WMECO investment tax credits 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.
Federal and state income taxes combined increased in 2001, primarily due to higher taxable income. The increase in income taxes as a result of higher taxable income was partially offset by a reduction in income taxes as a result of the favorable resolution of open tax years. For further information regarding income taxes, see the Consolidated Statements of Income Taxes.
Preferred Dividends of Subsidiaries
Preferred dividends decreased in 2001 and 2002 primarily due to lower preferred
stock outstanding.
Extraordinary Loss, Net of Tax Benefit
The extraordinary loss in 2000 is primarily due to an after-tax write-off by
PSNH of approximately $225 million of stranded costs under the Restructuring
Settlement with the state of New Hampshire, combined with other positive effects
on PSNH from the discontinuance of SFAS No. 71 ($11 million) and a loss
associated with the then pending discontinuance of SFAS No. 71 at HWP and the
sale of its assets ($20 million).
Cumulative Effect of Accounting Change, Net of Tax Benefit The cumulative effect of accounting change, net of tax benefit, recorded in 2001, represents the effect of the adoption of SFAS No. 133, as amended ($22 million).
Company Report
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 in 2002 and 2001, and Arthur Andersen LLP in 2000, 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, which 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 policies prohibiting conflicts of interest.
The Audit Committee of the Board of Trustees is composed entirely of independent trustees. 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 control. 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 accounting control 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 information disclosed is accumulated and reviewed by management for discussion and approval.
Independent Auditors' Report
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, 2002 and 2001, and the related consolidated statements of income, comprehensive income, shareholders' equity, cash flows and income taxes for the years then ended. The consolidated financial statements of the Company as of December 31, 2000, 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. 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, the 2002 and 2001 consolidated financial statements present fairly, in all material respects, the financial position of Northeast Utilities and subsidiaries (a Massachusetts trust) as of December 31, 2002 and 2001, 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.
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. In 2002, the Company adopted Emerging Issues Task Force Issue 02-3, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities," and, retroactively, restated the 2001 consolidated financial statements. Also, as discussed in Note 5, the Company adopted SFAS No. 142, "Goodwill and Other Intangible Assets," as of January 1, 2002.
As discussed above, the consolidated financial statements of the Company as of
December 31, 2000 and for the year then ended were audited by other auditors who
have ceased operations. As described in Note 5, the 2001 and 2000 consolidated
financial statements have been revised to include the transitional disclosures
required by SFAS No. 142, which was adopted by the Company as of January 1,
2002. Our audit procedures with respect to the disclosures in Note 5 with
respect to 2000 included i) agreeing the previously reported net income to the
previously issued consolidated financial statements and the adjustments to
reported net income representing amortization expense (including any related tax
effects) recognized in that period related to goodwill and intangible assets
that are no longer being amortized as a result of initially applying SFAS No.
142 (including any related tax effects) to the Company's underlying records
obtained from management, and ii) testing the mathematical accuracy of the
reconciliation of adjusted net income to reportednet income, and the related
earnings-per-share amounts. In our opinion, the disclosures in Note 5 are
appropriate. However, we were not engaged to audit, review, or apply any
procedures to the 2000 consolidated financial statements of the Company other
than with respect to such disclosures and, accordingly, we do not express an
opinion or any other form of assurance on the 2000 consolidated
financial statements taken as a whole.
/s/ DELOITTE & TOUCHE LLP
---------------------
DELOITTE & TOUCHE LLP
Hartford, Connecticut
January 28, 2003
(February 27, 2003 as to Note 8A)
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Report of Independent
Public Accountants
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 (a Massachusetts trust) and subsidiaries as of December 31, 2001 and 2000, 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, 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 Northeast Utilities and subsidiaries 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.
As discussed in Note 1C to the consolidated financial statements, effective January 1, 2001, the company adopted Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended.
/s/ ARTHUR ANDERSEN LLP
-------------------
ARTHUR ANDERSEN LLP
Hartford, Connecticut
January 22, 2002
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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.
Readers should also be aware that amounts previously reported have been reclassified with the adoption of net reporting, which is discussed in Note 1C to the consolidated financial statements. The 2001 consolidated financial statements have been reaudited by Deloitte & Touche LLP.
Consolidated Balance Sheets
At December 31,
(Thousands of Dollars) 2002 2001
-----------------------------------------------------------------------------------------------------------------------------------
Assets
Current Assets:
Cash and cash equivalents $ 85,393 $ 96,658
Investments in securitizable assets 178,908 206,367
Receivables, less provision for uncollectible
accounts of $15,425 in 2002 and $16,353 in 2001 767,089 659,759
Unbilled revenues 126,236 126,398
Fuel, materials and supplies, at average cost 119,853 108,516
Special deposits 2,455 60,261
Derivative assets 130,929 150,299
Prepayments and other 110,261 67,910
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1,521,124 1,476,168
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Property, Plant and Equipment:
Electric utility 5,141,887 5,743,575
Gas utility 679,055 634,884
Competitive energy 866,294 850,061
Other 205,115 195,741
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6,892,351 7,424,261
Less: Accumulated depreciation 2,484,549 3,273,737
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4,407,802 4,150,524
Construction work in progress 320,567 289,889
Nuclear fuel, net -- 32,564
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4,728,369 4,472,977
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Deferred Debits and Other Assets:
Regulatory assets 2,910,029 3,287,537
Goodwill and other purchased intangible assets, net 345,867 333,123
Prepaid pension 328,890 232,398
Nuclear decommissioning trusts, at market -- 61,713
Other 433,338 468,007
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4,018,124 4,382,778
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Total Assets $10,267,617 $10,331,923
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The accompanying notes are an integral part of these consolidated financial statements.
Consolidated Balance Sheets
At December 31,
(Thousands of Dollars) 2002 2001
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Liabilities and Capitalization
Current Liabilities:
Notes payable to banks $ 56,000 $ 290,500
Long-term debt - current portion 56,906 50,462
Accounts payable 766,128 608,705
Accrued taxes 141,667 27,371
Accrued interest 40,597 35,659
Derivative liabilities 63,900 151,648
Other 179,154 161,277
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1,304,352 1,325,622
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Rate Reduction Bonds 1,899,312 2,018,351
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Deferred Credits and Other Liabilities:
Accumulated deferred income taxes 1,436,507 1,491,394
Accumulated deferred investment tax credits 106,471 120,071
Deferred contractual obligations 354,469 216,566
Other 552,641 633,523
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2,450,088 2,461,554
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Capitalization:
Long-Term Debt 2,287,144 2,292,556
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Preferred Stock - Nonredeemable 116,200 116,200
-----------------------------------------------------------------------------------------------------------------------------------
Common Shareholders' Equity:
Common shares, $5 par value - authorized 225,000,000 shares;
149,375,847 shares issued and 127,562,031 shares outstanding in 2002
and 148,890,640 shares issued and 130,132,136 shares outstanding in 2001 746,879 744,453
Capital surplus, paid in 1,108,338 1,107,609
Deferred contribution plan - employee stock ownership plan (87,746) (101,809)
Retained earnings 765,611 678,460
Accumulated other comprehensive income/(loss) 14,927 (32,470)
Treasury stock, 18,022,415 shares in 2002 and 14,359,628 in 2001 (337,488) (278,603)
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Common Shareholders' Equity 2,210,521 2,117,640
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Total Capitalization 4,613,865 4,526,396
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Commitments and Contingencies (Note 8)
Total Liabilities and Capitalization $10,267,617 $10,331,923
===================================================================================================================================
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The accompanying notes are an integral part of these consolidated financial statements.
Consolidated Statements of Income
For the Years Ended December 31,
(Thousands of Dollars, except share information) 2002 2001 2000
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Operating Revenues $5,216,321 $5,968,220 $5,876,620
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Operating Expenses:
Operation -
Fuel, purchased and net interchange power 3,026,102 3,635,736 3,303,995
Other 752,482 773,058 866,742
Maintenance 263,487 258,961 255,884
Depreciation 205,646 201,013 239,798
Amortization 461,544 983,037 276,821
Taxes other than income taxes 227,518 219,197 238,587
Gain on sale of utility plant (187,113) (641,956) --
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Total operating expenses 4,749,666 5,429,046 5,181,827
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Operating Income 466,655 539,174 694,793
Interest Expense:
Interest on long-term debt 134,471 140,497 194,406
Interest on rate reduction bonds 115,791 87,616 --
Other interest 20,249 51,545 104,896
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Interest expense, net 270,511 279,658 299,302
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Other Income/(Loss), Net 43,828 187,627 (14,309)
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Income Before Income Tax Expense 239,972 447,143 381,182
Income Tax Expense 82,304 173,952 161,725
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Income Before Preferred Dividends of Subsidiaries 157,668 273,191 219,457
Preferred Dividends of Subsidiaries 5,559 7,249 14,162
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Income Before Cumulative Effect of Accounting Change
and Extraordinary Loss, Net of Tax Benefits 152,109 265,942 205,295
Cumulative effect of accounting change, net of tax benefit of $14,908 -- (22,432) --
Extraordinary loss, net of tax benefit of $169,562 -- -- (233,881)
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Net Income/(Loss) $ 152,109 $ 243,510 $ (28,586)
===================================================================================================================================
Basic Earnings/(Loss) Per Common Share:
Income before cumulative effect of
accounting change and extraordinary loss, net of tax benefits $ 1.18 $ 1.97 $ 1.45
Cumulative effect of accounting change, net of tax benefit -- (0.17) --
Extraordinary loss, net of tax benefit -- -- (1.65)
-----------------------------------------------------------------------------------------------------------------------------------
Basic Earnings/(Loss) Per Common Share $ 1.18 $ 1.80 $ (0.20)
===================================================================================================================================
Fully Diluted Earnings/(Loss) Per Common Share:
Income before cumulative effect of
accounting change and extraordinary loss, net of tax benefits $ 1.18 $ 1.96 $ 1.45
Cumulative effect of accounting change, net of tax benefit -- (0.17) --
Extraordinary loss, net of tax benefit -- -- (1.65)
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Fully Diluted Earnings/(Loss) Per Common Share $ 1.18 $ 1.79 $ (0.20)
===================================================================================================================================
Basic Common Shares Outstanding (average) 129,150,549 135,632,126 141,549,860
===================================================================================================================================
Fully Diluted Common Shares Outstanding (average) 129,341,360 135,917,423 141,967,216
===================================================================================================================================
Consolidated Statements of Comprehensive Income
For the Years Ended December 31,
(Thousands of Dollars) 2002 2001 2000
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Net Income/(Loss) $152,109 $243,510 $(28,586)
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Other Comprehensive Income/(Loss), Net of Tax:
Qualified cash flow hedging instruments 52,360 (36,859) --
Unrealized (losses)/gains on securities (5,121) 2,620 245
Minimum pension liability adjustments 158 -- --
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Other comprehensive income/(loss), net of tax 47,397 (34,239) 245
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Comprehensive Income/(Loss) $199,506 $209,271 $(28,341)
===================================================================================================================================
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The accompanying notes are an integral part of these consolidated financial statements.
Consolidated Statements of Shareholders' Equity
Accumulated
Capital Deferred Retained Other
Common Surplus, Contribution Earnings Comprehensive Treasury
(Thousands of Dollars) Shares Paid In Plan - ESOP (a) Income/(Loss) Stock Total
-----------------------------------------------------------------------------------------------------------------------------------
Balance as of January 1, 2000 $686,969 $ 942,025 $(127,725) $581,817 $ 1,524 $ (1,299) $2,083,311
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Net loss for 2000 (28,586) (28,586)
Cash dividends on common shares -
$0.40 per share (57,358) (57,358)
Issuance of 11,388,032 common shares,
$5 par value 56,940 164,443 221,383
Transaction fee on forward
share purchase arrangement (13,786) (13,786)
Allocation of benefits - ESOP (1,617) 13,262 11,645
Redemption of preferred stock (749) (749)
Capital stock expenses, net 2,478 2,478
Other comprehensive income 245 245
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Balance as of December 31, 2000 743,909 1,106,580 (114,463) 495,873 1,769 (15,085) 2,218,583
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Net income for 2001 243,510 243,510
Cash dividends on common shares -
$0.45 per share (60,923) (60,923)
Issuance of 108,779 common shares,
$5 par value 544 1,207 1,751
Allocation of benefits - ESOP (2,296) 12,654 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 2,118
Other comprehensive loss (34,239) (34,239)
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Balance as of December 31, 2001 744,453 1,107,609 (101,809) 678,460 (32,470) (278,603) 2,117,640
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Net income for 2002 152,109 152,109
Cash dividends on common shares -
$0.525 per share (67,793) (67,793)
Issuance of 485,207 common shares,
$5 par value 2,426 5,032 7,458
Allocation of benefits -
ESOP and restricted stock (4,679) 14,063 2,835 12,219
Repurchase of common shares (58,885) (58,885)
Capital stock expenses, net 376 376
Other comprehensive income 47,397 47,397
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Balance as of December 31, 2002 $746,879 $1,108,338 $ (87,746) $765,611 $ 14,927 $(337,488) $2,210,521
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(a) Certain consolidated subsidiaries have dividend restrictions imposed by their long-term debt agreements. These restrictions also limit the amount of retained earnings available for NU common dividends. At December 31, 2002, retained earnings available for payment of dividends totaled $318.3 million.
The accompanying notes are an integral part of these consolidated financial statements.
Consolidated Statements of Cash Flows
For the Years Ended December 31,
(Thousands of Dollars) 2002 2001 2000
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Operating Activities:
Income before preferred dividends of subsidiaries $ 157,668 $ 273,191 $ 219,457
Adjustments to reconcile to net cash flows provided by operating activities:
Depreciation 205,646 201,013 239,798
Deferred income taxes and investment tax credits, net (149,325) (116,704) (16,117)
Amortization 461,544 983,037 276,821
Net amortization/(deferral) of recoverable energy costs 27,623 (2,005) (30,603)
Gain on sale of utility plant (187,113) (641,956) --
Cumulative effect of accounting change, net of tax -- (22,432) --
Prepaid pension (96,492) (92,852) (138,877)
Net other sources/(uses) of cash 10,707 (65,064) 88,967
Changes in working capital:
Receivables and unbilled revenues, net (102,181) (301,068) (104,868)
Fuel, materials and supplies (27,590) 55,195 12,450
Accounts payable 153,450 100,277 171,148
Accrued taxes 114,296 (27,439) (128,107)
Investments in securitizable assets 27,459 61,779 9,474
Other working capital (excludes cash) 16,953 (76,366) 254
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Net cash flows provided by operating activities 612,645 328,606 599,797
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Investing Activities:
Investments in plant:
Electric, gas and other utility plant (468,842) (428,312) (345,596)
Competitive energy assets (23,150) (15,368) (7,140)
Nuclear fuel (465) (14,275) (61,286)
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Cash flows used for investments in plant (492,457) (457,955) (414,022)
Investments in nuclear decommissioning trusts (9,876) (105,076) (39,550)
Net proceeds from the sale of utility plant 366,786 1,045,284 --
Buyout/buydown of IPP contracts (5,152) (1,157,172) --
Payment for acquisitions, net of cash acquired (16,351) (31,699) (260,347)
Other investment activities, net 15,234 (51,677) (28,478)
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Net cash flows used in investing activities (141,816) (758,295) (742,397)
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Financing Activities:
Issuance of common shares 7,458 1,751 4,269
Repurchase of common shares (57,800) (291,789) --
Issuance of long-term debt 310,648 703,000 26,477
Issuance of rate reduction bonds 50,000 2,118,400 --
Retirement of rate reduction bonds (169,039) (100,049) --
Net (decrease)/increase in short-term debt (234,500) (1,019,477) 961,977
Reacquisitions and retirements of long-term debt (314,773) (714,226) (685,555)
Reacquisitions and retirements of preferred stock -- (60,768) (126,771)
Retirement of monthly income preferred securities -- (100,000) --
Retirement of capital lease obligation -- (180,000) --
Cash dividends on preferred stock (5,559) (7,249) (14,162)
Cash dividends on common shares (67,793) (60,923) (57,358)
Other financing activities, net (736) 37,660 (21,414)
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Net cash flows (used in)/provided by financing activities (482,094) 326,330 87,463
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Net decrease in cash and cash equivalents (11,265) (103,359) (55,137)
Cash and cash equivalents - beginning of year 96,658 200,017 255,154
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Cash and cash equivalents - end of year $ 85,393 $ 96,658 $ 200,017
===================================================================================================================================
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The accompanying notes are an integral part of these consolidated financial statements.
Consolidated Statements
of Capitalization
At December 31,
(Thousands of Dollars) 2002 2001
--------------------------------------------------------------------------------
Common Shareholders' Equity $2,210,521 $2,117,640
--------------------------------------------------------------------------------
Preferred Stock:
CL&P Preferred Stock Not Subject
to Mandatory Redemption -
$50 par value - authorized 9,000,000
shares in 2002 and 2001; 2,324,000
shares outstanding in 2002 and 2001;
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% 116,000 140,000
2009-2012 6.20% to 7.19% 80,000 80,000
2019-2024 7.88% to 10.07% 254,995 255,945
2026 8.81% 320,000 320,000
--------------------------------------------------------------------------------
Total First Mortgage Bonds 770,995 795,945
--------------------------------------------------------------------------------
Other Long-Term Debt -
Pollution Control Notes
and Other Notes - (b)
2003-2012 6.24% to 8.58%
and Adjustable Rate 358,400 381,500
2016-2018 5.90% 25,400 25,400
2021-2022 Adjustable Rate and
1.55% to 6.00% 428,285 428,285
2028 5.85% to 5.95% 369,300 369,300
2031 Adjustable Rate 62,000 62,000
--------------------------------------------------------------------------------
Total Pollution Control
Notes and Other Notes 1,243,385 1,266,485
Fees and interest due for spent nuclear
fuel disposal costs (c) 253,638 249,314
Other 80,181 36,257
--------------------------------------------------------------------------------
Total Other Long-Term Debt 1,577,204 1,552,056
--------------------------------------------------------------------------------
Unamortized premium and discount, net (4,149) (4,983)
--------------------------------------------------------------------------------
Total Long-Term Debt 2,344,050 2,343,018
Less: Amounts due within one year 56,906 50,462
--------------------------------------------------------------------------------
Long-Term Debt, Net 2,287,144 2,292,556
--------------------------------------------------------------------------------
Total Capitalization $4,613,865 $4,526,396
================================================================================
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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, 2002, for the years 2003 through 2007 and thereafter, excluding fees and interest due for spent nuclear fuel disposal costs of $253.6 million and unamortized premiums and discounts of $4.1 million are $56.9 million, $61.7 million, $88.7 million, $26.6 million, $8.3 million, and $1,852.4 million, respectively.
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 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 and a liquidity facility. For financial reporting purposes, these first mortgage bonds would not be considered outstanding 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, 2002 and 2001, $407.3 million of the PCRBs were outstanding. PSNH's obligation to repay each series of PCRBs is secured by bond insurance and the 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.
(b) The average effective interest rate on the variable-rate pollution control notes ranged from 1.2 percent to 1.7 percent for 2002 and 1.2 percent to 3.8 percent for 2001. NU's variable rate long-term debt maturities and cash sinking fund requirements are $178.5 million in 2021 and $62 million in 2031.
(c) For information regarding fees and interest due for spent nuclear fuel disposal costs, see Note 8C, "Commitments and Contingencies - Spent Nuclear Fuel Disposal Costs," to the consolidated financial statements.
Consolidated Statements of Income Taxes
For the Years Ended December 31,
(Thousands of Dollars) 2002 2001 2000
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The components of the federal and state income tax provisions are:
Current income taxes:
Federal $ 197,426 $244,501 $154,790
State 34,204 46,155 23,052
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Total current 231,630 290,656 177,842
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Deferred income taxes, net:
Federal (108,524) (80,968) 7,297
State (14,210) (15,644) (5,529)
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Total deferred (122,734) (96,612) 1,768
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Investment tax credits, net (26,592) (20,092) (17,885)
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Total income tax expense $ 82,304 $173,952 $161,725
====================================================================================================================================
Deferred income taxes are comprised of the tax effects of
temporary differences as follows:
Deferred tax asset associated with net operating losses $ -- $ 2,206 $ 1,563
Depreciation, leased nuclear fuel, settlement credits and disposal costs 89,621 (185,850) 9,514
Regulatory deferral (141,592) (33,187) (34,486)
Regulatory disallowance 345 2,323 --
Sale of generation assets (20,500) (225,019) --
Pension (1,720) 24,183 25,751
Loss on bond redemptions (1,084) 12,396 655
Securitized contract termination costs and other (23,044) 279,673 --
Contract settlements (14,991) 16,640 (4,442)
Other (9,769) 10,023 3,213
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Deferred income taxes, net $(122,734) $(96,612) $ 1,768
====================================================================================================================================
A reconciliation between income tax expense and the expected
tax expense at the statutory rate is as follows:
Expected federal income tax $ 81,400 $156,500 $133,413
Tax effect of differences:
Depreciation 10,404 5,313 2,882
Amortization of regulatory assets 13,540 5,748 16,835
Investment tax credit amortization (26,592) (20,092) (17,885)
State income taxes, net of federal benefit 12,996 19,832 11,390
Dividends received deduction (3,237) (3,382) (8,618)
Tax asset valuation allowance/reserve adjustments (1,310) (7,000) (2,136)
Merger-related expenditures -- (4,589) 5,829
Amortization of PSNH acquisition costs 1,426 4,512 9,946
Nondeductible stock expenses -- 12,388 --
Other, net (6,323) 4,722 10,069
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Total income tax expense $ 82,304 $173,952 $161,725
====================================================================================================================================
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The accompanying notes are an integral part of these consolidated financial statements.
Notes To Consolidated Financial Statements
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. About Northeast Utilities
Northeast Utilities (NU or the company) is the parent company of the Northeast
Utilities system. NU's regulated utilities furnish franchised retail electric
service in Connecticut, New Hampshire and western Massachusetts through three
wholly owned subsidiaries: The Connecticut Light and Power Company (CL&P),
Public Service Company of New Hampshire (PSNH) and Western Massachusetts
Electric Company (WMECO). Another wholly owned subsidiary, North Atlantic Energy
Corporation (NAEC), previously sold all of its entitlement to the capacity and
output of the Seabrook Station 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. Other subsidiaries include Holyoke Water
Power Company (HWP), a company engaged in the production of electric power, and
Yankee Energy System, Inc. (Yankee), the parent company of Yankee Gas Services
Company (Yankee Gas), Connecticut's largest natural gas distribution system.
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 NU's 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 operating subsidiaries are subject to further regulation for rates, accounting and other matters by the FERC and/or applicable state regulatory commissions.
NU Enterprises, Inc. (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 Select Energy, Inc., and subsidiary (Select Energy), a corporation engaged in the trading, marketing, transportation, storage, and sale of energy commodities, at wholesale and retail, in designated geographical areas; Northeast Generation Company (NGC), a corporation that acquires and manages generation facilities; Select Energy Services, Inc. and subsidiaries (SESI), a provider of energy management, demand-side management and related consulting services for commercial, industrial and institutional electric companies and electric utility companies, and; Northeast Generation Services Company and subsidiaries (NGS), a corporation that maintains and services fossil or hydroelectric facilities and provides third-party electrical, mechanical, and engineering contracting services.
In July 2002, the competitive energy subsidiaries acquired certain assets and assumed certain liabilities of Woods Electrical Co. Inc., (Woods Electrical), an electrical services company, and Woods Network Services, Inc. (Woods Network), a network products and services company for an aggregate adjusted purchase price of $16.3 million. Woods Electrical is wholly owned by NGS, and Woods Network is wholly owned by NUEI.
Another subsidiary is Mode 1 Communications, Inc. (Mode 1), an investor in a fiber-optic communications network.
Several wholly owned subsidiaries of NU provide support services for NU's companies and, in some cases, for other New England utilities. Northeast Utilities Service Company provides centralized accounting, administrative, engineering, financial, information resources, legal, operational, planning, purchasing, and other services to NU's companies. Until the sale of Seabrook on November 1, 2002, North Atlantic Energy Service Corporation (NAESCO) had operational responsibility for Seabrook. Three other subsidiaries construct, acquire or lease some of the property and facilities used by NU's companies.
B. Presentation
The consolidated financial statements of NU include the accounts of all
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 contingent liabilities 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.
C. New Accounting Standards
Energy Trading and Risk Management Activities: In June 2002, the Emerging Issues
Task Force (EITF) of the Financial Accounting Standards Board (FASB) reached a
consensus on EITF Issue No. 02-3, "Accounting for Contracts Involved in Energy
Trading and Risk Management Activities," requiring companies engaged in energy
trading activities to classify revenues and expenses associated with energy
trading contracts on a net basis in revenues, rather than recording revenues for
sales and expenses for purchases. While this consensus was subsequently
rescinded by the EITF on October 25, 2002, NU chose to adopt net reporting of
energy trading revenues and expenses for contracts that physically settle
effective July 1, 2002. Operating revenues and fuel, purchased and net
interchange power for the year ended December 31, 2002 reflect net reporting,
and the adoption of net reporting was applied retroactively to 2001 operating
revenues and fuel, purchased and net interchange power but had no effect on net
income.
The impact on previously reported amounts in 2001 is as follows:
(Millions of Dollars)
--------------------------------------------------- Operating Revenues: As previously reported $6,873.8 Impact of reclassification (905.6) --------------------------------------------------- As currently reported $5,968.2 =================================================== Fuel, Purchased and Net Interchange Power: As previously reported $4,541.3 Impact of reclassification (905.6) --------------------------------------------------- As currently reported $3,635.7 =================================================== |
Operating revenues and fuel, purchased and net interchange power for the year ended December 31, 2000 were not adjusted, as the impact of net reporting was not material to NU's consolidated results of operations in 2000.
On October 25, 2002, the EITF reached additional consensuses in EITF Issue No. 02-3. These consensuses supercede the consensuses the EITF reached in June 2002. The first consensus rescinds EITF Issue No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities for Energy Trading Activities," under which Select Energy previously accounted for energy trading activities. This consensus requires companies engaged in energy trading activities to discontinue fair value accounting effective January 1, 2003, for contracts that do not meet the definition of a derivative in Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended, effective January 1, 2003. NU adopted this consensus effective October 1, 2002. Management determined that there were no trading contracts subject to fair value accounting that did not meet the definition of a derivative in SFAS No. 133. Accordingly, there was no cumulative effect of an accounting change.
The second consensus requires that companies engaged in energy trading activities classify revenues and expenses associated with energy trading contracts on a net basis in revenues effective January 1, 2003. NU adopted net reporting effective July 1, 2002, before this consensus was reached by the EITF.
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 is effective on January 1, 2003, for NU. Management has completed its review process for potential asset retirement obligations (AROs) and has not identified any material AROs which have been incurred. However, management has identified certain removal obligations which arise in the ordinary course of business that either have a low probability of occurring or are not material in nature. 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.
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, 2002, NU maintained approximately $321 million in cost of removal regulatory liabilities, which are included in the accumulated provision for depreciation.
Stock-Based Compensation: In December 2002, the FASB issued SFAS No. 148,
"Accounting for Stock-Based Compensation - Transition and Disclosure." This
statement amends 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 stock-based employee compensation and
requires prominent disclosures in both annual and interim financial statements
about the method of accounting for stock-based employee compensation and the
effect of the method used on reported results. SFAS No. 148 is effective for
2002, and NU included the disclosures required by SFAS No. 148 in this annual
report. For the required disclosures, see Note 1K, "Summary of Significant
Accounting Policies - Stock-Based Compensation" and Note 4D, "Employee Benefits
- Stock-Based Compensation" to the consolidated financial statements. At this
time, NU has not elected to transition to the fair value-based method of
accounting for stock-based employee compensation.
Guarantees: In November 2002, the FASB issued Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others." Interpretation No. 45 requires that disclosures be made by a guarantor in its interim and annual financial statements about its obligations under certain guarantees that it has issued and clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. Interpretation No. 45 does not apply to certain guarantee contracts, such as residual value guarantees provided by lessees in capital leases, guarantees that are accounted for as derivatives, guarantees that represent contingent consideration in a business combination, guarantees issued between either parents and their subsidiaries or corporations under common control, a parent's guarantee of a subsidiary's debt to a third party, and a subsidiary's guarantee of the debt owed to a third party by either its parent or another subsidiary of that parent. The initial recognition and initial measurement provisions of Interpretation No. 45 are applicable to NU on a prospective basis to guarantees issued or modified after January 1, 2003. Currently, management does not expect the adoption of the initial recognition and initial measurement provisions of Interpretation No. 45 to have a material impact on NU's consolidated financial statements. The disclosure requirements in Interpretation No. 45 are effective for 2002. For further information regarding these disclosures, see Note 2, "Short-Term Debt" to the consolidated financial statements.
Consolidation of Variable Interest Entities: In January 2003, the FASB issued Interpretation No. 46, "Consolidation of Variable Interest Entities." Interpretation No. 46 addresses the consolidation and disclosure requirements for companies that hold an equity interest in a variable interest entity (VIE), regardless of the date on which the VIE was created. Interpretation No. 46 requires consolidation of a VIE's assets, liabilities and noncontrolling interests at fair value when a company is the primary beneficiary, which is defined as a company that absorbs a majority of the expected losses, risks and revenues from the VIE as a result of holding a contractual or other financial interest in the VIE. Consolidation is not required under Interpretation No. 46 for those companies that hold a significant equity interest in a VIE but are not the primary beneficiary. Interpretation No. 46 is effective for NU beginning in the third quarter of 2003. At December 31, 2002, NU held equity interests in various VIEs, for which NU was not the primary beneficiary, as NU does not absorb a majority of the expected losses, risks and revenues from the VIEs or provide a substantial portion of financial support. As a result, management does not expect the adoption of Interpretation No. 46 to have a material impact on NU's consolidated financial statements. For further information regarding NU's investments in its VIEs, see Note 1D, "Equity Investments and Jointly Owned Electric Utility Plant" to the consolidated financial statements.
Derivative Instruments: Effective January 1, 2001, NU adopted SFAS No. 133, as amended. All derivative instruments have been identified and recorded at fair value effective January 1, 2001. In addition, for those derivative instruments which are hedging an identified risk, NU has designated and documented all hedging relationships. For those contracts that do not meet the hedging requirements, the changes in fair value of those contracts were recognized currently in earnings.
D. Equity Investments and Jointly Owned Electric Utility Plant Regional Nuclear Generating Companies: CL&P, PSNH and WMECO own common stock in four regional nuclear companies (Yankee Companies). NU's ownership interests in the Yankee Companies at December 31, 2002 and 2001, which are accounted for on the equity method are 49 percent of the Connecticut Yankee Atomic Power Company (CYAPC), 38.5 percent of the Yankee Atomic Electric Company (YAEC), 20 percent of the Maine Yankee Atomic Power Company (MYAPC), and 17 percent of the Vermont Yankee Nuclear Power Corporation (VYNPC). NU's total equity investment in the Yankee Companies and its exposure to loss as a result of these investments at December 31, 2002 and 2001, is $48.9 million and $52.5 million, respectively. These investments are VIE's under FASB Interpretation No. 46. Excluding VYNPC, which sold its nuclear generating plant, each Yankee Company owns a single decommissioned nuclear generating plant. On July 31, 2002, VYNPC consummated the sale of its nuclear generating plant to a subsidiary of Entergy Corporation for approximately $180 million.
Seabrook: CL&P and NAEC together previously had a 40.04 percent joint ownership interest in Seabrook, a 1,148 megawatt nuclear generating unit. 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). At December 31, 2001, plant-in-service and the accumulated provision for depreciation for NU's share of Seabrook totaled $912.5 million and $840.6 million, respectively.
Hydro-Quebec: NU has a 22.66 percent equity ownership interest and an exposure to loss as a result of this investment totaling $12 million and $13.6 million at December 31, 2002 and 2001, respectively, in two companies that transmit electricity imported from the Hydro-Quebec system in Canada. This investment is a VIE under the FASB Interpretation No. 46.
Other Investments: NU also maintains certain cost method, equity method, and other investments in NEON Communications, Inc. (NEON), a provider of high-bandwidth fiber optic telecommunications services, 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 auto industry, R.M. Services, Inc. (RMS), a provider of consumer collection services for companies throughout the United States, and BMC Energy LLC (BMC), an operator of renewable energy projects. These investments have a combined total carrying value of $29.1 million and $54 million at December 31, 2002 and 2001, respectively. During 2002, after-tax impairment write-offs were recorded to reduce the carrying values of NEON, Acumentrics and RMS to their net realizable values. Excluding BMC, these investments are VIEs under FASB Interpretation No. 46, and NU's exposure to loss as a result of these investments totaled $24.4 million and $49.3 million at December 31, 2002 and 2001, respectively. In 2001, based on a reduction in its ownership share in NEON, NU changed from the equity method of accounting to the cost method of accounting for this investment.
E. Depreciation
The provision for depreciation is calculated using the straight-line method
based on the estimated remaining useful lives of depreciable utility
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 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. The depreciation rates for the
several classes of electric utility plant-in-service are equivalent to a
composite rate of 3.2 percent in 2002 and 3.1 percent in 2001 and 2000.
In 2002, the competitive energy subsidiaries 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 remaining 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's operating expenses decreased by approximately $5.1 million or $0.04 per share on a fully diluted basis in 2002.
In 2000, HWP discontinued SFAS No. 71, "Accounting for the Effect of Certain Types of Regulation," and recorded a charge to accumulated depreciation for the plant carrying value in excess of fair value for certain hydroelectric generation assets, which was recorded as an extraordinary loss. These assets were sold in the fourth quarter of 2001.
F. Revenues
Regulated utility revenues are based on rates approved by the state regulatory
commissions. These regulated rates are applied to customer's accounts based on
their use of energy. In general, rates can only be changed through formal
proceedings with the state regulatory commissions.
The determination of the energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is estimated. This unbilled revenue is estimated each month based on generation volumes, estimated customer usage by class, line losses, and applicable customer rates.
Competitive energy subsidiary revenues are recognized at different times for the different businesses. 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. Regulatory Accounting and Assets
The accounting policies of NU's regulated utilities 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.
CL&P's, PSNH's and WMECO's transmission and distribution businesses 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 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 regulatory assets are earning a return, except for securitized regulatory assets. The components of NU's regulatory assets are as follows:
At December 31,
(Millions of Dollars) 2002 2001
--------------------------------------------------------------------------------
Recoverable nuclear costs $ 85.4 $ 243.1
Securitized regulatory assets 1,891.8 2,004.1
Income taxes, net 331.9 301.3
Unrecovered contractual obligations 239.3 78.3
Recoverable energy costs, net 299.6 327.2
Other 62.0 333.5
--------------------------------------------------------------------------------
Totals $2,910.0 $3,287.5
================================================================================
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In March 2000, CL&P and WMECO completed the auction of certain hydroelectric generation assets with a book value of $129 million. NGC was the winning bidder in the auction and paid approximately $865.5 million for these assets. Restructuring legislation in both Connecticut and Massachusetts requires gains from the sale of generation to be used to reduce regulatory assets and other stranded costs. Since the entities to the transaction are all wholly owned by NU, a gain was not recognized. The purchase price of the hydroelectric generation assets is reflected in competitive energy property, plant and equipment, and NGC is depreciating the plant assets over their estimated useful life.
In March 2001, CL&P and WMECO sold their ownership interests in the Millstone units. The gain on these sales in the amount of approximately $521.6 million and $119.8 million, respectively, for CL&P and WMECO were used to offset recoverable nuclear costs, resulting in a total unamortized balance of $13.1 million and $158.1 million at December 31, 2002 and 2001, respectively. Additionally, PSNH recorded a regulatory asset in conjunction with the sale of the Millstone units with an unamortized balance of $36.8 million and $40.5 million at December 31, 2002 and 2001, which is also included in recoverable nuclear costs. Also included in recoverable nuclear costs for 2002 and 2001 are $35.5 million and $44.5 million, respectively, primarily related to Millstone 1 recoverable nuclear costs associated with the recoverable portion of the undepreciated plant and related assets.
In 2000, PSNH discontinued the application of SFAS No. 71 for its generation business and created a regulatory asset for Seabrook over market generation. In April 2001, PSNH issued rate reduction bonds in the amount of $525 million. PSNH used the majority of this amount to buydown its power contracts with NAEC. The Seabrook over market generation was securitized at that time and is reflected in securitized regulatory assets at December 31, 2002 and 2001. On May 22, 2001, the Governor of New Hampshire signed a bill modifying the state's electric utility industry restructuring laws delaying the sale of PSNH's fossil and hydroelectric generation assets until at least February 1, 2004. Since then there has been no regulatory action, 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 of and on these generation assets, as well as all operating expenses, PSNH again meets the criteria for the application of SFAS No. 71 for the generation portion of its business. Accordingly, costs related to the 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.
In March 2001, CL&P issued $1.4 billion in rate reduction certificates and used $1.1 billion of those proceeds to buyout or buydown certain contracts with independent power producers. In May 2001, WMECO issued $155 million in rate reduction certificates and used $80 million of those proceeds to buyout an independent power producer contract. In January 2002, PSNH issued an additional $50 million in rate reduction bonds and used the proceeds from this issuance to repay short-term debt that was incurred to buyout a purchased-power contract in December 2001. The majority of the payments to buyout or buydown these contracts were recorded as securitized regulatory assets. CL&P also securitized a portion of its SFAS No. 109 regulatory asset.
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. These 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 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.
CL&P, PSNH, WMECO, and NAEC, under the Energy Policy Act of 1992 (Energy Act), 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) when they owned nuclear generating plants. 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 are currently recovering these costs through rates. At December 31, 2002 and 2001, NU's total D&D Assessment deferrals were $21.9 million and $28.1 million, respectively, and have been recorded as recoverable energy costs, net.
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 and $59 million at December 31, 2002 and 2001, respectively, which have been recorded as recoverable energy costs, net. On July 26, 2001, the Connecticut Department of Public Utility Control (DPUC) authorized CL&P to assess a charge of approximately $0.002 per kilowatt-hour (kWh) from August 2001 through December 2003 to collect these 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, 2002 and 2001, PSNH had $179.6 million and $183.3 million, respectively, of recoverable energy costs deferred under the FPPAC, including previous deferrals of purchases from independent power producers. 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 independent power producers that had previously been included in the FPPAC. These costs are treated as Part 3 stranded costs and amounted to $62.1 million and $68.1 million at December 31, 2002 and 2001, 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 in or refunded in future periods. These amounts are recorded as recoverable energy costs, net.
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, "Accounting for Income Taxes."
The tax effect of temporary differences, including timing differences accrued under previously approved accounting standards, that give rise to the accumulated deferred tax obligation is as follows:
At December 31,
(Millions of Dollars) 2002 2001
--------------------------------------------------------------------------------
Accelerated depreciation and
other plant-related differences $ 493.7 $ 577.5
Regulatory assets:
Nuclear stranded investment
and other asset divestitures 270.9 324.6
Securitized contract termination
costs and other 255.4 279.7
Income tax gross-up 194.6 190.0
Other 221.9 119.6
--------------------------------------------------------------------------------
Totals $1,436.5 $1,491.4
================================================================================
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I. Cash and Cash Equivalents
Cash and cash equivalents includes cash on hand and short-term cash investments
which are highly liquid in nature and have original maturities of three months
or less.
J. Accounting for Competitive Energy Contracts The accounting treatment for energy contracts entered into by Select Energy varies between contracts and depends on the intended use of the particular contract and on whether or not the contracts are derivatives.
Nonderivative 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, are also recorded at the point of delivery under accrual accounting.
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. Other contracts that are derivatives that do not qualify as normal purchases and sales or hedges are also recorded on the consolidated balance sheets at fair value with changes in fair value reflected in operating revenues for sales and fuel, purchased and net interchange power for purchases.
Revenues and expenses for derivative contracts that are not entered into for trading purposes are recorded at gross amounts when these transactions settle.
Competitive energy contracts that are hedging an underlying transaction and qualify as cash flow hedges are recorded on the consolidated balance sheets at fair value with changes in fair value generally reflected in 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 accounting for competitive energy contracts, see Note 3, "Derivative Instruments, Market Risk and Risk Management," to the consolidated financial statements.
K. Stock-Based Compensation
At December 31, 2002, NU maintains an Employee Stock Purchase Plan (ESPP) and
other long-term incentive plans which are described more fully in Note 4D,
"Employee Benefits - Stock-Based Compensation" to the consolidated financial
statements. NU accounts for these plans under the recognition and measurement
principles of Accounting Principles Board Opinion No. 25, "Accounting for Stock
Issued to Employees," and related interpretations. No stock-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. 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 stock-based employee
compensation.
(Millions of Dollars, For the Years Ended December 31, except per share amounts) 2002 2001 2000 -------------------------------------------------------------------------------- Net income/(loss), as reported $152.1 $243.5 $(28.6) Total stock-based employee compensation expense determined under fair value-based method for all awards, net of related tax effects (5.3) (4.4) (5.3) -------------------------------------------------------------------------------- Pro forma net income/(loss) $146.8 $239.1 $(33.9) -------------------------------------------------------------------------------- Earnings/(loss) per share: Basic - as reported $ 1.18 $ 1.80 $(0.20) Basic - pro forma $ 1.14 $ 1.76 $(0.24) Diluted - as reported $ 1.18 $ 1.79 $(0.20) Diluted - pro forma $ 1.14 $ 1.76 $(0.24) ================================================================================ |
L. Other Income/(Loss), Net
The pre-tax components of NU's other income/(loss), net items are as follows:
For the Years Ended December 31,
(Millions of Dollars) 2002 2001 2000
--------------------------------------------------------------------------------
Seabrook-related gains $ 38.7 $ -- $ --
Investment write-downs (18.4) -- --
Gain related to Millstone sale -- 201.9 --
Loss on share repurchase contracts -- (35.4) --
Investment income 25.4 19.3 42.4
Other, net (1.9) 1.8 (56.7)
--------------------------------------------------------------------------------
Totals $ 43.8 $187.6 $(14.3)
================================================================================
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Other, net in 2000 primarily relates to nuclear related costs and adjustments to NU's environmental reserves.
M. Supplemental Cash Flow Information
In conjunction with the Yankee acquisition on March 1, 2000, common stock was
issued and debt was assumed as follows (millions of dollars):
Fair value of assets acquired,
net of liabilities assumed $ 712.5
Debt assumed (234.0)
NU common shares issued (217.1)
--------------------------------------------------------------------------------
Cash paid $ 261.4
================================================================================
For the Years Ended December 31,
(Millions of Dollars) 2002 2001 2000
--------------------------------------------------------------------------------
Cash paid during the year for:
Interest, net of amounts capitalized $259.9 $275.3 $269.7
Income taxes $114.4 $321.0 $253.4
================================================================================
|
2. SHORT-TERM DEBT
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. Currently, SEC authorization allows NU, CL&P, WMECO, and Yankee Gas to incur total short-term borrowings up to a maximum of $400 million, $375 million, $250 million, and $100 million, respectively. In addition, the charter of CL&P contains preferred stock provisions restricting the amount of unsecured debt that CL&P may incur. At December 31, 2002, CL&P's charter permits CL&P to incur $480 million of additional unsecured debt. PSNH is authorized by the New Hampshire Public Utilities Commission (NHPUC) to incur short-term borrowings up to a maximum of $100 million. Prior to the sale of Seabrook, NAEC had NHPUC authorization to incur short-term borrowings up to a maximum of $260 million. Currently, NAEC has no plans to incur any future short-term borrowings.
Regulated Companies Credit Agreement: On November 12, 2002, CL&P, PSNH, WMECO, and Yankee Gas entered into a 364-day unsecured revolving credit facility for $300 million. This facility replaced a $350 million facility for CL&P, PSNH, WMECO and Yankee Gas, which expired on November 15, 2002. CL&P may draw up to $150 million under the facility and PSNH, WMECO and Yankee Gas each may draw up to $100 million, subject to the $300 million maximum borrowing limit under the facility. Unless extended, the credit facility will expire on November 11, 2003. At December 31, 2002 and 2001, there were $7 million and $160.5 million, respectively, in borrowings under these facilities.
NU Parent Credit Agreement: NU replaced its $300 million 364-day unsecured revolving credit facility, which was to expire on November 15, 2002, with a 364-day unsecured revolving credit facility on November 12, 2002. This facility provides a total commitment of $350 million, which is available subject to two overlapping sub-limits. First, subject to the notional amount of any letters of credit outstanding, amounts up to $350 million are available for advances. Second, subject to the advances outstanding, letters of credit may be issued in notional amounts up to $250 million, an increase of $50 million over the prior facility in the name of NU or any of its subsidiaries. Unless extended, this credit facility will expire on November 11, 2003. At December 31, 2002 and 2001, there were $49 million and $40 million, respectively, in borrowings under these facilities. With regard to credit support, NU had $6.7 million and $45 million, respectively, in letters of credit issued under these facilities at December 31, 2002 and 2001.
NAEC Credit Agreement: On November 9, 2001, NAEC entered into an unsecured 364-day term credit agreement for $90 million. The term credit agreement contained a mandatory prepayment provision requiring 100 percent prepayment of the aggregate amount outstanding within two days of the sale of Seabrook. On November 1, 2002, NAEC consummated the sale of its ownership interest in Seabrook and repaid its $90 million in borrowings under this credit agreement. The agreement expired on November 8, 2002. At December 31, 2001, there were $90 million in borrowings under this term credit agreement.
Under the aforementioned 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, 2002 and 2001, were 4.25 percent and 3.38 percent, respectively.
These credit agreements provide that NU and its subsidiaries must comply with certain financial and nonfinancial covenants as are customarily included in such agreements, including, but not limited to, consolidated debt ratios and interest coverage ratios. The parties to the credit agreements currently are and expect to remain in compliance with these covenants.
Guarantees: NU provides credit assurance in the form of guarantees and letters of credit in the normal course of business for the financial performance obligations of certain of its competitive energy subsidiaries of which most are revocable with no term specifications. NU would be required to perform under these guarantees in the event of non-performance under these obligations by the competitive energy subsidiaries. NU currently has authorization from the SEC to provide up to $500 million of guarantees through September 30, 2003, and has applied for authority to increase this amount to $750 million. At December 31, 2002, payments guaranteed by NU, primarily on behalf of its competitive businesses, totaled $183.1 million. Additionally, NU had $6.7 million of letters of credit outstanding at December 31, 2002 and in conjunction with its investment in RMS, NU guarantees a $3 million line of credit through 2005. Also, in conjunction with its investment in SESI, NU guarantees up to $30 million of SESI debt under arrangements with a third-party financing of long-term receivables.
3. DERIVATIVE INSTRUMENTS, MARKET RISK AND RISK MANAGEMENT
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 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 trading
activities, see Note 1C, "Summary of Significant Accounting Policies - New
Accounting Standards," to the consolidated financial statements.
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. Also during 2002, new cash flow hedge transactions were entered into which hedge cash flows through 2005. As a result of these new transactions and market value changes since January 1, 2002, 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, and it is estimated that $9.3 million of this balance, net of tax, will be reclassified as an increase to earnings within the next twelve months. Cash flows from the hedge contracts are reported in the same category as cash flows from the underlying hedged transaction.
There have been changes to interpretations of SFAS No. 133, and the FASB continues to consider changes and amendments which could affect the way NU records and discloses derivative and hedging activities in the future.
During 2001, a positive $4.5 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 $1.3 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 2001, new cash flow hedge transactions were entered into which hedge cash flows through 2027. As a result of these new transactions and market value changes since January 1, 2001, other comprehensive income decreased by $36.9 million, net of tax. Accumulated other comprehensive income at December 31, 2001, was a negative $36.9 million, net of tax (decrease to equity), relating to hedged transactions, and it is estimated that $29.4 million of this balance, net of tax, will be reclassified as a decrease to earnings within the next twelve months. Cash flows from the hedge contracts are reported in the same category as cash flows from the underlying hedged transaction.
The tables below summarize the derivative assets and liabilities at December 31, 2002 and 2001. These amounts do not include premiums paid, which are recorded as prepayments and amounted to $26.6 million and $8.3 million at December 31, 2002 and 2001, respectively. These amounts also do not include premiums received, which are recorded as liabilities and amounted to $29.5 million and $44.2 million at December 31, 2002 and 2001, respectively. These amounts relate primarily to energy trading activities.
At December 31, 2002
(Millions of Dollars) Assets Liabilities Total
--------------------------------------------------------------------------------
Competitive Energy Subsidiaries:
Trading $102.9 $ (61.9) $41.0
Nontrading 2.9 -- 2.9
Hedging 22.8 (2.0) 20.8
Regulated Gas Utility:
Hedging 2.3 -- 2.3
--------------------------------------------------------------------------------
Total $130.9 $ (63.9) $67.0
================================================================================
At December 31, 2001
(Millions of Dollars) Assets Liabilities Total
--------------------------------------------------------------------------------
Competitive Energy Subsidiaries:
Trading $147.2 $ (90.8) $56.4
Hedging 2.9 (58.4) (55.5)
Regulated Gas Utility:
Hedging 0.2 (2.3) (2.1)
NU Parent:
Hedging -- (0.1) (0.1)
--------------------------------------------------------------------------------
Total $150.3 $(151.6) $(1.3)
================================================================================
|
Competitive Energy Subsidiaries Trading: As a market participant in the Northeast United States, Select Energy conducts 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 exposure. 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, 2002 and 2001 were assets of $41 million and $56.4 million, respectively.
The competitive energy subsidiaries 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 quotes; and bilateral contracts for the purchase or sale of electricity or natural gas, the fair value of which is modeled using available information from external sources based on recent transactions and validated with a gas forward curve and an estimated heat rate conversion. The competitive energy subsidiaries trading portfolio also includes transmission congestion contracts. The fair value of certain transmission congestion contracts is based on market inputs. Market information for other transmission congestion contracts is not available, and those contracts cannot be reliably valued. Management believes the amounts paid for these contracts are equal to their fair value and has established a valuation reserve for changes in fair value in excess of cost.
Management conducted a thorough review of the contracts in the trading portfolio in order to adopt EITF Issue No. 02-3 as of October 1, 2002. Based on this review, the significant changes in the energy trading market, and the change in the focus of the energy trading business, certain long-term derivative energy contracts that were previously included in the trading portfolio and valued at $33.9 million as of November 30, 2002 were determined to be nontrading and subsequently designated as normal purchases and sales, as defined by SFAS No. 133, as of that date. Management was able to make this designation based on the high probability that these contracts will result in physical delivery. The impact of the normal purchases and sales designation is that these contracts were adjusted to fair value as of November 30, 2002 and were not and will not be adjusted subsequently for changes in fair value. The $33.9 million carrying value as of November 30, 2002 was reclassified from trading derivative assets to other long-term assets and will be amortized on a straight-line basis to fuel, purchased and net interchange power expense over the remaining terms of the contracts, which extend to 2011.
Competitive Energy Subsidiaries Nontrading: Nontrading derivative contracts are for delivery of energy related to the competitive energy subsidiaries' retail and wholesale marketing activities. These contracts are not entered into for trading purposes, but are subject to fair value accounting because these contracts are derivatives that cannot be designated as normal purchases or sales, as defined by SFAS No. 133. 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 the normal purchase and sale designation was not elected by management. The fair value of nontrading derivatives was an asset of $2.9 million at December 31, 2002. The competitive energy subsidiaries held no nontrading derivatives at December 31, 2001.
Competitive Energy Subsidiaries 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 retail supply 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 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 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 2004. Select Energy has hedged its gas supply risk under these agreements through NYMEX futures contracts. Under these contracts, which also extend through 2004, the purchase price of a specified quantity of gas is effectively fixed over the term of the gas service agreements. At December 31, 2002 and 2001, the NYMEX futures contracts had notional values of $30.9 million and $91.3 million, respectively, and were recorded at fair value as a derivative asset of $12.2 million at December 31, 2002, and as a derivative liability of $24.5 million at December 31, 2001.
During 2002, Select Energy determined that cash flow hedges related to the CL&P standard offer service contract were ineffective. These hedges were natural gas derivatives that were used to hedge off-peak electricity purchases for CL&P standard offer sales. As a result of this ineffectiveness, Select Energy transferred $3.9 million related to these cash flow hedges from accumulated other comprehensive income to fuel, purchased and net interchange power expense. Also in 2002, Select Energy terminated these cash flow hedges and realized pre-tax income of $5.6 million. In 2001, Select Energy had a liability related to these standard offer contract hedges of $31.3 million with a corresponding accumulated other comprehensive loss.
In the fourth quarter of 2002, Select Energy designated new hedges with a derivative asset value of $5.6 million as hedging full requirements contracts in the New York market.
Regulated Gas Utility 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 two unaffiliated customers is effectively fixed over the term of the gas service agreements with those customers for a period of time not extending beyond 2005. At December 31, 2002 and 2001, the commodity swap agreement had notional values of $10.7 million and $16.9 million, respectively, and was recorded at fair value as a derivative asset of $2.3 million at December 31, 2002, and as a derivative liability of $2.3 million at December 31, 2001.
In 2001 Yankee Gas also held two interest rate swaps with a fair value derivative asset amount of $0.2 million. These swaps were terminated in 2002.
NU Parent Hedging: At December 31, 2001, NU Parent maintained a treasury interest rate lock agreement, which was recorded as a fair value liability of $0.1 million. This agreement was terminated in 2002.
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.
Competitive Energy Subsidiaries Trading Portfolio: At December 31, 2002, Select Energy has calculated the market price resulting from a 10 percent unfavorable change in forward market prices. That 10 percent change would result in approximately a $2.6 million decline in the fair value of the Select Energy trading portfolio. In the normal course of business, Select Energy also faces risks that are either nonfinancial or non-quantifiable. Such risks principally include credit risk, which is not reflected in this sensitivity analysis.
Competitive Energy Subsidiaries Retail and Wholesale Marketing Portfolio: When conducting sensitivity analyses of the change in the fair value of Select Energy's electricity, natural gas and oil nontrading derivatives 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 account 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 retail and wholesale marketing portfolio, which includes cash flow hedges and electricity, natural gas and oil contracts, assuming a 10 percent unfavorable change in forward market prices. At December 31, 2002, an unfavorable 10 percent change in market price would have resulted in a decline in fair value of approximately $4.4 million.
The impact of a change in electricity, natural gas and oil prices on Select Energy's retail and wholesale marketing portfolio at December 31, 2002, is not necessarily representative of the results that will be realized when these contracts are physically delivered.
C. Other Risk Management Activities
Interest Rate Risk Management: NU manages its interest rate risk exposure by
maintaining a mix of fixed and variable rate debt. At December 31, 2002,
approximately 79 percent of NU's long-term debt, including the current portion
and fees and interest due for spent nuclear fuel disposal costs, is at a fixed
interest rate. Fixed interest rate debt is subject to interest rate risk in a
falling interest rate environment. 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, annual
interest expense would have increased by $4.9 million. At December 31, 2002, NU
does not have any derivative contracts outstanding to manage interest rate risk.
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 independent power producers, 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.
NU's regulated utilities have a lower level of credit risk related to providing electric and gas distribution service than NU's competitive energy subsidiaries.
Credit risks and market risks at the competitive energy subsidiaries 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.
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 conditions (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 NU entering into trading activities. The appropriateness of these limits is subject to continuing review. Concentrations among these counterparties may impact NU'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.
4. EMPLOYEE BENEFITS
A. Pension Benefits and Postretirement Benefits Other Than Pensions Pension Benefits: NU's subsidiaries participate in a uniform noncontributory defined benefit retirement plan (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, approximately 30 percent of which was credited to utility plant, was $73.4 million in 2002, $101 million in 2001, and $90.9 million in 2000. These amounts exclude pension settlements, curtailments and net special termination income of $22.2 million in 2002, expense of $2.6 million in 2001, and income of $7 million in 2000.
Pension income attributable to earnings is as follows:
For the Years Ended December 31,
(Millions of Dollars) 2002 2001 2000
--------------------------------------------------------------------------------
Pension income before
settlements, curtailments
and special termination benefits $(73.4) $(101.0) $(90.9)
Net pension income
capitalized as utility plant (a) 22.0 30.3 27.3
--------------------------------------------------------------------------------
Net pension income before
settlements, curtailments
and special termination benefits (51.4) (70.7) (63.6)
Settlements, curtailments and
special termination benefits
reflected in earnings -- 7.5 --
--------------------------------------------------------------------------------
Total pension income
included in earnings $(51.4) $ (63.2) $(63.6)
================================================================================
|
(a) Net pension income capitalized as utility plant was calculated utilizing an average of 30 percent.
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. 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 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 and $6.6 million of curtailment income and $0.4 million of special termination benefits income in 2000.
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 NU's Plan and provides special provisions. Eligible employees include non-bargaining unit employees or employees belonging to a collective bargaining unit that has agreed to accept the VRP who are active participants in NU's Plan at January 1, 2002, and that have been 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. NU believes that the cost of the VRP is probable of recovery through regulated utility rates, and accordingly, 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 five 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. 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 annually funds postretirement costs through external trusts with amounts that have been rate-recovered and which also are tax deductible.
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 and special termination benefits expense totaling $11.9 million in connection with the VSP. This amount was recorded as a regulatory asset and collected through regulated utility rates in 2002.
Additionally, in conjunction with the divestiture of its generation assets, NU recorded $0.4 million in special termination benefits income in 2000.
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.
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) 2002 2001 2002 2001
------------------------------------------------------------------------------------------------------------------------------------
Change in benefit obligation
Benefit obligation at beginning of year $(1,687.6) $(1,670.9) $(400.0) $(335.3)
Service cost (37.2) (35.7) (6.2) (6.2)
Interest cost (119.8) (119.7) (29.2) (27.2)
Plan amendment (11.4) -- 34.2 --
Actuarial loss (117.7) (72.1) (44.0) (76.2)
Benefits paid - excluding lump sum payments 97.3 94.5 44.0 38.0
Benefits paid - lump sum payments 50.2 133.8 -- --
Curtailments and settlements 44.5 75.8 3.4 6.9
Special termination benefits (8.1) (93.3) -- --
------------------------------------------------------------------------------------------------------------------------------------
Benefit obligation at end of year $(1,789.8) $(1,687.6) $(397.8) $(400.0)
====================================================================================================================================
Change in plan assets
Fair value of plan assets at beginning of year $ 1,990.4 $ 2,319.4 $ 171.1 $ 197.6
Actual return on plan assets (213.1) (100.7) (14.4) (17.1)
Employer contribution -- -- 35.0 28.6
Plan asset transfer in 2.5 -- -- --
Benefits paid - excluding lump sum payments (97.3) (94.5) (44.0) (38.0)
Benefits paid - lump sum payments (50.2) (133.8) -- --
------------------------------------------------------------------------------------------------------------------------------------
Fair value of plan assets at end of year $ 1,632.3 $ 1,990.4 $ 147.7 $ 171.1
====================================================================================================================================
Funded status at December 31 $ (157.5) $ 302.8 $(250.1) $(228.9)
Unrecognized transition (asset)/obligation (2.6) (3.6) 118.5 159.1
Unrecognized prior service cost 70.1 72.8 (5.9) --
Unrecognized net loss/(gain) 418.9 (139.6) 124.8 55.4
------------------------------------------------------------------------------------------------------------------------------------
Prepaid/(accrued) benefit cost $ 328.9 $ 232.4 $ (12.7) $ (14.4)
====================================================================================================================================
The following actuarial assumptions were used in calculating the plans' year end
funded status:
At December 31,
Pension Benefits Postretirement Benefits
-------------------------------------------------------------------
2002 2001 2002 2001
------------------------------------------------------------------------------------------------------------------------------------
Discount rate 6.75% 7.25% 6.75% 7.25%
Compensation/progression rate 4.00% 4.25% 4.00% 4.25%
Health care cost trend rate (a) N/A N/A 10.00% 11.00%
====================================================================================================================================
|
(a) The annual per capita cost of covered health care benefits was assumed to decrease to 5.00 percent by 2007.
The components of net periodic benefit (income)/expense are as follows:
For the Years Ended December 31,
Pension Benefits Postretirement Benefits
----------------------------------------------------------------------------
(Millions of Dollars) 2002 2001 2000 2002 2001 2000
------------------------------------------------------------------------------------------------------------------------------------
Service cost $ 37.2 $ 35.7 $ 41.2 $ 6.2 $ 6.2 $ 6.8
Interest cost 119.8 119.7 118.5 29.2 27.2 23.7
Expected return on plan assets (204.9) (214.1) (205.1) (16.6) (17.0) (14.1)
Amortization of unrecognized net
transition (asset)/obligation (1.4) (1.5) (1.4) 13.6 14.5 15.1
Amortization of prior service cost 7.7 6.9 7.9 (0.1) -- --
Amortization of actuarial gain (31.8) (47.7) (52.0) -- -- --
Other amortization, net -- -- -- 2.2 (2.6) (4.3)
------------------------------------------------------------------------------------------------------------------------------------
Net periodic (income)/expense - before settlements,
curtailments and special termination benefits (73.4) (101.0) (90.9) 34.5 28.3 27.2
------------------------------------------------------------------------------------------------------------------------------------
Settlement income -- (26.0) -- -- -- --
Curtailment (income)/expense (30.3) (64.7) (6.6) -- 3.3 --
Special termination benefits expense/(income) 8.1 93.3 (0.4) (1.2) 8.6 (0.4)
------------------------------------------------------------------------------------------------------------------------------------
Total - settlements, curtailments and special
termination benefits (22.2) 2.6 (7.0) (1.2) 11.9 (0.4)
------------------------------------------------------------------------------------------------------------------------------------
Total - net periodic (income)/expense $ (95.6) $ (98.4) $(97.9) $ 33.3 $ 40.2 $ 26.8
====================================================================================================================================
|
For calculating pension and postretirement benefit income and expense amounts, the following assumptions were used:
For the Years Ended December 31,
Pension Benefits Postretirement Benefits
----------------------------------------------------------------------------
2002 2001 2000 2002 2001 2000
------------------------------------------------------------------------------------------------------------------------------------
Discount rate 7.25% 7.50% 7.75% 7.25% 7.50% 7.75%
Expected long-term rate of return 9.25% 9.50% 9.50% N/A N/A N/A
Compensation/progression rate 4.25% 4.50% 4.75% 4.25% 4.50% 4.75%
Long-term rate of return -
Health assets, net of tax N/A N/A N/A 7.25% 7.50% 7.50%
Life assets N/A N/A N/A 9.25% 9.50% 9.50%
====================================================================================================================================
|
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 One
Percentage Percentage
Point Point
(Millions of Dollars) Increase Decrease
--------------------------------------------------------------------------------
Effect on total service and
interest cost components $ 0.9 $ (0.8)
Effect on postretirement
benefit obligation $12.2 $(11.0)
================================================================================
|
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.
Pension and trust assets are invested primarily in domestic and international equity securities and bonds.
The trust holding the health plan assets is 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
$11.1 million in 2002, $11.7 million in 2001, and $13.6 million in 2000.
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 2001, NU declared a $0.10 per share
quarterly dividend. During the third quarter of 2001 through the second quarter
of 2002, NU declared a $0.125 per share quarterly dividend. NU declared a
$0.1375 per share dividend during the third and fourth quarters of 2002.
In 2002 and 2001, the ESOP trust issued 607,475 and 546,610 of NU common shares, respectively, to satisfy 401(k) Savings Plan obligations to employees. At December 31, 2002 and 2001, total allocated ESOP shares were 7,008,784 and 6,401,309, respectively, and total unallocated ESOP shares were 3,791,401 and 4,398,876, respectively. The fair market value of unallocated ESOP shares at December 31, 2002 and 2001, was $57.5 million and $77.6 million, respectively.
D. Stock-Based Compensation
Employee Share Purchase Plan: Since July 1998, NU has maintained an ESPP for all
eligible employees. Under the ESPP, NU common shares were purchased at 6-month
intervals at 85 percent of the lower of the price on the first or last day of
each 6-month period. Employees may purchase shares having a value not exceeding
25 percent of their compensation as of the beginning of the purchase period.
Effective January 1, 2001, the ESPP was terminated because of a pending merger.
In the second quarter of 2001, a new ESPP was adopted by NU's Board of Trustees
and approved by NU's shareholders. During 2002, employees purchased 188,774
shares at discounted prices of $14.15 and $15.39. At December 31, 2002,
1,811,226 shares remained registered for future issuance under the ESPP.
Incentive Plans: NU has long-term incentive plans authorizing various types of awards, including stock options and performance units, to be made to eligible employees and board members. 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 stock-based compensation cost is reflected in net income. A liability of $1.3 million was recorded at December 31, 2002, for the fair value of the performance units earned. Under the Northeast Utilities Incentive Plan (Incentive Plan), the number of shares which may be utilized for or made subject to issuance pursuant to grants and awards granted 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, 2002 and 2001, NU had 2,440,339 and 2,692,633 shares of common stock, respectively, registered for issuance under the Incentive Plan.
Stock option transactions for 2002, 2001 and 2000, including those options acquired in connection with the Yankee merger, are as follows:
Exercise Price Per Share
---------------------------------------------
Options Range Weighted Average
------------------------------------------------------------------------------------------------------------------------------------
Outstanding - December 31, 1999 1,826,256 $ 9.6250 - $21.1250 $14.0585
Granted 669,470 $18.4375 - $22.2500 $18.7029
Yankee merger 10,167 $ 9.3640 - $12.6888 $10.7653
Exercised (43,750) $14.9375 - $19.5000 $16.0658
Forfeited and cancelled (28,281) $14.9375 - $19.5000 $16.6515
------------------------------------------------------------------------------------------------------------------------------------
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
====================================================================================================================================
Exercisable - December 31, 2000 1,298,339 $ 9.3640 - $22.2500 $14.2021
------------------------------------------------------------------------------------------------------------------------------------
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
====================================================================================================================================
|
In 1997, 500,000 options with a weighted average exercise price of $9.625 were granted. These options, which are all exercisable at December 31, 2002, have a remaining contractual life of 4.63 years. Excluding these options from those outstanding at December 31, 2002, 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.
NU has also made several small grants of restricted stock and other incentive-based stock compensation under the Incentive Plan. During 2002, 2001 and 2000, $1 million, $1.2 million and $1.9 million, respectively, was expensed related to this stock-based compensation.
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:
2002 2001 2000
--------------------------------------------------------------------------------
Risk-free interest rate 4.86% 5.34% 6.56%
Expected life 10 years 10 years 10 years
Expected volatility 23.71% 25.47% 26.15%
Expected dividend yield 2.11% 2.11% 1.82%
================================================================================
|
The weighted average grant date fair values of options granted during 2002, 2001 and 2000 were $5.64, $6.94 and $7.50, respectively. The weighted average remaining contractual lives for those options outstanding at December 31, 2002 and 2001 are 7.50 years.
For further information regarding stock-based compensation, see Note 1C, "Summary of Significant Accounting Policies - New Accounting Standards," and Note 1K, "Summary of Significant Accounting Policies - Stock-Based Compensation," to the consolidated financial statements.
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 $20.1 million and $18 million at December 31, 2002 and 2001, respectively, represents NU's actuarially determined obligation under the SERP. For information regarding the SERP investments, see Note 9, "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 $32.2 million and $25.2 million at December 31, 2002 and 2001, respectively.
5. GOODWILL AND OTHER INTANGIBLE ASSETS
Effective January 1, 2002, NU adopted SFAS No. 142, "Goodwill and Other Intangible Assets," which ceases 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 upon adoption of SFAS No. 142 and at least annually thereafter by applying a fair value-based test. Under SFAS No. 142, 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.
On July 1, 2002, the competitive energy subsidiaries acquired certain assets and assumed certain liabilities of Woods Electrical, an electrical services company and Woods Network, a network products and services company, for an aggregate adjusted purchase price of $16.3 million. The aggregate adjusted purchase price consisted of $4.2 million of tangible net assets, $0.1 million of intangible assets subject to amortization, consisting of customer backlog and employment related agreements, $6.8 million of indefinite lived intangible assets not subject to amortization consisting of $3.8 million associated with customer relationships acquired and $3 million associated with tradenames acquired, and $5.2 million of goodwill. The customer backlog and employment related agreements are being amortized over periods of one and three years, respectively, and have a weighted average amortization period of 1.6 years. This purchase price allocation is preliminary and has been adjusted since the acquisition date. Financial results of the acquired companies are included in NU's results of operations since July 1, 2002. The goodwill recognized in these transactions in the aggregate amount of $5.2 million was assigned to the competitive energy subsidiaries reportable segment and is expected to be fully deductible for tax purposes. Additionally, as part of these purchase agreements, an additional payment of not more than $9.2 million would be contingently payable by 2005 if certain earnings targets are met. Any contingent payments made will be accounted for as part of the purchase price.
NU's reporting units that maintain goodwill are generally consistent with the
operating segments underlying the reportable segments identified in Note 13,
"Segment Information," to the consolidated financial statements. During the
fourth quarter of 2002, consistent with changes in the way management reviews
the operating results of its reporting units, NU's reporting units under the
competitive energy subsidiaries reportable segment were revised to include: 1)
the wholesale marketing reporting unit, 2) the retail marketing reporting unit,
3) the trading reporting unit, and 4) the services reporting unit. The wholesale
marketing, retail marketing and trading reporting units are comprised of the
operations of Select Energy, NGC and HWP, and the services reporting unit is
comprised of the operations of SESI, NGS and its newly acquired subsidiary Woods
Electrical, Woods Network, and the nonenergy related subsidiaries of Yankee,
including YESCO. As a result, NU's revised reporting units that maintain
goodwill are as follows: Yankee Gas, classified under the regulated utilities -
gas reportable segment, the wholesale and retail marketing reporting unit and
the services reporting unit which are both classified under the competitive
energy subsidiaries reportable segment. The goodwill balances of these reporting
units are included in the table herein.
On November 30, 2001, Select Energy acquired Niagara Mohawk Energy Marketing, Inc. (NMEM) for $31.7 million. NMEM was subsequently renamed Select Energy New York, Inc. (SENY). During 2002, as a result of subsequent adjustments to SENY's purchase price allocation as a result of changes in the fair value of the assets and liabilities acquired, $3.2 million of goodwill was recorded. This goodwill amount is included in the wholesale and retail marketing reporting unit at December 31, 2002.
NU has completed its initial and subsequent impairment analyses, on January 1, 2002 and October 1, 2002, respectively, for all reporting units that maintain goodwill under SFAS No. 142. YESCO holds a note from an entity that purchased certain YESCO assets. Cash flows for YESCO support the investment but not the goodwill recorded.
As a result, in 2002, a goodwill impairment loss totaling $0.4 million was recognized in the services reporting unit. For all other reporting units, NU 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. Except for the aforementioned acquisitions and YESCO impairment, there were no other impairments or adjustments to these goodwill balances in 2002.
Inclusive of the aforementioned acquisitions and the YESCO goodwill write-off, at December 31, 2002, NU maintained $321 million of goodwill that is no longer being amortized, $18.1 million of identifiable intangible assets which continue to be amortized over an average period of 8.5 years and $6.8 million of intangible assets not subject to amortization. Primarily based on revised financial information, the remaining period of amortization related to the exclusivity agreement and the customer list were reduced from 15 years to 8.5 years during the fourth quarter of 2002, resulting in a prospective increase to amortization expense related to these intangible assets of $2 million annually. At December 31, 2001, NU maintained $313 million of goodwill and $20.1 million of identifiable intangible assets. Amortization of goodwill ceased on January 1, 2002.
These amounts are included on the consolidated balance sheets as goodwill and other purchased intangible assets, net. A summary of NU's goodwill balances at December 31, 2002 and 2001, by reportable segment and reporting unit is as follows:
At December 31,
(Millions of Dollars) 2002 2001
--------------------------------------------------------------------------------
Regulated Utilities - Gas:
Yankee Gas $287.6 $287.6
Competitive Energy Subsidiaries:
Services 30.2 25.4
Wholesale and Retail Marketing 3.2 --
--------------------------------------------------------------------------------
Totals $321.0 $313.0
================================================================================
|
At December 31, 2002 and December 31, 2001, NU's intangible assets and related accumulated amortization consisted of the following:
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 and
employment related agreements 0.1 -- 0.1
--------------------------------------------------------------------------------
Totals $24.4 $6.3 $18.1
================================================================================
Intangible assets not subject
to amortization:
Customer relationships $ 3.8
Trade names 3.0
-------------------------------------------------
Totals $ 6.8
=================================================
At December 31, 2001
--------------------------------------------------------------------------------
Gross Accumulated Net
(Millions of Dollars) Balance Amortization Balance
--------------------------------------------------------------------------------
Intangible assets subject to amortization:
Exclusivity agreement $17.7 $3.1 $14.6
Customer list 6.6 1.1 5.5
--------------------------------------------------------------------------------
Totals $24.3 $4.2 $20.1
================================================================================
|
NU recorded amortization expense of $2.1 million and $1.6 million for the years ended December 31, 2002 and 2001, respectively, related to these intangible assets. Based on the current amount of intangible assets subject to amortization, the estimated annual amortization expense for each of the succeeding 5 years from 2003 through 2007 is $3.7 million in 2003 and $3.6 million in subsequent years. These amounts may vary as purchase price allocations are finalized and acquisitions and dispositions occur in the future.
The results for the years ended December 31, 2001 and 2000, on a historical basis, do not reflect the provisions of SFAS No. 142. Had NU adopted SFAS No. 142 on January 1, 2000, historical income before the cumulative effect of an accounting change and extraordinary loss, net income and basic and fully diluted EPS amounts would have been adjusted as follows:
Net Basic Fully
(Millions of Dollars, except share information) Income EPS Diluted EPS
-----------------------------------------------------------------------------------------------
Year Ended December 31, 2002 $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
===============================================================================================
Year Ended December 31, 2000:
Reported income before
extraordinary loss $205.3 $ 1.45 $ 1.45
Add back: goodwill amortization 7.5 0.05 0.05
-----------------------------------------------------------------------------------------------
Adjusted income before
extraordinary loss $212.8 $ 1.50 $ 1.50
===============================================================================================
Reported net loss $(28.6) $(0.20) $(0.20)
Add back: goodwill amortization 7.5 0.05 0.05
-----------------------------------------------------------------------------------------------
Adjusted net loss $(21.1) $(0.15) $(0.15)
===============================================================================================
|
6. SALE OF CUSTOMER RECEIVABLES
At December 31, 2002, CL&P had sold accounts receivable of $40 million to a subsidiary of Citigroup, Inc. with limited recourse through the CL&P Receivables Corporation (CRC), a wholly owned subsidiary of CL&P. Additionally, at December 31, 2002, $3.8 million of assets were designated as collateral and restricted under the agreement with the CRC and included in the consolidated balance sheets as cash and cash equivalents. 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, 2002, amounts sold to CRC from CL&P but not sold to the Citgroup, Inc. subsidiary totaling $178.9 million are included in investments in securitizable assets on the consolidated balance sheets. No amounts were sold in 2001.
7. NUCLEAR GENERATION ASSET DIVESTITURES
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 15 percent 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 will be used to pay approximately $95 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. In connection with the sale, NAEC and CL&P recorded a gain 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 related to the sale of this 15 percent ownership interest. The agreement also limited any top-off amount required to be funded by Baycorp for decommissioning as part of the sale process. NU received approximately $17 million in the fourth quarter of 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. 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.
Millstone: On March 31, 2001, CL&P and WMECO consummated the sale of Millstone 1 and 2 to a subsidiary of Dominion Resources, Inc. (Dominion). CL&P, PSNH and WMECO sold their ownership interests in Millstone 3 to Dominion along with all of the unaffiliated joint ownership interests in Millstone 3. NU received approximately $1.2 billion of cash proceeds from the sale and applied the proceeds to taxes and reductions of debt and equity at CL&P, PSNH and WMECO. As part of the sale, Dominion assumed responsibility for decommissioning the three Millstone units. In connection with the sale, CL&P and WMECO recorded a gain in the amount of $642 million, which was used to offset stranded costs. Additionally, NU recorded an after-tax gain of $115.6 million related to the prior settlement of Millstone 3 joint owner claims.
8. COMMITMENTS AND CONTINGENCIES
A. Restructuring and Rate Matters
Connecticut: On September 27, 2001, CL&P filed its application with the DPUC for
approval of the disposition of the proceeds in the amount of approximately $1.2
billion from the sale of the Millstone units to a subsidiary of Dominion. This
application described and requested DPUC approval for CL&P's treatment of its
share of the proceeds from the sale. In accordance with Connecticut's electric
utility industry restructuring legislation, CL&P was required to utilize any
gains from the Millstone sale to offset stranded costs. The DPUC's final
decision regarding this application was received on February 27, 2003, and did
not have a material impact on NU's 2002 results of operations.
New Hampshire: In July 2001, the NHPUC opened a docket to review the FPPAC costs incurred between August 2, 1999, and April 30, 2001. Under the Restructuring Settlement, FPPAC deferrals are recovered as a Part 3 stranded cost through the stranded cost recovery charge. On December 31, 2002, the NHPUC issued its final order allowing recovery of virtually all such costs.
On June 28, 2002, PSNH made its first stranded cost recovery charge reconciliation filing with the NHPUC for the period May 1, 2001, through December 31, 2001. This filing reconciles stranded cost revenues against actual stranded cost charges with any difference being credited against stranded costs or deferred for future recovery. Included in the stranded cost charges are the generation costs for the filing period. The generation costs included in this filing were subject to a prudence review by the NHPUC. In January 2003, PSNH entered into a settlement agreement with the Office of Consumer Advocate and the staff of the NHPUC which resolved all outstanding issues. In conjunction with the settlement agreement, the NHPUC staff recommended no disallowances resulting from their review of the outages at PSNH's generating plants. A final order approving the settlement agreement was issued by the NHPUC in February 2003. The NHPUC order approved PSNH's reconciliation of stranded costs as outlined within the settlement agreement and had no impact on PSNH's earnings.
Massachusetts: On March 30, 2001, WMECO filed its second annual stranded cost reconciliation with the Massachusetts Department of Telecommunications and Energy (DTE) for calendar year 2000. On March 29, 2002, WMECO filed its 2001 annual transition cost reconciliation with the DTE. This filing reconciled the recovery of stranded generation costs for calendar year 2001 and includes sales proceeds from WMECO's portion of the Millstone units, the impact of securitization and approximately a $13 million benefit to ratepayers from WMECO's nuclear performance-based ratemaking process.
WMECO and the office of the Massachusetts Attorney General reached a settlement resolving all transition charge issues for the 1998 through 2001 reconciliations. The DTE approved this settlement on December 27, 2002. The settlement had a positive impact of $9 million on WMECO 2002 pre-tax earnings.
B. Environmental Matters
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. As such, NU has active environmental auditing and training programs
and believes it is substantially in compliance with the current laws and
regulations.
However, the normal course of operations may involve activities and substances that expose NU to potential liabilities of which management cannot determine the outcome. Additionally, management cannot determine the outcome for liabilities that may be imposed for past acts, even though such past acts may have been lawful at the time they occurred. Management does not believe, however, that this will have a material impact on NU's consolidated financial statements.
Based upon currently available information for the estimated remediation costs at December 31, 2002 and 2001, the liability recorded by NU for its estimated environmental remediation costs amounted to $41.9 million and $46.2 million, respectively. These amounts include $28.1 million and $32.2 million at December 31, 2002 and 2001, respectively, for remediation of former manufactured gas plants.
PSNH and Yankee Gas have regulatory recovery mechanisms for environmental costs. Accordingly, regulatory assets have been recorded for certain environmental liabilities.
C. 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, 2002 and 2001, fees due to the DOE for
the disposal of Prior Period Fuel were $253.6 million and $249.3 million,
respectively, including interest costs of $171.5 million and $167.2 million,
respectively.
Fees for nuclear fuel burned on or after April 7, 1983, are billed currently to customers and paid to the DOE on a quarterly basis. At December 31, 2002, as NU's ownership shares of Millstone and Seabrook have been sold, NU is no longer responsible for fees relating to current fuel burned at these facilities.
D. 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 and VYNPC, 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 their agreements, NU's companies paid
their ownership (or entitlement) shares of costs, which included depreciation,
operation and maintenance (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
$27.6 million in 2002, $25.3 million in 2001, and $24.9 million in 2000.
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 $278.3 million in 2002, $363.9 million in 2001, and $482.1 million in 2000. These amounts are for independent power producer 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 $158 million in 2002, $195.8 million in 2001, and $148.2 million in 2000.
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 Costs: The estimated future annual costs of NU's significant long-term contractual arrangements are as follows:
(Millions of Dollars) 2003 2004 2005 2006 2007 -------------------------------------------------------------------------------- VYNPC $ 30.8 $ 29.4 $ 27.1 $ 28.3 $ 27.4 Electricity Procurement Contracts 338.5 345.1 350.0 349.9 278.2 Gas Procurement Contracts 172.2 151.3 130.9 116.2 36.9 Hydro-Quebec 26.3 25.5 25.0 22.7 21.7 -------------------------------------------------------------------------------- Totals $567.8 $551.3 $533.0 $517.1 $364.2 ================================================================================ |
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 $4.3 billion at December 31, 2002 as follows:
(Millions of Dollars)
-------------------------------------------------------------------------------- Year 2003 $3,302.0 2004 612.6 2005 290.1 2006 68.7 2007 69.2 -------------------------------------------------------------------------------- Total $4,342.6 ================================================================================ |
Select Energy's purchase contract amounts can exceed the amount expected to be reported in fuel, purchased and net interchange power because energy trading purchases are classified net in revenues.
F. 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.
During 2002, NU, along with the other joint owners, were notified by the Yankee Companies that the estimated cost of decommissioning the units owned by CYAPC, YAEC and MYAPC increased in total by approximately $380 million over prior estimates due to higher anticipated costs for spent fuel storage, security and liability and property insurance. NU's share of this increase would total $171.6 million. Following rate cases to be filed by the Yankee Companies with the FERC, NU will seek recovery of the higher decommissioning costs from retail customers through the appropriate state regulatory agency. At December 31, 2002 and 2001, NU's remaining estimated obligations, for decommissioning for the units owned by CYAPC, YAEC and MYAPC, which have been shut down were $354.5 million and $216.6 million, respectively.
G. Consolidated Edison, Inc. Merger Litigation Certain gain and loss contingencies exist with regard to the litigation related to the 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' October 13, 1999 Agreement and Plan of Merger, as amended and restated as of January 11, 2000 (the Merger Agreement). On March 12, 2001, NU filed suit against Con Edison in the United States District Court for the Southern District of New York (the District Court) seeking damages in excess of $1 billion arising from Con Edison's breach of the Merger Agreement.
On May 11, 2001, Con Edison filed an amended complaint seeking damages for breach of contract, fraudulent inducement and negligent misrepresentation. Con Edison has claimed that it is entitled to recover a portion of the merger synergy savings estimated to have a net present value of 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 have completed discovery in the litigation. Motions for summary judgment were argued before the District Court on February 4, 2002. 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.
For further information regarding this litigation, see NU's 2002 report on Form 10-K, Item 3, "Legal Proceedings."
9. FAIR VALUE OF FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair value of each of the following financial instruments:
Cash and Cash Equivalents: The carrying amounts approximate fair value due to the short-term nature of cash and cash equivalents.
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 $17.9 million and $7.4 million held for benefit of the SERP were recorded at their fair market values at December 31, 2002 and 2001, of $17.8 million and $9 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, 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
================================================================================
At December 31, 2001
(Millions of Dollars) Carrying Amount Fair Value
--------------------------------------------------------------------------------
Preferred stock not subject
to mandatory redemption $ 116.2 $ 62.4
Long-term debt -
First mortgage bonds 795.9 847.2
Other long-term debt 1,552.1 1,554.6
Rate reduction bonds 2,018.4 2,061.8
================================================================================
|
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.
10. LEASES
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 $1.7 million in 2002, $13.1 million in 2001, and $50.1 million in 2000. Interest included in capital lease rental payments was $0.6 million in 2002, $4.7 million in 2001, and $11.6 million in 2000. Operating lease rental payments charged to expense were $7.8 million in 2002, $7 million in 2001, and $10.1 million in 2000.
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, 2002 are as follows:
(Millions of Dollars) Capital Operating Year Leases Leases -------------------------------------------------------------------------------- 2003 $ 3.1 $ 23.1 2004 3.0 20.6 2005 2.8 18.4 2006 2.7 16.2 2007 2.6 9.8 After 2007 22.4 26.9 -------------------------------------------------------------------------------- Future minimum lease payments $36.6 $115.0 Less amount representing interest 19.8 -------------------------------------------------------------------------------- Present value of future minimum lease payments $16.8 ================================================================================ |
11. ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS)
The accumulated balance for each other comprehensive income/(loss) item is as follows:
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 pension liability adjustments (0.6) 0.1 (0.5)
--------------------------------------------------------------------------------
Accumulated other
comprehensive (loss)/income $(32.5) $47.4 $14.9
================================================================================
Current
December 31, Period December 31,
(Millions of Dollars) 2000 Change 2001
--------------------------------------------------------------------------------
Qualified cash flow
hedging instruments $ -- $(36.9) $(36.9)
Unrealized gains on securities 2.4 2.6 5.0
Minimum pension liability adjustments (0.6) -- (0.6)
--------------------------------------------------------------------------------
Accumulated other
comprehensive income/(loss) $1.8 $(34.3) $(32.5)
================================================================================
|
The changes in the components of other comprehensive income/(loss) are reported net of the following income tax effects:
(Millions of Dollars) 2002 2001 2000 -------------------------------------------------------------------------------- Qualified cash flow hedging instruments $(33.1) $24.3 $ -- Unrealized gains/(losses) on securities 3.3 (1.9) (0.2) Minimum pension liability adjustments -- -- -- -------------------------------------------------------------------------------- Accumulated other comprehensive income/(loss) $(29.8) $22.4 $(0.2) ================================================================================ |
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) 2002 2001
--------------------------------------------------------------------------------
Balance at beginning of year $(36.9) $ --
--------------------------------------------------------------------------------
Cumulative effect of adopting SFAS No. 133 -- 12.3
Hedged transactions recognized into earnings 17.0 4.5
Change in fair value 29.2 (29.6)
Cash flow transactions entered into for the period 6.2 (24.1)
--------------------------------------------------------------------------------
Net change associated with the current period
hedging transactions 52.4 (36.9)
--------------------------------------------------------------------------------
Total fair value adjustments included in
accumulated other comprehensive income/(loss) $ 15.5 $(36.9)
================================================================================
|
12. EARNINGS PER SHARE
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. The following table sets forth the components of basic and diluted EPS.
(Millions of Dollars, except share information) 2002 2001 2000 ------------------------------------------------------------------------------------------------------------------ Income before preferred dividends of subsidiaries $157.7 $273.2 $219.5 Preferred dividends of subsidiaries 5.6 7.3 14.2 ------------------------------------------------------------------------------------------------------------------ Income before cumulative effect of accounting change and extraordinary loss 152.1 265.9 205.3 Cumulative effect of accounting change, net of tax benefit -- (22.4) -- Extraordinary loss, net of tax benefit -- -- (233.9) ------------------------------------------------------------------------------------------------------------------ Net income/(loss) $152.1 $243.5 $(28.6) ================================================================================================================== Basic EPS common shares outstanding (average) 129,150,549 135,632,126 141,549,860 Dilutive effect of employee stock options 190,811 285,297 417,356 ------------------------------------------------------------------------------------------------------------------ Fully diluted EPS common shares outstanding (average) 129,341,360 135,917,423 141,967,216 ------------------------------------------------------------------------------------------------------------------ Basic earnings/(loss) per common share: Income before cumulative effect of accounting change and extraordinary loss $ 1.18 $ 1.97 $ 1.45 Cumulative effect of accounting change, net of tax benefit -- (0.17) -- Extraordinary loss, net of tax benefit -- -- (1.65) ------------------------------------------------------------------------------------------------------------------ Net income/(loss) $ 1.18 $ 1.80 $(0.20) ================================================================================================================== Fully diluted earnings/(loss) per common share: Income before cumulative effect of accounting change and extraordinary loss $ 1.18 $ 1.96 $ 1.45 Cumulative effect of accounting change, net of tax benefit -- (0.17) -- Extraordinary loss, net of tax benefit -- -- (1.65) ------------------------------------------------------------------------------------------------------------------ Net income/(loss) $ 1.18 $ 1.79 $(0.20) ================================================================================================================== |
13. SEGMENT INFORMATION
NU is organized between regulated utilities (electric and gas since the March 1, 2000 acquisition of Yankee) and competitive energy subsidiaries based on the regulatory environment of each segment. The regulated utilities segment represents approximately 78 percent, 78 percent, and 85 percent of NU's total revenues for each of the three years in the period ended December 31, 2002, respectively, and primarily includes the operations of CL&P, PSNH and WMECO, whose complete financial statements are included in NU's combined report on Form 10-K. The regulated gas utilities segment includes the operations of Yankee Gas. The reclassification of trading revenues and expenses, which has been retroactively applied to 2001, resulted in an increase in these percentages from amounts reported in prior periods. Regulated utility 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.
On January 1, 2000, Select Energy began serving one half of CL&P's standard offer load for a four-year period through 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 $631 million or 38 percent in 2002, approximately $648 million or 31 percent in 2001 and approximately $652 million or 34 percent in 2000, of total competitive energy subsidiaries' revenues. Total CL&P purchases from the competitive energy subsidiaries are eliminated in consolidation. Additionally, Select Energy revenues from NSTAR represented $277.3 million or 13 percent and $285.1 million or 15 percent of total competitive energy subsidiaries' revenues for the years ended December 31, 2001 and 2000, respectively. Beginning in 2002, Select Energy also provided basic generation service in the New Jersey market. Select Energy revenues related to these contracts represented $207.4 million or 12 percent of total competitive energy subsidiaries' revenues for the year ended December 31, 2002. No other individual customer represented in excess of 10 percent of the competitive energy subsidiaries revenues for 2002, 2001 and 2000.
Additionally, WMECO's purchases from Select Energy represented approximately $14 million and $4 million of total competitive energy subsidiaries' revenues in 2002 and 2001, respectively.
The competitive energy subsidiaries segment includes the operations of Select Energy, a corporation engaged in the trading, marketing, transportation, storage, and sale of energy commodities, at wholesale and retail, in designated geographical areas; NGC, a corporation that acquires and manages generation facilities; SESI, a provider of energy management, demand-side management and related consulting services for commercial, industrial and institutional electric companies and electric utility companies; NGS, including Woods Electrical, a corporation that maintains and services fossil or hydroelectric facilities and provides third-party electrical, mechanical, and engineering contracting services; HWP, a company engaged in the production of electric power; and Woods Network and the competitive energy subsidiaries of Yankee.
Other in the following table includes the results for Mode 1, an investor in fiber-optic communications network, the results of the nonenergy-related subsidiaries of Yankee and the company's investment in Accumentrics Corporation. Interest expense included in Other primarily relates to the debt of NU parent. Inter-segment eliminations of revenues and expenses are also included in Other.
For the Year Ended December 31, 2002
----------------------------------------------------------------------------------------------------------------------------
Regulated Utilities Competitive
--------------------------------------- Energy Eliminations
(Millions of Dollars) Electric Gas Subsidiaries And Other Total
----------------------------------------------------------------------------------------------------------------------------
Operating revenues $3,778.1 $293.3 $1,669.8 $(524.9) $ 5,216.3
Depreciation and amortization (618.9) (24.1) (22.0) (2.2) (667.2)
Other operating expenses (2,679.8) (229.3) (1,684.5) 511.2 (4,082.4)
----------------------------------------------------------------------------------------------------------------------------
Operating income/(loss) 479.4 39.9 (36.7) (15.9) 466.7
Other income/(loss), net 42.1 (0.8) (2.0) 4.5 43.8
Interest expense, net (187.2) (14.2) (43.9) (25.2) (270.5)
Income tax (expense)/benefit (121.7) (7.3) 28.5 18.2 (82.3)
Preferred dividends (5.6) -- -- -- (5.6)
----------------------------------------------------------------------------------------------------------------------------
Net income/(loss) $ 207.0 $ 17.6 $ (54.1) $ (18.4) $ 152.1
----------------------------------------------------------------------------------------------------------------------------
Total assets $7,549.0 $963.0 $1,973.2 $(217.6) $10,267.6
----------------------------------------------------------------------------------------------------------------------------
Total investments in plant $ 380.6 $ 70.6 $ 23.2 $ 18.1 $ 492.5
============================================================================================================================
For the Year Ended December 31, 2001
----------------------------------------------------------------------------------------------------------------------------
Regulated Utilities Competitive
--------------------------------------- Energy Eliminations
(Millions of Dollars) Electric Gas Subsidiaries And Other Total
----------------------------------------------------------------------------------------------------------------------------
Operating revenues $4,282.7 $378.0 $2,074.8 $ (767.3) $ 5,968.2
Depreciation and amortization (1,619.3) (33.3) (10.4) 478.9 (1,184.1)
Other operating expenses (2,171.9) (294.6) (2,019.5) 241.0 (4,245.0)
----------------------------------------------------------------------------------------------------------------------------
Operating income/(loss) 491.5 50.1 44.9 (47.4) 539.1
Other income, net 72.8 4.1 5.8 104.9 187.6
Interest expense, net (199.3) (14.0) (42.9) (23.4) (279.6)
Income tax expense (154.3) (14.3) (2.8) (2.5) (173.9)
Preferred dividends (7.3) -- -- -- (7.3)
----------------------------------------------------------------------------------------------------------------------------
Income before cumulative effect
of accounting change 203.4 25.9 5.0 31.6 265.9
Cumulative effect of accounting change,
net of tax benefit -- -- (22.0) (0.4) (22.4)
----------------------------------------------------------------------------------------------------------------------------
Net income/(loss) $ 203.4 $ 25.9 $ (17.0) $ 31.2 $ 243.5
----------------------------------------------------------------------------------------------------------------------------
Total assets $8,730.3 $890.0 $1,728.0 $(1,016.4) $10,331.9
----------------------------------------------------------------------------------------------------------------------------
Total investments in plant $ 380.6 $ 47.8 $ 15.4 $ 14.2 $ 458.0
============================================================================================================================
For the Year Ended December 31, 2000
----------------------------------------------------------------------------------------------------------------------------
Regulated Utilities Competitive
--------------------------------------- Energy Eliminations
(Millions of Dollars) Electric Gas Subsidiaries And Other Total
----------------------------------------------------------------------------------------------------------------------------
Operating revenues $4,738.5 $251.2 $1,894.9 $(1,008.0) $ 5,876.6
Depreciation and amortization (483.5) (21.7) (8.4) (3.0) (516.6)
Other operating expenses (3,594.6) (202.5) (1,821.6) 953.5 (4,665.2)
----------------------------------------------------------------------------------------------------------------------------
Operating income/(loss) 660.4 27.0 64.9 (57.5) 694.8
Other (loss)/income, net (11.6) (7.1) (4.7) 9.1 (14.3)
Interest expense, net (191.9) (12.2) (53.4) (41.8) (299.3)
Income tax (expense)/benefit (173.4) (6.5) (0.1) 18.3 (161.7)
Preferred dividends (14.2) -- -- -- (14.2)
----------------------------------------------------------------------------------------------------------------------------
Income/(loss) before extraordinary loss 269.3 1.2 6.7 (71.9) 205.3
Extraordinary loss, net of tax benefit (214.2) -- (19.7) -- (233.9)
----------------------------------------------------------------------------------------------------------------------------
Net income/(loss) $ 55.1 $ 1.2 $ (13.0) $ (71.9) $ (28.6)
----------------------------------------------------------------------------------------------------------------------------
Total assets $9,620.0 $912.6 $ 684.1 $ (999.6) $10,217.1
----------------------------------------------------------------------------------------------------------------------------
Total investments in plant $ 373.5 $ 21.6 $ 7.1 $ 11.8 $ 414.0
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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
----------------------------------------------------------------------------------------------------------------------------------
2002
----------------------------------------------------------------------------------------------------------------------------------
Operating Revenues $1,284,461 $1,141,928 $1,414,304 $1,375,628
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
----------------------------------------------------------------------------------------------------------------------------------
2001
----------------------------------------------------------------------------------------------------------------------------------
Operating Revenues $1,708,436 $1,422,549 $1,544,375 $1,292,860
Operating Income 159,595 133,472 113,378 132,729
Income Before Cumulative Effect of Accounting Change 134,595 46,732 34,631 49,984
Cumulative Effect of Accounting Change, Net of Tax Benefit (22,432) -- -- --
----------------------------------------------------------------------------------------------------------------------------------
Net Income $ 112,163 $ 46,732 $ 34,631 $ 49,984
==================================================================================================================================
Basic and Fully Diluted Earnings Per Common Share:
Income Before Cumulative Effect of Accounting Change $ 0.93 $ 0.35 $ 0.26 $ 0.38
Cumulative Effect of Accounting Change, Net of Tax Benefit (0.15) -- -- --
----------------------------------------------------------------------------------------------------------------------------------
Net Income $ 0.78 $ 0.35 $ 0.26 $ 0.38
==================================================================================================================================
|
(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 the first and second quarters related to the adoption of EITF Issue No. 02-3.
Selected Consolidated Financial Data (Unaudited)
(Thousands of Dollars, except percentages and share information) 2002 2001 2000 1999 1998
------------------------------------------------------------------------------------------------------------------------------------
Balance Sheet Data:
Property, Plant and Equipment, Net $ 4,728,369 $ 4,472,977 $ 3,547,215 $ 3,947,434 $ 6,170,881
Total Assets 10,267,617 10,331,923 10,217,149 9,688,052 10,387,381
Total Capitalization (a) 4,670,771 4,576,858 4,739,417 5,216,456 6,030,402
Obligations Under Capital Leases (a) 16,803 17,539 159,879 181,293 209,279
------------------------------------------------------------------------------------------------------------------------------------
Income Data:
Operating Revenues $ 5,216,321 $ 5,968,220 $ 5,876,620 $ 4,471,251 $ 3,767,714
Income/(Loss) Before Cumulative Effect of
Accounting Change and Extraordinary Loss,
Net of Tax Benefits 152,109 265,942 205,295 34,216 (146,753)
Cumulative Effect of Accounting Change,
Net of Tax Benefit -- (22,432) -- -- --
Extraordinary Loss, Net of Tax Benefit -- -- (233,881) -- --
------------------------------------------------------------------------------------------------------------------------------------
Net Income/(Loss) $ 152,109 $ 243,510 $ (28,586) $ 34,216 $ (146,753)
====================================================================================================================================
Common Share Data:
Basic Earnings/(Loss) Per Common Share:
Income/(Loss) Before Cumulative Effect of
Accounting Change and Extraordinary Loss,
Net of Tax Benefits $ 1.18 $ 1.97 $ 1.45 $ 0.26 $ (1.12)
Cumulative Effect of Accounting Change,
Net of Tax Benefit -- (0.17) -- -- --
Extraordinary Loss, Net of Tax Benefit -- -- (1.65) -- --
------------------------------------------------------------------------------------------------------------------------------------
Net Income/(Loss) $ 1.18 $ 1.80 $ (0.20) $ 0.26 $ (1.12)
====================================================================================================================================
Fully Diluted Earnings/(Loss)
Per Common Share:
Income/(Loss) Before Cumulative Effect of
Accounting Change and Extraordinary Loss,
Net of Tax Benefits $ 1.18 1.96 1.45 0.26 (1.12)
Cumulative Effect of Accounting Change,
Net of Tax Benefit -- (0.17) -- -- --
Extraordinary Loss, Net of Tax Benefit -- -- (1.65) -- --
------------------------------------------------------------------------------------------------------------------------------------
Net Income/(Loss) $ 1.18 $ 1.79 $ (0.20) $ 0.26 $ (1.12)
====================================================================================================================================
Basic Common Shares Outstanding (Average) 129,150,549 135,632,126 141,549,860 131,415,126 130,549,760
Fully Diluted Common Shares Outstanding (Average) 129,341,360 135,917,423 141,967,216 132,031,573 130,549,760
Dividends Per Share $ 0.53 $ 0.45 $ 0.40 $ 0.10 $ --
Market Price - Closing (high) (c) $ 20.57 $ 23.75 $ 24.25 $ 22.00 $ 17.25
Market Price - Closing (low) (c) $ 13.20 $ 16.80 $ 18.25 $ 13.56 $ 11.69
Market Price - Closing (end of year) (c) $ 15.17 $ 17.63 $ 24.25 $ 20.56 $ 16.00
Book Value Per Share (end of year) $ 17.33 $ 16.27 $ 15.43 $ 15.80 $ 15.63
Tangible Book Value Per Share (end of year) $ 14.62 $ 13.71 $ 13.09 $ 15.53 $ 15.63
Rate of Return Earned on Average Common Equity (%) 7.0 11.2 (1.3) 1.6 (7.0)
Market-to-Book Ratio (end of year) 0.9 1.1 1.6 1.3 1.0
------------------------------------------------------------------------------------------------------------------------------------
Capitalization:
Common Shareholders' Equity 47% 46% 47% 40% 34%
Preferred Stock (a) (b) 3 3 4 5 5
Long-Term Debt (a) 50 51 49 55 61
------------------------------------------------------------------------------------------------------------------------------------
100% 100% 100% 100% 100%
====================================================================================================================================
|
(a) Includes portions due within one year.
(b) Excludes $100 million of Monthly Income Preferred Securities.
(c) Market price information reflects closing prices as presented in the Wall
Street Journal.
Consolidated Electric Sales Statistics (Unaudited)
2002 2001 2000 1999 1998
------------------------------------------------------------------------------------------------------------------------------------
Revenues: (Thousands)
Residential $1,512,397 $1,490,487 $1,469,439 $1,517,913 $1,475,363
Commercial 1,294,943 1,303,351 1,256,126 1,272,969 1,273,146
Industrial 485,592 549,808 566,625 560,801 568,913
Other Utilities 1,190,396 1,761,324 1,884,082 926,056 336,623
Streetlighting and Railroads 43,679 43,889 45,998 45,564 47,682
Nonfranchised Sales -- (3,438) 16,932 24,659 22,479
Miscellaneous 41,357 67,809 96,666 52,357 16,429
------------------------------------------------------------------------------------------------------------------------------------
Total Electric 4,568,364 5,213,230 5,335,868 4,400,319 3,740,635
Gas 466,596 566,814 461,716 -- --
Other 181,361 188,176 79,036 70,932 27,079
------------------------------------------------------------------------------------------------------------------------------------
Total $5,216,321 $5,968,220 $5,876,620 $4,471,251 $3,767,714
====================================================================================================================================
Sales: (kWh - Millions)
Residential 13,923 13,322 12,940 12,912 12,162
Commercial 14,103 13,751 13,023 12,850 12,477
Industrial 6,265 6,790 7,130 7,050 6,948
Other Utilities 85,224 51,789 42,127 33,575 9,742
Streetlighting and Railroads 344 332 333 314 320
Nonfranchised Sales -- -- 107 147 193
------------------------------------------------------------------------------------------------------------------------------------
Total 119,859 85,984 75,660 66,848 41,842
====================================================================================================================================
Customers: (Average)
Residential 1,614,239 1,610,154 1,576,068 1,569,932 1,555,013
Commercial 183,577 171,218 166,114 164,932 162,500
Industrial 7,763 7,730 7,701 7,721 7,847
Other 3,949 3,969 3,917 3,908 3,890
------------------------------------------------------------------------------------------------------------------------------------
Total Electric 1,809,528 1,793,071 1,753,800 1,746,493 1,729,250
Gas 190,855 190,998 185,328 -- --
Total 2,000,383 1,984,069 1,939,128 1,746,493 1,729,250
====================================================================================================================================
Average Annual Use Per
Residential Customer (kWh) 8,611 8,251 8,233 8,243 7,799
====================================================================================================================================
Average Annual Bill Per
Residential Customer $ 934.90 $ 923.70 $ 934.94 $ 969.38 $ 946.80
====================================================================================================================================
Average Revenue Per kWh:
Residential 10.86[cents] 11.20[cents] 11.36[cents] 11.76[cents] 12.14[cents]
Commercial 9.18 9.48 9.65 9.91 10.20
Industrial 7.75 8.10 7.95 7.95 8.19
====================================================================================================================================
|
EXHIBIT 13.2
2002 Annual Report
The Connecticut Light and Power Company and Subsidiaries
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.............................................. 9 Consolidated Balance Sheets....................................... 10-11 Consolidated Statements of Income................................. 12 Consolidated Statements of Comprehensive Income................... 12 Consolidated Statements of Common Stockholder's Equity............ 13 Consolidated Statements of Cash Flows............................. 14 Notes to Consolidated Financial Statements........................ 15 Selected Consolidated Financial Data.............................. 25 Consolidated Quarterly Financial Data (Unaudited)................. 25 Consolidated Statistics (Unaudited)............................... 26 Preferred Stockholder and Bondholder Information.................. Back Cover |
Management's Discussion and Analysis
Overview
The Connecticut Light and Power Company (CL&P or the company), the largest
operating subsidiary of Northeast Utilities (NU), earned $85.6 million in
2002 compared with $109.8 million in 2001. The lower 2002 net 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 (NAEC), Select Energy, Inc.
(Select Energy), Northeast Generation Company, Northeast Generation
Services Company, and Select Energy Services, Inc.
CL&P's revenues for 2002 decreased to $2.5 billion from revenues of $2.6 billion for 2001. The decrease in revenues was primarily due to lower wholesale revenues, partially offset by higher retail revenues. Wholesale revenues decreased due to the sale of the Millstone units in the first quarter of 2001, lower revenues from sales of energy and capacity resulting from the buyout of cogenerator purchase contracts and lower wholesale market prices, and lower revenue from expiring market based contracts. Retail revenues were higher due to the recovery of previously deferred fuel costs and higher sales.
Future Outlook
CL&P is expected to have reduced earnings in 2003 as compared to 2002. The
primary reason for the earnings decrease at CL&P in 2003 is a significant
reduction in the projected level of pension income in 2003 and forward.
CL&P recorded $50.6 million in pre-tax pension income in 2002, approximately 40 percent of which was capitalized and reflected as a reduction to the cost of capital expenditures with the remainder being recognized in the consolidated statements of income as reductions to operating expenses. In 2003, as a result of continued poor performance in the equity markets, CL&P is projecting the total level of pre-tax pension income to decline to approximately $27 million, with a similar percentage being reflected as a reduction to the cost of capital expenditures. Pension income is annually adjusted during the second quarter based upon updated actuarial valuations, at which time the 2003 estimate may be modified.
Liquidity
The year 2002 represented the final year of a four-year process of selling
all of the regulated generation assets owned by CL&P.
On November 1, 2002, CL&P consummated the sale of its 4.06 percent
ownership interest in Seabrook. CL&P received approximately $36 million of
total cash proceeds from the sale of Seabrook.
In November 2002, CL&P, along with NU's other regulated utilities, renewed their $300 million credit line under terms similar to the arrangement that expired in November 2002. A previous credit line had provided up to $350 million for the regulated companies. CL&P had no borrowings on this credit line at December 31, 2002.
In addition to its revolving credit arrangement, CL&P can access up to $100 million by selling certain of its accounts receivable. At December 31, 2002, CL&P had $40 million sold under this arrangement. This accounts receivable arrangement is expected to be renewed in July 2003.
Rate reduction bonds are included on the consolidated balance sheets of CL&P, even though the debt is nonrecourse to CL&P. At December 31, 2002, CL&P had $1.2 billion in rate reduction bonds outstanding, compared with $1.4 billion outstanding at December 31, 2001. All outstanding rate reduction bonds of CL&P are scheduled to be amortized by December 30, 2010. Interest on the rate reduction bonds totaled $75.7 million in 2002, compared with $60.6 million in 2001. Amortization of the rate reduction bonds totaled $112.9 million in 2002, compared with $79.7 million in 2001. CL&P fully recovered the amortization and interest payments from customers in 2002, and the bonds had no impact on net income. Moreover, because the debt is nonrecourse to CL&P, the three rating agencies that rate CL&P's debt and preferred stock securities do not include the revenues, expenses, or outstanding securities related to the rate reduction bonds in establishing the credit ratings of CL&P.
CL&P is also considering refinancing approximately $200 million of spent nuclear fuel obligations in 2003. These obligations are included in long- term debt.
CL&P's net cash flows provided by operating activities increased to $387.4 million in 2002, compared with $12.2 million in 2001. Cash flows provided by operating activities increased 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 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. The level of common dividends totaled $60.1 million in 2002 and 2001.
CL&P has embarked upon a significant upgrade program within its service territory. Over the past five years, CL&P has increased its annual investment in electric utility plant by approximately 50 percent. Much of the additional investment has been devoted to improving the reliability of CL&P's electric distribution system. Over the next several years, CL&P has proposed a significant expansion of its 345,000 volt electric transmission system into southwestern Connecticut at a cost that is likely to exceed $500 million. If Connecticut regulators approve the expansion, CL&P's construction expenditures are projected to exceed $350 million annually from 2004 through 2007. Such a program would significantly exceed CL&P's projections for internally generated operating cash flows and would require CL&P to access the capital markets for financing. In 2003, CL&P is expected to generate enough cash internally to fund most, if not all, of its capital needs.
Implementation of Standard Market Design On March 1, 2003, the New England independent system operator (ISO) implemented a new Standard Market Design (SMD). As part of this effort, locational marginal pricing (LMP) will be utilized to assign value and causation to transmission congestion. Transmission congestion costs will be assigned to the load zone in which the congestion occurs. Those costs are now spread across virtually all New England electric customers. In addition, the implementation of SMD will impact wholesale energy contracts with respect to the energy delivery points contained in those contracts.
Connecticut has been designated a single load zone. Due to the transmission constraints and inadequate generation, Connecticut could experience significant additional congestion costs under SMD. The New England ISO estimates that the costs of transmission congestion for 2003 in New England will range between $50 million and $300 million. The New England ISO estimates that the majority of this congestion and its costs will be in Connecticut, where approximately 80 percent are expected to be paid by CL&P beginning on March 1, 2003. CL&P believes that under the terms of its contracts with its standard offer suppliers, these costs are its responsibility. The contracts with the standard offer suppliers expire on December 31, 2003. In addition, the determination of the energy delivery points associated with the standard offer service contracts under SMD could also produce significant costs for CL&P that management cannot determine at this time.
Another factor affecting the level of congestion costs is the designation of certain generating units by the New England ISO as units needed for system reliability. Some of the companies owning these units have applied to the Federal Energy Regulatory Commission (FERC) for "reliability must run" (RMR) treatment. RMR treatment allows these units to receive cost of service - based payments that recognize their reliability value. Prior to March 1, 2003, all RMR costs were spread across New England with all utilities being billed by the New England ISO based upon their share of New England's load. NU's regulated electric utilities were responsible for approximately 25 percent of these costs. Effective with the March 1, 2003 implementation of SMD by the New England ISO, RMR costs will be allocated to the load zone in which the RMR unit is located. At present, the only load zone that will experience a cost increase in which a NU regulated electric company operates is Connecticut. With respect to the Connecticut load zone, there are two generating units operating under a RMR contract with an additional contract pending before FERC. These contracts are for one year terms, and one contract contains an extension option. On a combined basis, these two RMR contracts will result in an annual cost of approximately $45 million to the Connecticut load zone. CL&P accounts for approximately 80 percent of the Connecticut load zone, and would be responsible for approximately $36 million of this cost. In the near future, it is probable that there will be significant new requests for RMR treatment in Connecticut which, if approved by FERC, would add significant additional costs to the total cost of energy in Connecticut. However, generating units operating under RMR contracts could potentially mitigate the overall level of congestion costs.
These unavoidable congestion and RMR costs are part of the prudent cost of providing regulated electric service in Connecticut. A Connecticut Department of Public Utility Control (DPUC) regulatory proceeding is expected to be initiated soon to determine the appropriate recovery mechanism for these costs. If these costs are incurred before the final recovery mechanism is established by the DPUC, CL&P expects to record a regulatory asset for those costs incurred. See Critical Accounting Policies and Estimates - Regulatory Accounting and Assets included in management's discussion and analysis for further information.
Business Development and Capital Expenditures CL&P's capital expenditures, excluding nuclear fuel, totaled $242.3 million in 2002, compared with $237.4 million in 2001 and $208.2 million in 2000. CL&P expects capital expenditures to increase to $326.9 million in 2003. CL&P spent $141.2 million related to its overhead and underground electric distribution system in 2002 and expects to spend a similar amount in 2003. CL&P spent $35.6 million to upgrade its transmission system in 2002, and expects its transmission capital expenditures to increase to $95 million in 2003, if its current construction plans receive regulatory approval. CL&P also spent $20 million on new meters and customer services, and $17 million on substations in 2002.
In 2001, CL&P announced plans for three transmission projects. In September 2002, the Connecticut Siting Council (CSC) approved the first project, a plan to replace an undersea electric transmission line between Norwalk, Connecticut and Northport - Long Island, New York, at an estimated cost of $80 million. CL&P owns 50 percent of the line with the Long Island Power Authority also owning 50 percent. The project still requires federal and New York state approvals. Given the approval process and the uncertainty created by the recent damage to the existing transmission line, the expected in-service date is currently under evaluation. At December 31, 2002, CL&P has capitalized approximately $4.8 million related to this project.
In early 2003, the CSC completed hearings on the second project, a $135 million proposal to build a new 345,000 volt transmission line between Norwalk, Connecticut and Bethel, Connecticut. A decision is expected in April 2003. The current cost estimate is based on building the entire transmission line aboveground. Alternative proposals have been made to build all or part of the line underground, which likely would result in significantly higher construction costs. CL&P hopes to have the new transmission line operational by the summer of 2005. At December 31, 2002, CL&P has capitalized approximately $8.8 million related to this project.
By mid-2003, CL&P expects to apply to the CSC for approval of a third project, the installation of another 345,000 volt transmission line between Norwalk, Connecticut and Middletown, Connecticut. Estimated construction costs of this overhead line are approximately $500 million. CL&P will jointly construct this project with United Illuminating with CL&P owning 80 percent or approximately $400 million of the project. At December 31, 2002, CL&P has capitalized approximately $2.4 million related to 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.
Regional Transmission Organization
The FERC has required all transmission owning utilities, including CL&P, to
voluntarily start forming regional transmission organizations (RTO) or to
state why this process has not begun.
CL&P has been discussing with the other transmission owners in New England the potential to form an Independent Transmission Company (ITC). If formed, the ITC would be a for-profit entity and would perform certain transmission functions required by the FERC, including tariff control, system planning and system operations. The remaining functions required by the FERC would be performed by the ISO regarding the energy market and short-term reliability. Together, the ITC, if formed, and ISO would form the FERC-desired RTO.
In January 2002, the New York and New England ISOs announced their intention to form an RTO. On November 22, 2002, the two ISOs withdrew their joint petition to FERC. The New England ISO intends to make an RTO filing with the transmission owners in New England in 2003. The agreements needed to create the RTO and to define the working relationships among the ISO and the transmission owners should be created in 2003, and will allow the RTO to begin operation shortly thereafter. The agreements are expected to include provisions for the future creation of one or more ITCs within the RTO. The creation of the RTO will require a FERC rate case, and the impact on CL&P's return on equity as a result of this rate case cannot be estimated at this time. At December 31, 2002, CL&P capitalized $0.8 million related to RTO formation activities.
Merchant Energy Company Counterparty Exposures CL&P has entered into various transactions with subsidiaries of NRG Energy, Inc. (NRG). NRG's credit rating has been downgraded to below investment grade by all three major rating agencies, and NRG is presently in default on debt service payments. Management does not expect that the resolution of the transactions with NRG will have a material adverse effect on CL&P's consolidated financial condition or results of operations. Additionally, CL&P does not have a significant level of exposure to other merchant energy companies. For further information regarding these transactions, see NU's 2002 report on Form 10-K, Item 1, "Business."
Restructuring and Rate Matters
Since retail competition began in Connecticut in 2000, an extremely small
number of customers have opted to choose an alternate supplier. At
December 31, 2002, virtually all of CL&P's customers were procuring their
electricity through CL&P's standard offer service. In 2003, Select Energy
will continue to supply 50 percent of CL&P's standard offer supply service
with NRG Power Marketing, Inc. (NRG-PM), a subsidiary of NRG, contracted to
supply 45 percent and a subsidiary of Duke Energy, Inc. contracted to
supply the remaining 5 percent of service. On November 18, 2001, at NRG-
PM's request, CL&P filed an application with the DPUC to raise the standard
offer rate from an average of $0.0495 per kilowatt-hour (kWh) to $0.0595
per kWh to help promote competition in advance of the January 1, 2004
termination of the standard offer period and to provide financial relief to
standard offer suppliers. In December 2001, the DPUC rejected CL&P's
request, but opened two new dockets to examine the absence of effective
retail competition in Connecticut and the financial condition of the
suppliers. The first docket culminated in a joint study report issued in a
DPUC decision on February 15, 2002, which provided the DPUC's and the
Office of Consumer Counsel's findings on how to best structure default
service and other issues related to electric industry restructuring. In
the second docket, the DPUC concluded on June 17, 2002, that it would not
commence further proceedings.
On July 18, 2002, CL&P, concerned with NRG-PM's financial viability, filed a new proposal with the DPUC to maintain current total rates, but to shift $0.007 per kWh from being used to recover stranded costs to instead provide additional payments to NRG-PM and Select Energy to ensure electric reliability in southwestern Connecticut. On July 26, 2002, the DPUC denied the proposal. CL&P continues to evaluate NRG-PM's ability to meet its obligations under the standard offer service contract. If CL&P is required to seek an alternate source of supply, CL&P would pursue recovery of any additional costs associated with obtaining such supply from NRG-PM pursuant to the contract and may be required to seek DPUC approval to flow through any such costs to customers. Management believes that recovery of these costs, should they be incurred, would be permitted under the provisions of Connecticut's electric utility restructuring legislation and with the DPUC's prior decisions. On February 21, 2003, Fitch Ratings lowered its rating outlook on CL&P to negative as a result of its concern over timely recovery of purchased-power costs if NRG-PM were to default on its CL&P standard offer obligations and CL&P needs to acquire replacement supply service at significantly higher prices.
On September 27, 2001, CL&P filed its application with the DPUC for approval of the disposition of the proceeds in the amount of approximately $1.2 billion from the sale of the Millstone units. This application described and requested DPUC approval for CL&P's treatment of its share of the proceeds from the sale. In accordance with Connecticut's electric utility industry restructuring legislation, CL&P was required to utilize any gains from the Millstone sale to offset stranded costs. The DPUC's final decision regarding this application was issued on February 27, 2003, and increased the amount of net proceeds used to reduce stranded costs by $26.9 million. The earnings impact of the final decision will be reflected in 2003 earnings and will result in an increase in first quarter net income of $2.6 million.
On November 1, 2002, CL&P sold its interest in Seabrook to a subsidiary of FPL Group, Inc. The gain on the sale was used to reduce stranded costs.
CL&P continues to be subject to the earnings sharing mechanism implemented by the DPUC, under which CL&P's earnings in excess of a 10.3 percent return on equity will be shared equally by shareholders and ratepayers.
CL&P expects to file a distribution rate case with the DPUC in mid-2003 that would be effective January 1, 2004. Also in the second half of 2003, CL&P will need to secure bids for power supply contracts for 2004 to meet the needs of its customers. Management has not yet identified what level of rates it will request in 2004, but believes that several factors could combine to result in a significant increase in supply costs in 2004. The first is the expiration of current standard offer supply contracts. Another factor is the likely impact of LMP in New England with the implementation of SMD. Implementation of such pricing, which occurred on March 1, 2003, will force Connecticut electric customers to bear the significant additional costs of serving southwestern Connecticut with less efficient local generation because of insufficient transmission capacity to bring cheaper energy into the region. CL&P's completed and planned reliability improvements and transmission construction program will also impact the level of rates management will request in 2004.
For further information regarding commitments and contingencies related to restructuring, see Note 6A, "Commitments and Contingencies - Restructuring and Rate Matters," to the consolidated financial statements.
Nuclear Generation Asset Divestitures
Seabrook: On November 1, 2002, CL&P, NAEC, and certain other joint owners
consummated the sale of their ownership interest in Seabrook.
VYNPC: On July 31, 2002, Vermont Yankee Nuclear Power Corporation (VYNPC) consummated the sale of its nuclear generating unit. CL&P owns 10.1 percent of VYNPC.
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.
Under the terms of these asset divestitures, the purchasers agreed to assume responsibility for decommissioning their respective units. For further information regarding these divestitures and nuclear decommissioning, see Note 5, "Nuclear Generation Asset Divestitures," and Note 6F, "Nuclear Decommissioning and Plant Closure Costs," to the consolidated financial statements. For further information regarding spent nuclear fuel disposal costs, see Note 6C, "Commitments and Contingencies - Spent Nuclear Fuel Disposal Costs," to the consolidated financial statements.
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 condition of CL&P. The following describes 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 significant control is maintained and 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, Maine Yankee Atomic Power Company, VYNPC, and two companies that transmit electricity imported from the Hydro-Quebec system, which are classified as variable interest entities under Financial Accounting Standards Board Interpretation No. 46, "Consolidation of Variable Interest Entities," and for which CL&P is not the primary beneficiary. As a result, management does not expect the adoption of Interpretation No. 46 to result in the consolidation of any currently unconsolidated entities or to have any other material impacts on CL&P's consolidated financial statements.
Revenue Recognition: Revenues are based on rates approved by the DPUC. These regulated rates are applied to customers' accounts based on their use of energy. In general, rates can only be changed through formal proceedings with the DPUC.
The determination of the energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is estimated. This unbilled revenue is estimated each month based on generation volumes, estimated customer usage by class, line losses, and applicable customer rates.
Regulatory Accounting and Assets: The accounting policies of CL&P historically reflect the effects of the rate-making process in accordance with Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." CL&P's transmission and distribution businesses continue to be cost-of-service rate regulated, and management believes the application of SFAS No. 71 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 this business 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 regulatory assets. Such a write-off could have a material impact on CL&P's consolidated financial statements.
The application of SFAS No. 71 results in the deferral of costs as regulatory assets that, in some cases, have not yet been approved for recovery by the applicable regulatory commission. Management must conclude that any costs deferred as regulatory assets are probable of future recovery in rates. However, the regulatory commission can reach different conclusions about the recovery of costs, which can have a material impact on CL&P's consolidated financial statements. Management believes it is probable that CL&P will recover its investments in long-lived assets, including regulatory assets.
Pension and Postretirement Benefit Obligations: CL&P participates in a uniform noncontributory defined benefit retirement plan (Plan) covering substantially all regular NU employees and also provides 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 resultant 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.
CL&P's pre-tax periodic pension income for the Plan, excluding settlements, curtailments, and special termination benefits, totaled $50.6 million and $61.4 million for the years ended December 31, 2002 and 2001, respectively. Pension income is calculated based upon a number of actuarial assumptions, including an expected long-term rate of return on Plan assets of 9.25 percent for 2002 and 9.5 percent for 2001. CL&P expects to use a long-term rate of return assumption of 8.75 percent for 2003. 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 expenses totaled $8.1 million and $1.2 million for the years ended December 31, 2002 and 2001, respectively. Approximately 40 percent of net pension income is capitalized as a reduction to capital additions to utility plant.
In developing the expected long-term rate of return assumption, CL&P evaluated input from actuaries, consultants and economists as well as long- term inflation assumptions and NU's historical 20-year compounded return of 10.7 percent. NU's expected long-term rate of return on Plan assets is based on target asset allocation assumptions of 45 percent in United States equities and 14 percent in non-United States equities, both with expected long-term rates of return of 9.25 percent, 3 percent in emerging market equities with an expected long-term return of 10.25 percent, 20 percent in fixed income securities with an expected long-term rate of return of 5.5 percent, 5 percent in high yield fixed income securities with expected long-term rates of return of 7.5 percent, 8 percent in private equities with expected long-term rates of return of 14.25 percent, and 5 percent in real estate with expected long-term rates of return of 7.5 percent. The combination of these target allocations and expected returns results in the overall assumed long-term rate of return of 8.75 percent for 2003. The actual asset allocation at December 31, 2002, was close to these target asset allocations, and NU regularly reviews the actual asset allocations and periodically rebalances the investments to the targeted allocation when appropriate. NU reduced the long-term rate of return assumption by 0.5 percent and 0.25 percent, respectively, each of the last two years due to lower rate of return assumptions for most asset classes. CL&P believes that 8.75 percent is a reasonable long-term rate of return on Plan assets for 2003. 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.
CL&P bases the actuarial determination of Plan pension income/expense on a market-related valuation of assets, which reduces year-to-year volatility. This market-related valuation 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 value of assets 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 Plan assets. At December 31, 2002, CL&P's portion of the Plan had cumulative unrecognized investment losses of $234.2 million, which will increase Plan expense over the next four years by reducing the expected return on Plan assets. At December 31, 2002, CL&P's portion of the Plan also had cumulative unrecognized actuarial gains of $57.6 million, which will reduce Plan expenses over the expected future working lifetime of active Plan participants, or approximately 13 years. The combined total of unrecognized investment losses and actuarial gains at December 31, 2002 is $176.6 million. This amount impacts the actuarially determined prepaid pension amount recorded on the consolidated balance sheet but has no impact on expected Plan funding.
The discount rate that is utilized in determining future pension 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 Plan's longer duration 0.25 percent was added to this rating. The discount rate determined on this basis has decreased from 7.25 percent at December 31, 2001 to 6.75 percent at December 31, 2002.
Due to the effect of the unrecognized actuarial losses and based on an expected rate of return on Plan assets of 8.75 percent, a discount rate of 6.75 percent and various other assumptions, CL&P estimates that pension income/expense for the Plan will be approximately $27 million in income, approximately $10 million in income and approximately $4 million in expense in 2003, 2004 and 2005, respectively. 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 plan.
The value of CL&P's portion of the Plan assets has decreased from $910.4 million at December 31, 2001 to $752.7 million at December 31, 2002. The investment performance returns and declining discount rates have reduced the funded status of CL&P's portion of the Plan, on a projected benefit obligation (PBO) basis, from an overfunded position of $284.4 million at December 31, 2001 to $72.3 million at December 31, 2002. The PBO includes expectations of future employee service and compensation increases. The significant deterioration in the funded position of the Plan will likely result in Plan contributions sooner than previously expected. CL&P has not made contributions since 1991. This deterioration could also lead to the requirement under defined benefit plan accounting to record an additional minimum liability. The total accumulated benefit obligation (ABO) of the entire Plan was $78 million less than Plan assets at December 31, 2002. The ABO is the obligation for employee service provided through December 31, 2002. If the ABO exceeds Plan assets, CL&P may need to record an additional minimum liability in 2003.
Income Taxes: Income tax expense is calculated for each period for which a statement of income is presented. 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 of expenses for tax and book accounting purposes. These differences result in deferred tax assets and liabilities, which are included in the consolidated balance sheets. CL&P must also assess the likelihood that the 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. 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. This asset amounted to $170.5 million and $154.2 million at December 31, 2002 and 2001, respectively.
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.
Environmental Matters: At December 31, 2002, CL&P has recorded a reserve for various environmental liabilities. CL&P's environmental liabilities are based on the best estimate of the amounts to be incurred for the investigation, remediation and monitoring of the remediation sites. It is possible that future cost estimates will either increase or decrease as additional information becomes known.
Special Purpose Entities: CL&P has two special purpose entities (SPE), which are currently consolidated in the financial statements. During 2001, to facilitate the issuance of rate reduction certificates intended to finance certain stranded costs, CL&P established one SPE, CL&P Funding LLC. The funding company was created as part of state sponsored securitization programs. 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 becomes involved in such bankruptcy proceedings.
The CL&P Receivables Corporation (CRC) is an SPE that was incorporated on September 5, 1997, and is a wholly owned subsidiary of CL&P. The CRC was established for the sole purpose of selling CL&P's accounts receivable and is included in the consolidation of CL&P's financial statements. On July 10, 2002 the CRC renewed its Receivables Purchase and Sale Agreement with CL&P and a subsidiary of Citigroup, Inc. (Citigroup). The agreement gives the CRC the right to sell and Citigroup the right to purchase up to $100 million in receivables through July 9, 2003. At December 31, 2002 there was $40 million outstanding under this facility. Sales of receivables to Citigroup under this arrangement meet the accounting criteria for derecognition from the consolidated balance sheet. Accordingly, the $40 million outstanding under this facility is not reflected as debt or included in the consolidated financial statements.
For further information regarding these types of activities, see Note 1, "Summary of Significant Accounting Policies," Note 3, "Pension Benefits and Postretirement Benefits Other Than Pensions," Note 4, "Sale of Customer Receivables," Note 6B, "Commitments and Contingencies - Environmental Matters," and Note 12, "Income Tax Expense," to the consolidated financial statements.
Other Matters
Other 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, 2002, is summarized through 2007 as follows:
--------------------------------------------------------------------- (Millions of Dollars) 2003 2004 2005 2006 2007 --------------------------------------------------------------------- Capital leases $ 2.6 $ 2.5 $ 2.4 $ 2.4 $ 2.4 Operating leases 12.0 11.0 10.2 9.1 6.1 Long-term contractual arrangements 230.3 231.9 233.7 236.7 240.4 --------------------------------------------------------------------- Totals $244.9 $245.4 $246.3 $248.2 $248.9 --------------------------------------------------------------------- |
Rate reduction bond amounts are not included in this table. For further information regarding CL&P's contractual obligations and commercial commitments, see Note 8, "Leases," and Note 6E, "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, 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.
Results of Operations
The components of significant income statement variances for the past two years are provided in the table below.
--------------------------------------------------------------------------------
2002 over/(under)2001 2001 over/(under) 2000
Income Statement Variances --------------------- ----------------------
(Millions of Dollars) Amount Percent Amount Percent
--------------------------------------------------------------------------------
Operating Revenues $(139) (5)% $(290) (10)%
Operating Expenses:
Fuel, purchased and net
interchange power (37) (2) (151) (9)
Other operation (10) (3) (102) (25)
Maintenance (26) (25) (30) (22)
Depreciation 2 2 (21) (18)
Amortization of regulatory
assets, net (568) (76) 649 (a)
Taxes other than income taxes 7 5 (7) (5)
Gain on sale of utility plant 505 97 (522) (100)
--------------------------------------------------------------------------------
Total operating expenses (127) (5) (184) (7)
--------------------------------------------------------------------------------
Operating income (12) (4) (106) (29)
Interest expense, net - - 22 23
Other income/(loss), net (30) (58) 75 (a)
--------------------------------------------------------------------------------
Income before income tax expense (42) (22) (53) (22)
Income tax expense (18) (21) (15) (15)
--------------------------------------------------------------------------------
Net income/(loss) $ (24) (22)% $ (38) (26)%
================================================================================
|
(a) Percent greater than 100.
Operating Revenues
Operating revenues decreased $139 million or 5 percent 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.
Total revenues decreased $290 million or 10 percent in 2001, primarily due to lower wholesale revenues ($325 million) and lower transmission revenues ($19 million), partially offset by higher retail revenues ($57 million). Wholesale revenues were lower primarily as a result of the sale of the Millstone units at the end of the first quarter of 2001 and lower sales of capacity and energy. The lower transmission revenues were partially offset by lower transmission expenses. Retail revenues increased primarily due to higher retail sales ($43 million) and the recovery of previously deferred fuel costs ($19 million), partially offset by a rate decrease ($5 million). Retail sales increased 2.4 percent compared to 2000.
Fuel, Purchased and Net Interchange Power 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).
Fuel, purchased and net interchange power expense decreased in 2001, primarily due to lower purchased power costs resulting from the buydown and buyout of various cogeneration contracts and lower nuclear fuel expense.
Other Operation and Maintenance
Other operation and maintenance (O&M) expenses decreased $36 million in
2002, primarily due to lower nuclear expense as a result of the sale of the
Millstone units at the end of the first quarter of 2001 ($52 million),
lower distribution expenses ($8 million), partially offset by higher
transmission expenses ($16 million) and higher administrative and general
expenses ($10 million).
Other O&M expenses decreased $132 million in 2001, primarily due to lower nuclear expenses ($95 million) as a result of the sale of the Millstone units at the end of the first quarter of 2001, lower administrative and general expenses ($22 million), lower transmission expenses ($16 million), and lower fossil/hydro expenses ($3 million), partially offset by higher distribution expenses ($4 million).
Depreciation
Depreciation expense increased $2 million in 2002, primarily due to higher
utility plant balances.
Depreciation expense decreased in 2001, primarily due to the elimination of decommissioning expenses as a result of the sale of the Millstone units at the end of the first quarter of 2001.
Amortization of Regulatory Assets, Net
Amortization of regulatory assets, net decreased $568 million in 2002,
primarily due to lower amortizations related to the sale of the Millstone
units ($524 million) and lower amortizations of the nuclear investment ($42
million).
Amortization of regulatory assets, net increased in 2001, primarily due to the amortization related to the gain on the sale of the Millstone units ($524 million) and higher amortization related to securitized assets ($68 million), stranded costs ($30 million), and other amortizations related to restructuring ($27 million).
Taxes Other Than Income Taxes
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.
Taxes other than income taxes decreased in 2001, primarily due to settlement of a property tax appeal with the City of Meriden in 2001 ($5 million) and the reduction in property tax due to the sale of the Millstone units ($12 million), partially offset by higher gross earnings tax paid on higher revenues ($8 million).
Gain on Sale of Utility Plant
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 the Millstone
units ($522 million). A corresponding amount of amortization expenses was
recorded.
CL&P recorded a gain on the sale of its ownership share in the Millstone units. A corresponding amount of amortization expense was recorded in 2001.
Interest Expense, Net
Interest expense, net increased in 2001, primarily due to interest
associated with the issuance of rate reduction certificates in 2001,
partially offset by lower interest on other long-term debt resulting from
reacquisitions and retirements of long-term debt in 2001.
Other Income/(Loss), Net
Other income, net decreased $30 million in 2002, primarily due to the gain
recognized in 2001 on the sale of the Millstone units ($29 million).
Other income/(loss), net increased in 2001, primarily due to the gain on the sale of CL&P's ownership share in the Millstone units ($29 million), the settlement, in 2000, of Millstone-related litigation, net of insurance proceeds ($9 million), a write-off associated with the former CMEEC nuclear entitlement ($6 million) in 2000 and higher interest income in 2001, including the allowed return on deferred fuel balances ($10 million), interest on an Internal Revenue Service tax settlement ($10 million), and interest income related to the City of Meriden property tax refund ($2 million).
Income Tax Expense
Income tax expense decreased in 2002 primarily due to lower book taxable
income.
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, 2002 and 2001, and the related consolidated statements of income, comprehensive income, common stockholder's equity, and cash flows for the years then ended. The consolidated financial statements of the Company as of December 31, 2000, 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. 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, the 2002 and 2001 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, 2002 and 2001, 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
January 28, 2003
(February 27, 2003 as to Note 6A)
|
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 (a Connecticut corporation and a wholly owned subsidiary of Northeast Utilities) and subsidiaries 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 The Connecticut Light and Power Company and subsidiaries 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.
THE CONNECTICUT LIGHT AND POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
----------------------------------------------------------------------------------------------
At December 31, 2002 2001
----------------------------------------------------------------------------------------------
(Thousands of Dollars)
ASSETS
------
Current Assets:
Cash and cash equivalents.................................. $ 159 $ 773
Investments in securitizable assets........................ 178,908 206,367
Receivables, less provision for uncollectible
accounts of $525 in 2002 and 2001 ........................ 88,001 77,801
Accounts receivable from affiliated companies.............. 51,060 22,134
Unbilled revenues.......................................... 5,801 7,492
Notes receivable from affiliated companies................. 1,900 77,200
Fuel, materials and supplies, at average cost.............. 32,379 33,085
Prepayments and other...................................... 19,407 17,873
---------- ----------
377,615 442,725
---------- ----------
Property, Plant and Equipment:
Electric utility........................................... 3,139,128 3,127,548
Less: Accumulated depreciation.......................... 1,113,991 1,236,638
---------- ----------
2,025,137 1,890,910
Construction work in progress.............................. 153,556 134,964
Nuclear fuel, net.......................................... - 3,299
---------- ----------
2,178,693 2,029,173
---------- ----------
Deferred Debits and Other Assets:
Regulatory assets.......................................... 1,702,677 1,877,191
Prepaid pension............................................ 276,173 233,692
Nuclear decommissioning trusts, at market.................. - 6,231
Other...................................................... 96,925 138,715
---------- ----------
2,075,775 2,255,829
---------- ----------
Total Assets................................................. $4,632,083 $4,727,727
========== ==========
|
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, 2002 2001
----------------------------------------------------------------------------------------------
(Thousands of Dollars)
LIABILITIES AND CAPITALIZATION
------------------------------
Current Liabilities:
Accounts payable....................................... $ 174,890 $ 132,593
Accounts payable to affiliated companies............... 117,904 85,057
Accrued taxes.......................................... 34,350 34,993
Accrued interest....................................... 10,077 10,369
Other.................................................. 48,495 47,342
---------- ----------
385,716 310,354
---------- ----------
Rate Reduction Bonds..................................... 1,245,728 1,358,653
---------- ----------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes...................... 756,461 820,444
Accumulated deferred investment tax credits............ 93,408 95,996
Deferred contractual obligations....................... 234,537 141,497
Other.................................................. 276,325 283,399
---------- ----------
1,360,731 1,341,336
---------- ----------
Capitalization:
Long-Term Debt......................................... 827,866 824,349
---------- ----------
Preferred Stock - Nonredeemable........................ 116,200 116,200
---------- ----------
Common Stockholder's Equity:
Common stock, $10 par value - authorized
24,500,000 shares; 6,035,205 shares outstanding
in 2002 and 7,584,884 shares outstanding in 2001.... 60,352 75,849
Capital surplus, paid in............................. 327,299 414,018
Retained earnings.................................... 308,554 286,901
Accumulated other comprehensive (loss)/income........ (363) 67
---------- ----------
Common Stockholder's Equity............................ 695,842 776,835
---------- ----------
Total Capitalization..................................... 1,639,908 1,717,384
---------- ----------
Commitments and Contingencies (Note 6)
Total Liabilities and Capitalization..................... $4,632,083 $4,727,727
========== ==========
|
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, 2002 2001 2000
---------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Operating Revenues.......................................... $2,507,036 $2,646,123 $2,935,922
---------- ---------- ----------
Operating Expenses:
Operation -
Fuel, purchased and net interchange power.............. 1,477,347 1,514,418 1,665,806
Other.................................................. 300,439 310,477 412,230
Maintenance............................................... 80,132 106,228 136,141
Depreciation.............................................. 98,360 96,212 117,305
Amortization of regulatory assets, net.................... 178,274 746,693 97,315
Taxes other than income taxes............................. 137,299 130,656 137,846
Gain on sale of utility plant............................. (16,143) (521,590) -
---------- ---------- ----------
Total operating expenses................................ 2,255,708 2,383,094 2,566,643
---------- ---------- ----------
Operating Income............................................ 251,328 263,029 369,279
Interest Expense:
Interest on long-term debt................................ 41,332 56,527 85,980
Interest on rate reduction bonds.......................... 75,705 60,644 -
Other interest............................................ 3,925 3,958 12,886
---------- ---------- ----------
Interest expense, net................................... 120,962 121,129 98,866
---------- ---------- ----------
Other Income/(Loss), Net.................................... 22,112 52,804 (22,224)
---------- ---------- ----------
Income Before Income Tax Expense............................ 152,478 194,704 248,189
Income Tax Expense.......................................... 66,866 84,901 100,054
---------- ---------- ----------
Net Income.................................................. $ 85,612 $ 109,803 $ 148,135
========== ========== ==========
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Net Income................................................. $ 85,612 $ 109,803 $ 148,135
---------- ---------- ----------
Other comprehensive (loss)/income, net of tax:
Unrealized (losses)/gains on securities.................. (452) (439) 90
Minimum pension liability adjustments.................... (22) - -
---------- ---------- ----------
Other comprehensive (loss)/income, net of tax......... (474) (439) 90
---------- ---------- ----------
Comprehensive Income....................................... $ 85,138 $ 109,364 $ 148,225
========== ========== ==========
|
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
Capital Other
Common Surplus, Retained Comprehensive Total
Stock Paid In Earnings Income/(Loss) (a)
-------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Balance at January 1, 2000........................ $122,229 $665,598 $153,254 $ 416 $941,497
Net income for 2000........................... 148,135 148,135
Cash dividends on preferred stock............. (7,402) (7,402)
Cash dividends on common stock................ (72,014) (72,014)
Redemption of preferred stock................. (749) (749)
Repurchase of common stock.................... (46,380) (253,620) (300,000)
Capital stock expenses, net................... 1,963 1,963
Allocation of benefits - ESOP (b)............. 21,224 21,224
Other comprehensive income.................... 90 90
-------- -------- -------- ----- --------
Balance at December 31, 2000...................... 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...................... 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.................... (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...................... $ 60,352 $327,299 $308,554 $(363) $695,842
======== ======== ======== ===== ========
|
(a) The company has a dividend restriction as well as two tests it must meet before it can pay out any dividends. The most restrictive of which limits the company's ability to pay out approximately $275.4 million of equity at December 31, 2002.
(b) In June 1999, CL&P paid NU parent $30.5 million for NU shares issued from 1992 through 1998 on behalf of its employees in accordance with NU's 401(k) plan. This transaction resulted in a reduction of the NU parent loss and a tax benefit to CL&P. The amount in 2000 represents the remaining previously unallocated 1993 through 1999 NU parent losses.
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, 2002 2001 2000
-------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Operating Activities:
Net income....................................................... $ 85,612 $ 109,803 $ 148,135
Adjustments to reconcile to net cash flows
provided by operating activities:
Depreciation................................................... 98,360 96,212 117,305
Deferred income taxes and investment tax credits, net.......... (71,880) (144,559) 5,672
Net amortization of recoverable energy costs................... 30,787 5,162 4,155
Amortization of regulatory assets, net......................... 178,274 746,693 97,315
Tax benefit for 1993-1999 from
reduction in NU parent losses................................ - - 21,461
Gain on sale of utility plant.................................. (16,143) (521,590) -
Prepaid pension................................................ (42,481) (63,020) (170,672)
Net other sources/(uses) of cash............................... 62,868 (107,024) 111,594
Changes in working capital:
Receivables and unbilled revenues, net......................... (37,435) (144,419) (109,938)
Fuel, materials and supplies................................... (1,017) 3,247 1,271
Accounts payable............................................... 74,831 (58,400) 171,729
Accrued taxes.................................................. (643) 1,922 (136,313)
Investments in securitizable assets............................ 27,459 61,779 9,474
Other working capital (excludes cash).......................... (1,184) 26,440 3,204
-------- ---------- ---------
Net cash flows provided by operating activities.................... 387,408 12,246 274,392
-------- ---------- ---------
Investing Activities:
Investments in plant:
Electric utility plant......................................... (242,301) (237,423) (208,249)
Nuclear fuel................................................... (57) (1,992) (35,709)
--------- ---------- ---------
Cash flows used for investments in plant......................... (242,358) (239,415) (243,958)
NU system Money Pool borrowing/(lending)......................... 75,300 (39,200) (49,700)
Investments in nuclear decommissioning trusts.................... (1,086) (74,866) (25,133)
Net proceeds from the sale of utility plant...................... 35,887 827,681 686,807
Buyout/buydown of IPP contracts.................................. - (1,029,008) -
Other investment activities, net................................. 23,395 (10,164) 10,246
--------- ---------- ---------
Net cash flows (used in)/provided by investing activities.......... (108,862) (564,972) 378,262
-------- ----------- ---------
Financing Activities:
Repurchase of common stock....................................... (99,990) - (300,000)
Issuance of rate reduction bonds................................. - 1,438,400 -
Retirement of rate reduction bonds............................... (112,924) (79,747) -
Net(decrease)/increase in short-term debt........................ - (115,000) 25,000
Reacquisitions and retirements of long-term debt................. - (416,155) (179,071)
Reacquisitions and retirements of preferred stock................ - - (99,539)
Retirement of monthly income preferred securities................ - (100,000) -
Retirement of capital lease obligation........................... - (145,800) -
Cash dividends on preferred stock................................ (5,559) (5,559) (7,402)
Cash dividends on common stock................................... (60,145) (60,072) (72,014)
Other financing activities, net.................................. (542) 31,971 (14,531)
--------- ---------- ---------
Net cash flows (used in)/provided by financing activities.......... (279,160) 548,038 (647,557)
--------- ---------- ---------
Net (decrease)/increase in cash and cash equivalents............... (614) (4,688) 5,097
Cash and cash equivalents - beginning of year...................... 773 5,461 364
--------- ---------- ---------
Cash and cash equivalents - end of year............................ $ 159 $ 773 $ 5,461
========= ========== =========
Supplemental Cash Flow Information:
Cash paid during the year for:
Interest, net of amounts capitalized............................. $ 117,718 $ 120,645 $ 96,735
========= ========== =========
Income taxes..................................................... $ 141,724 $ 230,144 $ 226,380
========= ========== =========
|
The accompanying notes are an integral part of these consolidated financial statements.
Notes to Consolidated Financial Statements
1. Summary of Significant Accounting Policies
A. About The Connecticut Light and Power Power Company The Connecticut Light and Power Company (CL&P or the company) along with the Public Service Company of New Hampshire (PSNH), Western Massachusetts Electric Company (WMECO), North Atlantic Energy Corporation (NAEC), Holyoke Water Power Company (HWP), and Yankee Energy System, Inc. (Yankee) are the operating companies comprising the Northeast Utilities system and are wholly owned by Northeast Utilities (NU). CL&P furnishes franchised retail electric service in Connecticut, while PSNH and WMECO furnish franchised retail electric service in New Hampshire and western Massachusetts. NAEC previously sold all of its entitlement to the capacity and output of the Seabrook Station 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. NU's other subsidiaries include HWP, a company engaged in the production of electric power, Yankee, the parent company of Yankee Gas Services Company (Yankee Gas), Connecticut's largest natural gas distribution system, and several competitive subsidiaries including Select Energy, Inc., Northeast Generation Company, Northeast Generation Services Company, and Select Energy Services, Inc.
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).
Several wholly owned subsidiaries of NU provide support services for NU's companies, including CL&P, and in some cases, for other New England utilities. Northeast Utilities Service Company (NUSCO) provides centralized accounting, administrative, engineering, financial, information resources, legal, operational, planning, purchasing, and other services to NU's companies. Until the sale of Seabrook on November 1, 2002, North Atlantic Energy Service Corporation had operational responsibility for Seabrook. Three other subsidiaries construct, acquire or lease some of the property and facilities used by NU's companies.
B. Presentation The consolidated financial statements of CL&P include the accounts of all 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 contingent liabilities
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.
C. New Accounting Standards Asset Retirement Obligations: In June 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (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 is effective on January 1, 2003, for CL&P. Management has completed its review process for potential asset retirement obligations (AROs) and has not identified any material AROs which have been incurred. However, management has identified certain removal obligations which arise in the ordinary course of business that either have a low probability of occurring or are not material in nature. 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.
A portion of CL&P's regulated rates is intended to recover the cost of removal of certain utility assets. The amounts recovered do not represent AROs. At December 31, 2002, CL&P maintained approximately $154.5 million in cost of removal regulatory liabilities, which are included in its accumulated provision for depreciation.
Guarantees: In November 2002, the FASB issued Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others." Interpretation No. 45 requires that disclosures be made by a guarantor in its interim and annual financial statements about its obligations under certain guarantees that it has issued and clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. Interpretation No. 45 does not apply to certain guarantee contracts, such as residual value guarantees provided by lessees in capital leases, guarantees that are accounted for as derivatives, guarantees that represent contingent consideration in a business combination, guarantees issued between either parents and their subsidiaries or corporations under common control, a parent's guarantee of a subsidiary's debt to a third party, and a subsidiary's guarantee of the debt owed to a third party by either its parent or another subsidiary of that parent. The initial recognition and initial measurement provisions of Interpretation No. 45 are applicable to CL&P on a prospective basis to guarantees issued or modified after January 1, 2003. Currently, management does not expect the adoption of the initial recognition and initial measurement provisions of Interpretation No. 45 to have a material impact on CL&P's consolidated financial statements.
Consolidation of Variable Interest Entities: In January 2003, the FASB issued Interpretation No. 46, "Consolidation of Variable Interest Entities." Interpretation No. 46 addresses the consolidation and disclosure requirements for companies that hold an equity interest in a variable interest entity (VIE), regardless of the date on which the VIE was created. Interpretation No. 46 requires consolidation of a VIE's assets, liabilities and noncontrolling interests at fair value when a company is the primary beneficiary, which is defined as a company that absorbs a majority of the expected losses, risks and revenues from the VIE as a result of holding a contractual or other financial interest in the VIE. Consolidation is not required under Interpretation No. 46 for those companies that hold a significant equity interest in a VIE but are not the primary beneficiary. Interpretation No. 46 is effective for CL&P beginning in the third quarter of 2003. At December 31, 2002, CL&P held equity interests in various VIEs, for which CL&P was not the primary beneficiary, as CL&P does not absorb a majority of the expected losses, risks and revenues from the VIEs or provide a substantial portion of financial support. As a result, management does not expect the adoption of Interpretation No. 46 to have a material impact on CL&P's consolidated financial statements. For further information regarding CL&P's investments in its VIEs, see Note 1D, "Equity Investments and Jointly Owned Electric Utility Plant" to the consolidated financial statements.
D. Equity Investments and Jointly Owned Electric Utility Plant Regional Nuclear Generating Companies: CL&P owns common stock in four regional nuclear companies (Yankee Companies). CL&P's ownership interests in the Yankee Companies at December 31, 2002 and 2001, which are accounted for on the equity method, are 34.5 percent of the Connecticut Yankee Atomic Power Company (CYAPC), 24.5 percent of the Yankee Atomic Electric Company (YAEC), 12 percent of the Maine Yankee Atomic Power Company (MYAPC), and 10.1 percent of the Vermont Yankee Nuclear Power Corporation (VYNPC). CL&P's total equity investment in the Yankee Companies and its exposure to loss as a result of these investments at December 31, 2002 and 2001, is $32.2 million and $34.7 million, respectively. These investments are VIE's under FASB Interpretation No. 46. Excluding VYNPC, which sold its nuclear generating plant, each Yankee Company owns a single decommissioned nuclear generating plant. On July 31, 2002, VYNPC consummated the sale of its nuclear generating plant to a subsidiary of Entergy Corporation for approximately $180 million.
Seabrook: CL&P had a 4.06 percent joint ownership interest in Seabrook, a 1,148 megawatt nuclear generating unit. On November 1, 2002, CL&P consummated the sale of its ownership interest in Seabrook to a subsidiary of FPL Group, Inc. (FPL). At December 31, 2001, plant-in-service and the accumulated provision for depreciation for CL&P's share of Seabrook totaled $174.7 million and $164.8 million, respectively.
E. Depreciation The provision for depreciation is calculated using the straight-line method based on the estimated remaining useful lives of depreciable utility 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 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. The depreciation rates for the several classes of electric utility plant-in- service are equivalent to a composite rate of 3.2 percent in 2002 and 3.1 percent in 2001 and 3 percent in 2000.
F. Revenues Revenues are based on rates approved by the DPUC. These regulated rates are applied to customer's accounts based on their use of energy. In general, rates can only be changed through formal proceedings with the DPUC.
The determination of the energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is estimated. This unbilled revenue is estimated each month based on generation volumes, estimated customer usage by class, line losses, and applicable customer rates.
G. Regulatory Accounting and Assets 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."
CL&P's transmission and distribution businesses 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 also believes it is probable that CL&P will recover its investments in long-lived assets, including regulatory assets. In addition, all material regulatory assets are earning a return, except for securitized regulatory assets. The components of CL&P's regulatory assets are as follows:
---------------------------------------------------------------------
At December 31,
---------------------------------------------------------------------
(Millions of Dollars) 2002 2001
---------------------------------------------------------------------
Recoverable nuclear costs $ 10.6 $ 158.1
Securitized regulatory assets 1,244.5 1,356.3
Income taxes, net 170.5 154.2
Unrecovered contractual obligations 116.8 2.1
Recoverable energy costs, net 49.3 80.1
Other 111.0 126.4
---------------------------------------------------------------------
Totals $1,702.7 $1,877.2
---------------------------------------------------------------------
|
In March 2001, CL&P sold its ownership interests in the Millstone units. The gain on this sale of approximately $521.6 million was used to offset recoverable nuclear costs, resulting in an unamortized balance of $6 million and $148.9 million at December 31, 2002 and 2001, respectively. Also included in recoverable nuclear costs is $4.6 million and $9.2 million at December 31, 2002 and 2001, respectively, associated with Millstone 1 recoverable nuclear costs relating to the recoverable portion of the undepreciated plant and related assets.
In March 2001, CL&P issued $1.4 billion in rate reduction certificates and used $1.1 billion of those proceeds to buyout or buydown certain contracts with independent power producers. The majority of the payments to buyout or buydown these contracts were recorded as securitized regulatory assets. CL&P also securitized a portion of its SFAS No. 109 regulatory asset.
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.
CL&P, under the Energy Policy Act of 1992 (Energy Act), 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) when they owned nuclear generating plants. 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 is currently recovering these costs through rates. At December 31, 2002 and 2001, CL&P's total D&D Assessment deferrals were $17.6 million and $21.1 million, respectively, and have been recorded as recoverable energy costs, net.
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 and $59 million at December 31, 2002 and 2001, respectively, which have been recorded as recoverable energy costs, net. On July 26, 2001, the DPUC authorized CL&P to assess a charge of approximately $0.002 per kilowatt-hour (kWh) from August 2001 through December 2003 to collect these costs.
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, "Accounting for Income Taxes."
The tax effect of temporary differences, including timing differences accrued under previously approved accounting standards, that give rise to the accumulated deferred tax obligation is as follows:
---------------------------------------------------------------------
At December 31,
---------------------------------------------------------------------
(Millions of Dollars) 2002 2001
---------------------------------------------------------------------
Accelerated depreciation and
other plant-related differences $239.6 $279.1
Regulatory assets:
Nuclear stranded investment and
other asset divestitures 213.5 276.1
Securitized contract termination
costs and other 57.5 63.4
Income tax gross-up 134.4 134.4
Other 111.5 67.4
---------------------------------------------------------------------
Totals $756.5 $820.4
---------------------------------------------------------------------
|
I. Cash and Cash Equivalents Cash and cash equivalents includes cash on hand and short-term cash investments which are highly liquid in nature and have original maturities of three months or less.
J. Other Income/(Loss), Net The pre-tax components of CL&P's other income/(loss), net items are as follows:
---------------------------------------------------------------------
For the Years Ended December 31,
---------------------------------------------------------------------
(Millions of Dollars) 2002 2001 2000
---------------------------------------------------------------------
Seabrook-related gains $ 2.1 $ - $ -
Gain related to Millstone sale - 29.5 -
Nuclear related costs - - (14.1)
Investment income 10.2 12.9 6.5
Other, net 9.8 10.4 (14.6)
---------------------------------------------------------------------
Totals $22.1 $52.8 $(22.2)
---------------------------------------------------------------------
|
2. Short-Term Debt
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. Currently, SEC authorization allows CL&P to incur total short- term borrowings up to a maximum of $375 million. In addition, the charter of CL&P contains preferred stock provisions restricting the amount of unsecured debt that CL&P may incur. At December 31, 2002, CL&P's charter permits CL&P to incur $480 million of additional unsecured debt.
Credit Agreement: On November 12, 2002, CL&P, PSNH, WMECO, and Yankee Gas entered into a 364-day unsecured revolving credit facility for $300 million. This facility replaced a $350 million facility for CL&P, PSNH, WMECO and Yankee Gas, which expired on November 15, 2002 and CL&P may draw up to $150 million under the facility. Unless extended, the credit facility will expire on November 11, 2003. At December 31, 2002 and 2001, there were no borrowings under these 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.
This credit agreement provides that CL&P must comply with certain financial and nonfinancial covenants as are customarily included in such agreements, including, but not limited to, consolidated debt ratios and interest coverage ratios. CL&P currently is and expects to remain in compliance with these covenants.
Money Pool: CL&P is a member of the Northeast Utilities System Money Pool (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, 2002 and 2001, CL&P had $1.9 million and $77.2 million of lendings to the Pool, respectively. The interest rate on lendings to the Pool at December 31, 2002 and 2001 was 1.2 percent and 1.5 percent, respectively.
3. Pension Benefits and Postretirement Benefits Other Than Pensions
Pension Benefits: CL&P participates in a uniform noncontributory defined benefit retirement plan (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, approximately 40 percent of which was credited to utility plant, was $50.6 million in 2002, $61.4 million in 2001, and $57.2 million in 2000. These amounts exclude pension settlements, curtailments and net special termination expenses of $8.1 million and $1.2 million in 2002 and 2001, respectively. There were no pension settlements, curtailments, or net special termination expenses recognized in 2000. Pension income attributable to earnings is as follows:
--------------------------------------------------------------------------
For Years Ended December 31,
--------------------------------------------------------------------------
(Millions of Dollars) 2002 2001 2000
--------------------------------------------------------------------------
Pension income before
settlements, curtailments
and special termination benefits $(50.6) $(61.4) $(57.2)
Net pension income
capitalized as utility plant (a) 20.2 24.6 22.9
--------------------------------------------------------------------------
Net pension income before
settlements, curtailments
and special termination
benefits (30.4) (36.8) (34.3)
Settlements, curtailments and
special termnination benefits
reflected in earnings - 3.3 -
--------------------------------------------------------------------------
Total pension income
included in earnings $(30.4) $(33.5) $(34.3)
--------------------------------------------------------------------------
|
(a) Net pension income capitalized as utility plant was calculated utilizing an average of 40 percent.
Effective February 1, 2002, certain CL&P employees who were displaced were eligible for a Voluntary Retirement Program (VRP). The VRP supplements NU's Plan and provides special provisions. Eligible employees include non- bargaining unit employees or employees belonging to a collective bargaining unit that has agreed to accept the VRP who are active participants in NU's Plan at January 1, 2002, and that have been displaced as part of the reorganization between January 22, 2002 and March 3, 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. CL&P believes that the cost of the VRP is probable of recovery through regulated utility rates, and accordingly, 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 five 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 and $2.1 million was deferred as a regulatory liability and has been returned to customers.
Postretirement Benefits Other Than Pensions (PBOP): NU's subsidiaries, including CL&P, also provide certain health care benefits, primarily medical and dental, and life insurance benefits through a benefit plan to retired employees. 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. CL&P annually funds postretirement costs through external trusts with amounts that have been rate-recovered and which also are tax deductible.
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 regulated utility rates in 2002.
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 $13.5 million decrease in CL&P's benefit obligation under the PBOP plan at December 31, 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) 2002 2001 2002 2001
-------------------------------------------------------------------------------------------------
Change in benefit obligation
Benefit obligation at beginning of year $(626.0) $(587.3) $(165.7) $(136.3)
Service cost (11.7) (10.0) (2.0) (1.9)
Interest cost (44.8) (43.7) (13.4) (11.1)
Plan amendment (4.5) - 13.5 -
Transfers (2.2) (2.4) (20.4) -
Actuarial loss (45.3) (24.9) (17.7) (32.2)
Benefits paid - excluding lump sum payments 41.5 40.2 18.3 16.0
Benefits paid - lump sum payments 20.7 4.9 - -
Curtailments and settlements - 0.8 - (0.2)
Special termination benefits (8.1) (3.6) - -
-------------------------------------------------------------------------------------------------
Benefit obligation at end of year $(680.4) $(626.0) $(187.4) $(165.7)
-------------------------------------------------------------------------------------------------
Change in plan assets
Fair value of plan assets at beginning of year $ 910.4 $ 998.8 $ 55.7 $ 62.4
Actual return on plan assets (97.7) (45.7) (5.9) (5.8)
Employer contribution - - 18.3 14.5
Benefits paid - excluding lump sum payments (41.5) (40.2) (18.3) (16.0)
Benefits paid - lump sum payments (20.7) (4.9) - -
Transfers 2.2 2.4 9.5 0.6
-------------------------------------------------------------------------------------------------
Fair value of plan assets at end of year $ 752.7 $ 910.4 $ 59.3 $ 55.7
-------------------------------------------------------------------------------------------------
Funded status at December 31 $ 72.3 $ 284.4 $(128.1) $(110.0)
Unrecognized transition (asset)/obligation (1.8) (2.7) 62.7 80.3
Unrecognized prior service cost 29.1 27.6 (2.9) -
Unrecognized net loss/(gain) 176.6 (75.6) 60.9 29.1
-------------------------------------------------------------------------------------------------
Prepaid/(accrued) benefit cost $ 276.2 $ 233.7 $ (7.4) $ (0.6)
-------------------------------------------------------------------------------------------------
|
The following actuarial assumptions were used in calculating the plans' year end funded status:
-------------------------------------------------------------------------------
At December 31,
-------------------------------------------------------------------------------
Pension Benefits Postretirement Benefits
-------------------------------------------------------------------------------
2002 2001 2002 2001
-------------------------------------------------------------------------------
Discount rate 6.75% 7.25% 6.75% 7.25%
Compensation/progression rate 4.00% 4.25% 4.00% 4.25%
Health care cost trend rate (a) N/A N/A 10.00% 11.00%
-------------------------------------------------------------------------------
|
(a) The annual per capita cost of covered health care benefits was assumed to decrease to 5.00 percent by 2007.
The components of net periodic benefit (income)/expense are as follows:
---------------------------------------------------------------------------------------------------
For the Years Ended December 31,
---------------------------------------------------------------------------------------------------
Pension Benefits Postretirement Benefits
---------------------------------------------------------------------------------------------------
(Millions of Dollars) 2002 2001 2000 2002 2001 2000
---------------------------------------------------------------------------------------------------
Service cost $ 11.7 $ 10.0 $ 9.7 $ 2.0 $ 1.9 $ 1.9
Interest cost 44.8 43.7 42.3 13.4 11.1 10.1
Expected return on plan assets (94.2) (95.3) (88.4) (6.3) (5.5) (4.9)
Amortization of unrecognized net
transition (asset)/obligation (0.9) (0.9) (0.9) 6.9 7.3 7.3
Amortization of prior service cost 3.0 2.6 2.7 - - -
Amortization of actuarial gain (15.0) (21.5) (22.6) - - -
Other amortization, net - - - 2.0 (0.5) (1.9)
---------------------------------------------------------------------------------------------------
Net periodic (income)/expense - before
settlements, curtailments and special
termination benefits (50.6) (61.4) (57.2) 18.0 14.3 12.5
---------------------------------------------------------------------------------------------------
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 $(42.5) $(60.2) $(57.2) $18.0 $15.0 $12.5
---------------------------------------------------------------------------------------------------
|
For calculating pension and postretirement benefit income and expense amounts, the following assumptions were used:
-----------------------------------------------------------------------------------------
For the Years Ended December 31,
-----------------------------------------------------------------------------------------
Pension Benefits Postretirement Benefits
-----------------------------------------------------------------------------------------
2002 2001 2000 2002 2001 2000
-----------------------------------------------------------------------------------------
Discount rate 7.25% 7.50% 7.75% 7.25% 7.50% 7.75%
Expected long-term rate of return 9.25% 9.50% 9.50% N/A N/A N/A
Compensation/progression rate 4.25% 4.50% 4.75% 4.25% 4.50% 4.75%
Long-term rate of return -
Health assets, net of tax N/A N/A N/A 7.25% 7.50% 7.50%
Life assets N/A N/A N/A 9.25% 9.50% 9.50%
-----------------------------------------------------------------------------------------
|
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 $0.4 $(0.4)
Effect on postretirement
benefit obligation $5.7 $(5.1)
--------------------------------------------------------------------------
|
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.
Pension and trust assets are invested primarily in domestic and international equity securities and bonds.
The trust holding the postretirement benefit health plan assets is subject to federal income taxes.
4. Sale of Customer Receivables
At December 31, 2002, CL&P had sold accounts receivable of $40 million to a subsidiary of Citigroup, Inc. with limited recourse through the CL&P Receivables Corporation (CRC), a wholly owned subsidiary of CL&P. Additionally, at December 31, 2002, $3.8 million of assets were designated as collateral and restricted under the agreement with the CRC and included in the consolidated balance sheets as cash and cash equivalents. 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, 2002, amounts sold to CRC from CL&P, but not sold to the Citgroup, Inc. subsidiary, totaling $178.9 million are included in investments in securitizable assets on the consolidated balance sheets. No amounts were sold in 2001.
5. Nuclear Generation Asset Divestitures
Seabrook: On November 1, 2002, CL&P consummated the sale of its 4.06 percent 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. CL&P received approximately $36 million of total cash proceeds from the sale of Seabrook. As part of the sale, FPL assumed responsibility for decommissioning Seabrook. In connection with the sale, CL&P recorded a gain 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 these approvals, CL&P eliminated $0.6 million, on a pre-tax basis, of reserves related to its ownership shares 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. Under the terms of the sale, CL&P will continue to buy 9.5 percent of the plant's output through March 2012 at a range of fixed prices.
Millstone: On March 31, 2001, CL&P and WMECO consummated the sale of Millstone 1 and 2 to a subsidiary of Dominion Resources, Inc. (Dominion). CL&P, PSNH and WMECO sold their ownership interests in Millstone 3 to Dominion along with all of the unaffiliated joint ownership interests in Millstone 3. CL&P received approximately $828 million of cash proceeds from the sale and applied the proceeds to taxes and reductions of debt and equity. As part of the sale, Dominion assumed responsibility for decommissioning the three Millstone units. In connection with the sale, CL&P recorded a gain in the amount of $521.6 million, which was used to offset stranded costs.
6. Commitments and Contingencies
A. Restructuring and Rate Matters On September 27, 2001, CL&P filed its application with the DPUC for approval of the disposition of the proceeds in the amount of approximately $1.2 billion from the sale of the Millstone units to a subsidiary of Dominion. This application described and requested DPUC approval for CL&P's treatment of its share of the proceeds from the sale. In accordance with Connecticut's electric utility industry restructuring legislation, CL&P was required to utilize any gains from the Millstone sale to offset stranded costs. The DPUC's final decision regarding this application was received on February 27, 2003, and did not have a material impact on NU's 2002 results of operations.
B. Environmental Matters 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. As such, CL&P has active environmental auditing and training programs and believes it is substantially in compliance with the current laws and regulations.
However, the normal course of operations may involve activities and substances that expose CL&P to potential liabilities of which management cannot determine the outcome. Additionally, management cannot determine the outcome for liabilities that may be imposed for past acts, even though such past acts may have been lawful at the time they occurred. Management does not believe, however, that this will have a material impact on CL&P's consolidated financial statements.
Based upon currently available information for the estimated remediation costs at December 31, 2002 and 2001, the liability recorded by CL&P for its estimated environmental remediation costs amounted to $7.3 million and $2.5 million, respectively.
C. 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, 2002 and 2001, fees due to the DOE for the disposal of Prior Period Fuel were $205.5 million and $201.9 million, respectively, including interest costs of $138.9 million and $135.4 million, respectively. Fees for nuclear fuel burned on or after April 7, 1983, were billed currently to customers and paid to the DOE on a quarterly basis. At December 31, 2002, as CL&P's ownership shares of Millstone and Seabrook have been sold, CL&P is no longer responsible for fees relating to current fuel burned at these facilities.
D. Nuclear Insurance Contingencies In conjunction with the divestiture of Millstone in 2001 and Seabrook in 2002, NU and CL&P terminated their 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 and VYNPC, 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 agreements, CL&P paid its ownership (or entitlement) shares of costs, which included depreciation, operation and maintenance (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 9.5 percent of the plant's output through March 2012 at a range of fixed prices. CL&P's cost of purchases under contracts with VYNPC amounted to $16.4 million in 2002, $14.7 million in 2001, and $14.5 million in 2000.
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 $154.6 million in 2002, $205 million in 2001, and $308.6 million in 2000. These amounts are for independent power producer 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 an agreement 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, 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 CL&P's significant long-term contractual arrangements are as follows:
------------------------------------------------------------------------------- (Millions of Dollars) 2003 2004 2005 2006 2007 ------------------------------------------------------------------------------- VYNPC $ 18.3 $ 17.4 $ 16.1 $ 16.8 $ 16.3 Electricity Procurement Contracts 197.0 200.0 203.4 206.9 211.7 Hydro-Quebec 15.0 14.5 14.2 13.0 12.4 ------------------------------------------------------------------------------- Totals $230.3 $231.9 $233.7 $236.7 $240.4 ------------------------------------------------------------------------------- |
F. 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.
During 2002, NU, along with the other joint owners, were notified by the Yankee Companies that the estimated cost of decommissioning the units owned by CYAPC, YAEC and MYAPC increased in total by approximately $380 million 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 would total $115.6 million. Following rate cases to be filed by the Yankee Companies with the FERC, NU will seek recovery of the higher decommissioning costs from retail customers through the appropriate state regulatory agency. At December 31, 2002 and 2001, CL&P's remaining estimated obligations, for decommissioning for the units owned by CYAPC, YAEC and MYAPC, which have been shut down, were $234.5 million and $141.5 million, respectively.
7. Fair Value of Financial Instruments
The following methods and assumptions were used to estimate the fair value of each of the following financial instruments:
Cash and Cash Equivalents: The carrying amounts approximate fair value due to the short-term nature of cash and cash equivalents.
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, 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 629.3 643.0
Rate reduction bonds 1,245.7 1,356.1
--------------------------------------------------------------------------
--------------------------------------------------------------------------
At December 31, 2001
--------------------------------------------------------------------------
(Millions of Dollars) Carrying Amount Fair Value
--------------------------------------------------------------------------
Preferred stock not subject
to mandatory redemption $ 116.2 $ 62.4
Long-term debt -
First mortgage bonds 198.8 212.8
Other long-term debt 625.8 615.1
Rate reduction bonds 1,358.7 1,388.3
--------------------------------------------------------------------------
|
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.
8. Leases
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 million in 2002, $9.2 million in 2001, and $36.3 million in 2000. Interest included in capital lease rental payments was $2 million in 2002, $3.4 million in 2001, and $7.9 million in 2000. Operating lease rental payments charged to expense were $6.9 million in 2002, $7.1 million in 2001, and $9.8 million in 2000.
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, 2002 are as follows:
-------------------------------------------------------------------------- (Millions of Dollars) Capital Operating Year Leases Leases -------------------------------------------------------------------------- 2003 $ 2.6 $12.0 2004 2.5 11.0 2005 2.4 10.2 2006 2.4 9.1 2007 2.4 6.1 After 2007 22.2 15.2 -------------------------------------------------------------------------- Future minimum lease payments $34.5 $63.6 Less amount representing interest 19.0 -------------------------------------------------------------------------- Present value of future minimum lease payments $15.5 -------------------------------------------------------------------------- |
9. Accumulated Other Comprehensive Income/(Loss)
The accumulated balance for each other comprehensive income/(loss) item is as follows:
--------------------------------------------------------------------------
Current
December 31, Period December 31,
(Millions of Dollars 2001 Change 2002
--------------------------------------------------------------------------
Unrealized
gains/(losses)
on securities $ 0.4 $(0.5) $(0.1)
Minimum pension
liability adjustments (0.3) - (0.3)
--------------------------------------------------------------------------
Accumulated other
comprehensive
income/(loss) $ 0.1 $(0.5) $(0.4)
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Current
December 31, Period December 31,
(Millions of Dollars 2000 Change 2001
--------------------------------------------------------------------------
Unrealized
gains/(losses)
on securities $ 0.8 $(0.4) $ 0.4
Minimum pension
liability adjustments (0.3) - (0.3)
--------------------------------------------------------------------------
Accumulated other
comprehensive
income/(loss) $ 0.5 $(0.4) $ 0.1
--------------------------------------------------------------------------
|
The changes in the components of other comprehensive income/(loss) are reported net of the following income tax effects:
-------------------------------------------------------------------------- (Millions of Dollars 2002 2001 2000 -------------------------------------------------------------------------- Unrealized gains/(losses) on securities $0.3 $0.3 $(0.1) Minimum pension liability adjustments - - - -------------------------------------------------------------------------- Accumulated other comprehensive income/(loss) $0.3 $0.3 $(0.1) -------------------------------------------------------------------------- |
10. Preferred Stock Not Subject to Mandatory Redemption
Details of preferred stock not subject to mandatory redemption are as follows:
------------------------------------------------------------------------------
Shares
December 31, Outstanding
2002 at December 31,
Redemption December 31, ------------
Description Price 2002 2002 2001
------------------------------------------------------------------------------
(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
-------------------------------------------------------------------------------
|
11. Long-Term Debt
Details of long-term debt outstanding are as follows:
-------------------------------------------------------------------------------
At December 31, 2002 2001
-------------------------------------------------------------------------------
(Millions of Dollars)
First Mortgage Bonds:
8 1/2% Series C due 2024 $ 59.0 $ 59.0
7 7/8% Series D due 2024 139.8 139.8
------ ------
198.8 198.8
Pollution Control Notes:
Fixed rate, due 2016-2022 46.4 46.4
Fixed rate, tax exempt, due 2028 315.5 315.5
Variable rate, tax exempt, due 2031 62.0 62.0
Fees and interest due for spent
nuclear fuel disposal costs 205.5 201.9
------ ------
629.4 625.8
Less amounts due within one year - -
Unamortized premium and
discount, net (0.3) (0.3)
-------------------------------------------------------------------------------
Long-term debt $827.9 $824.3
-------------------------------------------------------------------------------
|
Essentially, all utility plant of CL&P is subject to the liens of the company's first mortgage bond indenture.
CL&P has secured $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 and a liquidity facility. For financial reporting purposes, these first mortgage bonds would not be considered outstanding unless CL&P failed to meet its obligations under the PCRBs.
The average effective interest rates on the variable-rate pollution control notes ranged from 1.2 percent to 1.7 percent for 2002 and from 1.3 percent to 3.6 percent for 2001.
12. Income Tax Expense
The components of the federal and state income tax provisions were charged/(credited) to operations as follows:
-------------------------------------------------------------------------------
For the Years
Ended December 31, 2002 2001 2000
-------------------------------------------------------------------------------
(Millions of Dollars)
Current income taxes:
Federal $114.4 $190.7 $ 77.2
State 24.3 38.8 17.2
------ ------ ------
Total current 138.7 229.5 94.4
------ ------ ------
Deferred income taxes, net:
Federal (53.3) (117.0) 10.6
State (15.2) (23.8) 2.4
------ ------ ------
Total deferred (68.5) (140.8) 13.0
------ ------ ------
Investment tax credits, net (3.3) (3.8) (7.3)
-------------------------------------------------------------------------------
Total income tax expense $ 66.9 $ 84.9 $100.1
-------------------------------------------------------------------------------
|
Deferred income taxes are comprised of the tax effects of temporary differences as follows:
-------------------------------------------------------------------------------
For the Years
Ended December 31, 2002 2001 2000
-------------------------------------------------------------------------------
(Millions of Dollars
Depreciation, leased nuclear
fuel, settlement credits and
disposal costs $ 34.4 $ (9.2) $ 13.8
Regulatory deferral (68.3) (33.1) (14.1)
State net operating
loss carryforward - - -
Regulatory disallowance 0.3 - -
Sale of generation assets (18.4) (197.6) -
Pension (deferral)/accrual (6.3) 19.9 13.6
Securitized contract
termination
costs and other (5.9) 63.4 -
Other (4.3) 15.8 (0.3)
-------------------------------------------------------------------------------
Deferred income taxes, net $(68.5) $(140.8) $ 13.0
-------------------------------------------------------------------------------
|
A reconciliation between income tax expense and the expected tax expense at the statutory rate is as follows:
-------------------------------------------------------------------------------
For the Years
Ended December 31, 2002 2001 2000
-------------------------------------------------------------------------------
(Millions of Dollars
Expected federal income tax $53.4 $68.1 $ 86.9
Tax effect of differences:
Depreciation 3.8 4.0 5.8
Amortization of
regulatory assets 13.7 (0.6) 3.6
Investment tax credit
amortization (3.3) (3.8) (7.3)
State income taxes,
net of federal benefit 5.9 9.8 12.7
Other, net (6.6) 7.4 (1.6)
-------------------------------------------------------------------------------
Total income tax expense $66.9 $84.9 $100.1
-------------------------------------------------------------------------------
|
13. Segment Information
NU is organized between regulated utilities (electric and gas since the March 1, 2000 acquisition of Yankee) and competitive energy subsidiaries. CL&P is included in the regulated utilities segment of NU and has no other reportable segments.
-------------------------------------------------------------------------------------------------------- Selected Consolidated Financial Data -------------------------------------------------------------------------------------------------------- (Thousands of Dollars) 2002 2001 2000 1999 1998 -------------------------------------------------------------------------------------------------------- Operating Revenues $2,507,036 $2,646,123 $2,935,922 $2,452,855 $2,386,864 Net Income/(Loss) 85,612 109,803 148,135 (13,568) (195,725) Cash Dividends on Common Stock 60,145 60,072 72,014 - - Total Assets 4,632,083 4,727,727 4,764,198 5,298,284 6,050,198 Rate Reduction Bonds 1,245,728 1,358,653 - - - Long-Term Debt (a) 827,866 824,349 1,232,688 1,400,056 2,007,957 Preferred Stock Not Subject to Mandatory Redemption 116,200 116,200 116,200 116,200 116,200 Preferred Stock Subject to Mandatory Redemption (a) - - - 99,539 119,289 Obligations Under Capital Leases (a) 15,499 16,040 129,869 144,400 162,884 -------------------------------------------------------------------------------------------------------- |
(Thousands of Dollars) Quarter Ended ------------------------------------------------------------------------------- 2002 March 31 June 30 September 30 December 31 ------------------------------------------------------------------------------- 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 ------------------------------------------------------------------------------- 2001 ------------------------------------------------------------------------------- Operating Revenues $733,905 $610,275 $675,578 $626,365 Operating Income $ 65,096 $ 68,114 $ 63,103 $ 66,716 Net Income $ 38,300 $ 18,812 $ 18,824 $ 33,867 ------------------------------------------------------------------------------- |
(a) Includes portions due within one year.
Gross Electric
Utility Plant Average Annual
December 31, Use Per Electric
(Thousands of kWh Sales Residential Customers Employees
Dollars) (a) (Millions) Customer (kWh) (Average) December 31,
-------------------------------------------------------------------------------
2002 $3,292,685 29,623 9,244 1,158,307 2,130
2001 3,265,811 32,645 8,884 1,153,234 2,160
2000 5,964,605 42,120 8,976 1,121,551 2,057
1999 6,007,421 29,235 8,969 1,120,846 2,377
1998 6,345,215 27,300 8,476 1,111,370 2,379
|
(a) Amount includes construction work in progress.
EXHIBIT 13.3
2002 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............................... 7 Consolidated Balance Sheets..................................... 8-9 Consolidated Statements of Income............................... 10 Consolidated Statements of Comprehensive Income................. 10 Consolidated Statements of Common Stockholder's Equity.......... 11 Consolidated Statements of Cash Flows........................... 12 Notes to Consolidated Financial Statements...................... 13 Selected Consolidated Financial Data............................ 22 Consolidated Quarterly Financial Data (Unaudited)............... 22 Consolidated Statistics (Unaudited)............................. 23 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 $37.7 million in 2002 compared
with $15 million in 2001. The improved 2002 results were largely due to the
recognition of $13 million in investment tax credits and the elimination of
$9 million of reserves, both in 2002, as a result of regulatory decisions.
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. (Select Energy),
Northeast Generation Company, Northeast Generation Services Company, and
Select Energy Services, Inc.
WMECO's revenues during 2002 decreased to $369.5 million from $478.9 million during 2001 primarily due to lower retail revenues and lower wholesale and other revenues. Retail revenues were lower primarily due to a decrease in the standard offer service rate partially offset by higher distribution revenues from higher retail sales. This decrease in revenues 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 the Millstone nuclear units (Millstone) and the lower sales of energy and capacity due to the buydown and buyout of various cogenerator contracts.
Future Outlook
WMECO is expected to have reduced earnings in 2003 compared to 2002. The
primary reason for the earnings decrease at WMECO is that the positive
results from 2002 regulatory decisions are not expected in 2003. Another
reason for the earnings reduction at WMECO is a significant reduction in the
projected level of pension income in 2003 and forward.
WMECO recorded $12.1 million of pre-tax pension income in 2002, approximately 30 percent of which was capitalized and reflected as a reduction to the cost of capital expenditures with the remainder being recognized in the consolidated statements of income as reductions to operating expenses. In 2003, as a result of continued poor performance in the equity markets, WMECO is projecting the total level of pre-tax pension income to decline to approximately $7 million, with a similar percent being reflected as a reduction to the cost of capital expenditures. Pension income is annually adjusted during the second quarter based upon updated actuarial valuations, and the 2003 estimate may be modified.
Liquidity
In November 2002, WMECO, along with NU's other regulated utilities, renewed
their $300 million credit line, under terms similar to the arrangement that
expired in November 2002. A previous credit line had provided up to $350
million for the regulated companies. WMECO had $7 million in borrowings on
this credit line at December 31, 2002.
Rate reduction bonds are included on the consolidated balance sheets of WMECO, even though the debt is nonrecourse to WMECO. At December 31, 2002, WMECO had a total of $142.7 million in rate reduction bonds outstanding, compared with $152.3 million outstanding at December 31, 2001. All outstanding rate reduction bonds of WMECO are scheduled to be fully amortized by June 1, 2013. Interest on the rate reduction bonds totaled $9.6 million in 2002, compared with $6.3 million in 2001. Amortization of the rate reduction bonds totaled $9.6 million in 2002, compared with $2.7 million in 2001. WMECO fully recovered the amortization and interest payments from customers in 2002 and the bonds had no impact on net income. Moreover, because the debt is nonrecourse to WMECO, the three rating agencies that rate WMECO's debt do not include the revenues, expenses, or outstanding securities related to the rate reduction bonds in establishing the credit ratings of WMECO.
WMECO has applied to the Massachusetts Department of Telecommunications and Energy (DTE) to refinance approximately $100 million of short-term and spent nuclear fuel obligations. A decision is expected in the first half of 2003.
WMECO's net cash flows provided by operating activities decreased to $27.9 million in 2002, compared with $57.5 million in 2001. Cash flows provided by operating activities decreased primarily 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 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. The level of common dividends totaled $16 million in 2002, as compared to $22 million in 2001.
Business Development and Capital Expenditures As a result of a lower than projected growth rate and an adequately sized transmission system to meet near term needs, WMECO does not forecast significant changes in its construction program. WMECO's capital expenditures, excluding nuclear fuel, totaled $23.4 million in 2002, compared with $30.9 million in 2001. WMECO's capital expenditures are expected to total $28.1 million in 2003.
Regional Transmission Organization
The Federal Energy Regulatory Commission (FERC) has required all transmission
owning utilities, including WMECO, to voluntarily start forming regional
transmission organizations (RTO) or to state why this process has not begun.
WMECO has been discussing with the other transmission owners in New England the potential to form an Independent Transmission Company (ITC). If formed, the ITC would be a for-profit entity and would perform certain transmission functions required by the FERC including tariff control, system planning and system operations. The remaining functions required by the FERC would be performed by the Independent System Operator (ISO) regarding the energy market and short-term reliability. Together, the ITC, if formed, and ISO would form the FERC-desired RTO.
In January 2002, the New York and New England ISOs announced their intention to form an RTO. On November 22, 2002, the two ISOs withdrew their joint petition to FERC. The New England ISO intends to make an RTO filing with the transmission owners in New England in 2003. The agreements needed to create the RTO and to define the working relationships among the ISO and the transmission owners should be created in 2003, and will allow the RTO to begin operation shortly thereafter. The agreements are expected to include provisions for the future creation of one or more ITCs within the RTO. The creation of the RTO will require a FERC rate case, and the impact on WMECO's return on equity as a result of this rate case cannot be estimated at this time. At December 31, 2002, WMECO capitalized $0.2 million related to RTO formation activities.
Restructuring and Rate Matters
In December 2001, the DTE approved approximately a 14 percent reduction in
WMECO's overall rates for standard offer service, primarily reflecting a
reduction in WMECO's standard offer service supply costs in 2002 to
approximately $0.048 per kilowatt-hour (kWh) from approximately $0.073 per
kWh. In December 2002, the DTE approved an overall increase of approximately
1.8 percent in WMECO's non-contract standard offer rates, primarily
reflecting slightly increased standard offer and default service costs as
well as other inflationary factors. Select Energy, an NU affiliate, won the
bid to supply WMECO with standard offer service in 2003 at an average rate of
approximately $0.050 per kWh. An unaffiliated company won a bid to serve
WMECO with default service for the period of January 1, 2003 through June 30,
2003, at an average price of $0.051 per kWh.
On June 7, 2002, the DTE issued its decision on WMECO's 1998 through 1999 stranded cost reconciliation. The decision included, among other things, a conclusion that investment tax credits associated with generation assets that have been divested should not be returned to ratepayers. As a result, WMECO recognized approximately $13 million in tax credits during the second quarter of 2002.
On March 30, 2001, WMECO filed its second annual stranded cost reconciliation with the DTE for calendar year 2000. On March 29, 2002, WMECO filed its 2001 annual transition cost reconciliation with the DTE. This filing reconciled the recovery of stranded generation costs for calendar year 2001 and includes sales proceeds from WMECO's portion of the Millstone units, the impact of securitization and approximately a $13 million benefit to ratepayers from WMECO's nuclear performance-based ratemaking process.
Subsequently, WMECO and the office of the Massachusetts Attorney General reached a settlement resolving all transition charge issues for the 1998 through 2001 reconciliations. This settlement was filed for DTE review on December 3, 2002 and approved on December 27, 2002. The settlement had a positive impact of $9 million on WMECO 2002 pre-tax earnings.
For further information regarding commitments and contingencies related to restructuring, see Note 5A, "Commitments and Contingencies - Restructuring and Rate Matters," to the consolidated financial statements.
Nuclear Generation Asset Divestitures
VYNPC: On July 31, 2002, Vermont Yankee Nuclear Power Corporation (VYNPC)
consummated the sale of its nuclear generating unit. WMECO owns 2.6 percent
of VYNPC.
Millstone: On March 31, 2001, WMECO and CL&P consummated the sale of Millstone 1 and 2, and WMECO, CL&P and PSNH sold their ownership interests in Millstone 3.
Under the terms of these asset divestitures, the purchasers agreed to assume responsibility for decommissioning their respective units. For further information regarding nuclear decommissioning, see Note 4, "Nuclear Generation Asset Divestitures," Note 5F, "Commitments and Contingencies - Nuclear Decommissioning and Plant Closure Costs" to the consolidated financial statements. For further information regarding spent nuclear fuel disposal costs, see Note 5C, "Commitments and Contingencies - Spent Nuclear Fuel Disposal Costs," to the consolidated financial statements.
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 condition of WMECO. The following describes 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 significant control is maintained and 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, Maine Yankee Atomic Power Company, and VYNPC, which are classified as variable interest entities under Financial Accounting Standards Board Interpretation No. 46, "Consolidation of Variable Interest Entities," and for which WMECO was not classified as the primary beneficiary. As a result, management does not expect the adoption of Interpretation No. 46 to result in the consolidation of any currently unconsolidated entities or to have any other material impacts on WMECO's consolidated financial statements.
Revenue Recognition: WMECO revenues are based on rates approved by the DTE. These regulated rates are applied to customers' accounts based on their use of energy. In general, rates can only be changed through formal proceedings with the DTE.
The determination of the energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is estimated. This unbilled revenue is estimated each month based on generation volumes, estimated customer usage by class, line losses, and applicable customer rates.
Regulatory Accounting and Assets: The accounting policies of WMECO historically reflect the effects of the rate-making process in accordance with Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." WMECO's transmission and distribution businesses continue to be cost-of-service rate regulated, and management believes the application of SFAS No. 71 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 transmission and distribution businesses no longer meets the criteria of regulatory accounting under SFAS No. 71, that portion of the business would have to discontinue regulatory accounting and write-off regulatory assets. Such a write-off could have a material impact on WMECO's consolidated financial statements.
The application of SFAS No. 71 results in the deferral of costs as regulatory assets that, in some cases, have not yet been approved for recovery by the applicable regulatory commission. Management must conclude that any costs deferred as regulatory assets are probable of future recovery in rates. However, the regulatory commission can reach different conclusions about the recovery of costs, which can have a material impact on WMECO's consolidated financial statements. Management believes that it is probable that WMECO will recover its investments in long-lived assets, including regulatory assets.
Pension and Postretirement Benefit Obligations: WMECO participates in a uniform noncontributory defined benefit retirement plan (Plan) covering substantially all regular NU employees and also provides 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 resultant 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.
WMECO's pre-tax periodic pension income for the Plan, excluding settlements, curtailments, and special termination benefits, totaled $12.1 million and $13.7 million for the years ended December 31, 2002 and 2001, respectively. Pension income is calculated based upon a number of actuarial assumptions, including an expected long-term rate of return on Plan assets of 9.25 percent for 2002 and 9.5 percent for 2001. WMECO expects to use a long-term rate of return assumption of 8.75 percent for 2003. 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 nuclear units. Net SFAS No. 88 items totaled $1.2 million of income and $0.3 million in expense for the years ended December 31, 2002 and 2001, respectively. Approximately 30 percent of net pension income is capitalized as a reduction to capital additions to utility plant.
In developing the expected long-term rate of return assumption, WMECO evaluated input from actuaries, consultants and economists as well as long- term inflation assumptions and NU's historical 20-year compounded return of 10.7 percent. NU's expected long-term rate of return on Plan assets is based on target asset allocation assumptions of 45 percent in United States equities and 14 percent in non-United States equities, both with expected long-term rates of return of 9.25 percent, 3 percent in emerging market equities with an expected long-term return of 10.25 percent, 20 percent in fixed income securities with an expected long-term rate of return of 5.5 percent, 5 percent in high yield fixed income securities with expected long- term rates of return of 7.5 percent, 8 percent in private equities with expected long-term rates of return of 14.25 percent, and 5 percent in real estate with expected long-term rates of return of 7.5 percent. The combination of these target allocations and expected returns results in the overall assumed long-term rate of return of 8.75 percent for 2003. The actual asset allocation at December 31, 2002, was close to these target asset allocations, and WMECO regularly reviews the actual asset allocations and periodically rebalances the investments to the targeted allocation when appropriate. WMECO reduced the long-term rate of return assumption by 0.5 percent and 0.25 percent, respectively, each of the last two years due to lower rate of return assumptions for most asset classes. WMECO believes that 8.75 percent is a reasonable long-term rate of return on Plan assets for 2003. 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.
WMECO bases the actuarial determination of Plan pension income/expense on a market-related valuation of assets, which reduces year-to-year volatility. This market-related valuation 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 value of assets 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 Plan assets. At December 31, 2002, WMECO's portion of the Plan had cumulative unrecognized investment losses of $50.5 million, which will increase Plan expense over the next four years by reducing the expected return on Plan assets. At December 31, 2002, WMECO's portion of the Plan also had cumulative unrecognized actuarial gains of $17.7 million, which will reduce Plan expenses over the expected future working lifetime of active Plan participants, or approximately 13 years. The combined total of unrecognized investment losses and actuarial gains at December 31, 2002 is $32.8 million. This amount impacts the actuarially determined prepaid pension amount recorded on the consolidated balance sheet but has no impact on expected Plan funding.
The discount rate that is utilized in determining future pension 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 Plan's longer duration 0.25 percent was added to this rating. The discount rate determined on this basis has decreased from 7.25 percent at December 31, 2001 to 6.75 percent at December 31, 2002.
Due to the effect of the unrecognized actuarial losses and based on an expected rate of return on Plan assets of 8.75 percent, a discount rate of 6.75 percent and various other assumptions, WMECO estimates that pension income/expense for the Plan will be approximately $7 million in income, approximately $3 million in income and approximately $0.1 million in expense in 2003, 2004 and 2005, respectively. 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 plan.
The value of WMECO's portion of the Plan assets has decreased from $191.2 million at December 31, 2001 to $162.4 million at December 31, 2002. The investment performance returns and declining discount rates have reduced the funded status of WMECO's portion of the Plan, on a projected benefit obligation (PBO) basis, from an overfunded position of $69.9 million at December 31, 2001 to $28.8 million at December 31, 2002. The PBO includes expectations of future employee service and compensation increases. The significant deterioration in the funded position of the Plan will likely result in Plan contributions sooner than previously expected. WMECO has not made contributions since 1991. This deterioration could also lead to the requirement under defined benefit plan accounting to record an additional minimum liability. The total accumulated benefit obligation (ABO) of the entire Plan was $78 million less than Plan assets at December 31, 2002. The ABO is the obligation for employee service provided through December 31, 2002. If the ABO exceeds Plan assets, WMECO may need to record an additional minimum liability in 2003.
Income Taxes: Income tax expense is calculated for each period for which a statement of income is presented. 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 of expenses for tax and book accounting purposes. These differences result in deferred tax assets and liabilities, which are included in the consolidated balance sheets. WMECO must also assess the likelihood that the 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. 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. This asset amounted to $54.2 million and $57.3 million at December 31, 2002 and 2001, respectively.
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.
Environmental Matters: At December 31, 2002, WMECO has recorded a reserve for various environmental liabilities. WMECO's environmental liabilities are based on the best estimate of the amounts to be incurred for the investigation, remediation and monitoring of the remediation sites. It is possible that future cost estimates will either increase or decrease as additional information becomes known.
Special Purpose Entity: WMECO has one special purpose entity, which is currently consolidated in the financial statements. During 2001, to facilitate the issuance of rate reduction certificates intended to finance certain stranded costs, WMECO established WMECO Funding LLC. The funding company was created as part of state sponsored securitization programs. 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 they ever become involved in such bankruptcy proceedings.
For further information regarding these types of activities, see Note 1, "Summary of Significant Accounting Policies," Note 3, "Pension Benefits and Postretirement Benefits Other Than Pensions," Note 5B, "Commitments and Contingencies - Environmental Matters," and Note 10, "Income Tax Expense," to the consolidated financial statements.
Other Matters
Other Commitments and Contingencies: For further information regarding other
commitments and contingencies, see Note 5, "Commitments and Contingencies,"
to the consolidated financial statements.
Contractual Obligations and Commercial Commitments: Information regarding WMECO's contractual obligations and commercial commitments as of December 31, 2002, is summarized through 2007 as follows:
-------------------------------------------------------------------------- (Millions of Dollars) 2003 2004 2005 2006 2007 -------------------------------------------------------------------------- Notes payable to banks $ 7.0 $ - $ - $ - $ - Operating leases 3.5 3.4 3.2 2.9 2.3 Long-term contractual arrangements 10.6 10.3 9.9 9.8 9.6 -------------------------------------------------------------------------- Totals $21.1 $13.7 $13.1 $12.7 $11.9 -------------------------------------------------------------------------- |
Rate reduction bond amounts are not included in this table. For further information regarding WMECO's contractual obligations and commercial commitments, see Note 2, "Short-Term Debt," and Note 5E, "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, 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, and other presently unknown or unforeseen factors.
Results of Operations
The components of significant income statement variances for the past two years are provided in the table below.
--------------------------------------------------------------------------------------------
2002 over/(under)2001 2001 over/(under) 2000
Income Statement Variances --------------------- -----------------------
(Millions of Dollars) Amount Percent Amount Percent
--------------------------------------------------------------------------------------------
Operating Revenues $(109) (23)% $ (35) (7)%
Operating Expenses:
Fuel, purchased and net interchange power (135) (43) 70 28
Other operation (18) (26) (9) (12)
Maintenance (5) (26) (13) (41)
Depreciation 1 4 (4) (22)
Amortization of regulatory assets, net (92) (70) 84 (a)
Taxes other than income taxes (2) (18) (6) (26)
Gain on sale of utility plant 120 (a) (120) (a)
--------------------------------------------------------------------------------------------
Total operating expenses (131) (30) 2 1
--------------------------------------------------------------------------------------------
Operating income 22 58 (37) (50)
Interest expense, net (1) (6) (10) (40)
Other income/(loss), net - - (2) (a)
--------------------------------------------------------------------------------------------
Income before income tax expense 23 (a) (29) (57)
Income tax expense - - (9) (57)
--------------------------------------------------------------------------------------------
Net income/(loss) $ 23 (a)% $ (20) (58)%
============================================================================================
|
(a) Percent greater than 100.
Operating Revenues
Operating revenues decreased $109 million or 23 percent in 2002, primarily
due to lower retail revenues ($71 million) and lower wholesale and other
revenue ($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 the Millstone nuclear units ($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.
Operating revenues decreased $35 million or 7 percent in 2001, primarily due to lower wholesale revenues ($85 million), partially offset by higher regulated retail revenues ($52 million). Wholesale revenues were lower primarily as a result of the sale of the Millstone units at the end of the first quarter of 2001 and lower sales of energy and capacity. Retail revenues increased primarily due to an increase in the standard offer service rate partially offset by lower retail sales. Retail sales decreased by 0.9 percent compared to 2000.
Fuel, Purchased and Net Interchange Power 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).
Fuel, purchased and net interchange power expense increased in 2001, primarily due to higher purchased energy costs associated with the standard offer supply.
Other Operation and Maintenance
Other operation and maintenance (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 units at the end of the first quarter in 2001 ($12 million) and
lower administrative and general expenses ($9 million).
Other O&M expenses decreased in 2001, primarily due to lower nuclear expenses ($29 million) as a result of the sale of the Millstone units at the end of the first quarter in 2001 and lower transmission and distribution expenses ($2 million), partially offset by higher administrative and general expenses ($10 million).
Depreciation
Depreciation increased $1 million in 2002, primarily due to an increase in
utility plant balances.
Depreciation expense decreased in 2001, primarily due to the elimination of decommissioning expenses as a result of the sale of the Millstone units at the end of the first quarter of 2001.
Amortization of Regulatory Assets, Net
Amortization of regulatory assets, net decreased $92 million in 2002
primarily due to the amortization in 2001 related to the sale of the
Millstone units ($120 million) and lower amortization related to the recovery
of the Millstone investment ($9 million), partially offset by higher
amortizations in 2002 related to the recovery of stranded costs ($37
million).
Amortization of regulatory assets, net increased in 2001, primarily due to the amortization in 2001 related to the gain from the sale of Millstone ($120 million), partially offset by lower amortization of nuclear-related transition costs ($22 million) and the current deferral of transition costs ($23 million).
Taxes Other Than Income Taxes
Taxes other than income taxes decreased $2 million in 2002 and $6 million in
2001, primarily due to decreases in local property taxes.
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 2002 and $10 million in 2001,
primarily due to retirement of long-term debt in 2001.
Other Income/(Loss), Net
Other income/(loss), net was unchanged due to lower environmental costs
recorded in 2002 ($3 million) offset by the DTE's order in 2002 resulting in
an adjustment to the gain from the sale of the fossil units ($3 million).
Other income/(loss), net decreased in 2001, primarily due to higher environmental reserves in 2001, partially offset by the settlement, in 2000, of Millstone-related litigation, net of insurance proceeds ($2 million).
Income Tax Expense
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).
Income tax expense decreased in 2001, primarily due to lower revenues resulting from the sale of Millstone.
To the Board of Directors
of Western Massachusetts Electric Company:
We have audited the accompanying consolidated balance sheet of Western Massachusetts Electric Company and subsidiary (a Massachusetts corporation and a wholly owned subsidiary of Northeast Utilities) (the "Company") as of December 31, 2002, and the related consolidated statements of income, comprehensive income, common stockholder's equity, and cash flows for the year then ended. The consolidated financial statements of the Company as of December 31, 2001 and 2000, and for the years 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. 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 audit.
We conducted our audit 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 audit provides a reasonable basis for our opinion.
In our opinion, the 2002 consolidated financial statements present fairly, in all material respects, the financial position of Western Massachusetts Electric Company and subsidiary as of December 31, 2002, and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America.
/s/ DELOITTE & TOUCHE LLP
---------------------
DELOITTE & TOUCHE LLP
Hartford, Connecticut
January 28, 2003
|
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, 2002 2001
-----------------------------------------------------------------------------------------------
(Thousands of Dollars)
ASSETS
------
Current Assets:
Cash........................................................ $ 123 $ 599
Receivables, less provision for uncollectible
accounts of $1,958 in 2002 and $2,028 in 2001............. 42,203 43,761
Accounts receivable from affiliated companies............... 6,369 2,208
Unbilled revenues........................................... 8,944 12,746
Fuel, materials and supplies, at average cost............... 1,821 1,457
Prepayments and other....................................... 1,470 1,544
-------- --------
60,930 62,315
-------- --------
Property, Plant and Equipment:
Electric utility............................................ 590,153 564,857
Less: Accumulated depreciation........................... 195,804 186,784
-------- --------
394,349 378,073
Construction work in progress............................... 11,860 18,326
-------- --------
406,209 396,399
-------- --------
Deferred Debits and Other Assets:
Regulatory assets........................................... 283,702 320,222
Prepaid pension............................................. 67,516 54,226
Other ...................................................... 18,304 19,500
-------- --------
369,522 393,948
-------- --------
Total Assets.................................................. $836,661 $852,662
======== ========
|
The accompanying notes are an integral part of these consolidated financial statements.
WESTERN MASSACHUSETTS ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
-----------------------------------------------------------------------------------------
At December 31, 2002 2001
-----------------------------------------------------------------------------------------
(Thousands of Dollars)
LIABILITIES AND CAPITALIZATION
------------------------------
Current Liabilities:
Notes payable to banks................................... $ 7,000 $ 50,000
Notes payable to affiliated companies.................... 85,900 9,200
Accounts payable......................................... 17,730 34,970
Accounts payable to affiliated companies................. 6,233 2,982
Accrued taxes............................................ 4,334 3,691
Accrued interest......................................... 2,059 2,201
Other.................................................... 8,005 10,127
-------- --------
131,261 113,171
-------- --------
Rate Reduction Bonds....................................... 142,742 152,317
-------- --------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes........................ 222,065 229,893
Accumulated deferred investment tax credits.............. 3,662 3,998
Deferred contractual obligations......................... 63,767 37,357
Other.................................................... 13,213 64,309
-------- --------
302,707 335,557
-------- --------
Capitalization:
Long-Term Debt........................................... 101,991 101,170
-------- --------
Common Stockholder's Equity:
Common stock, $25 par value - authorized
1,072,471 shares; 434,653 shares outstanding
in 2002 and 509,696 shares outstanding in 2001........ 10,866 12,742
Capital surplus, paid in............................... 69,712 82,224
Retained earnings...................................... 77,476 55,422
Accumulated other comprehensive (loss)/income.......... (94) 59
-------- --------
Common Stockholder's Equity.............................. 157,960 150,447
-------- --------
Total Capitalization....................................... 259,951 251,617
-------- --------
Commitments and Contingencies (Note 5)
Total Liabilities and Capitalization....................... $836,661 $852,662
======== ========
|
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, 2002 2001 2000
---------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Operating Revenues...................................... $369,487 $478,869 $513,678
-------- -------- --------
Operating Expenses:
Operation -
Fuel, purchased and net interchange power.......... 181,485 315,903 246,130
Other.............................................. 49,039 66,458 75,940
Maintenance........................................... 14,499 19,635 33,111
Depreciation.......................................... 14,381 13,818 17,693
Amortization of regulatory assets, net................ 39,712 131,876 47,775
Taxes other than income taxes......................... 10,688 13,065 17,759
Gain on sale of utility plant......................... - (119,775) -
-------- -------- --------
Total operating expenses........................ 309,804 440,980 438,408
-------- -------- --------
Operating Income........................................ 59,683 37,889 75,270
Interest Expense:
Interest on long-term debt............................ 2,942 4,940 13,754
Interest on rate reduction bonds...................... 9,587 6,251 -
Other interest........................................ 1,857 4,120 11,788
-------- -------- --------
Interest expense, net.............................. 14,386 15,311 25,542
-------- -------- --------
Other (Loss)/Income, Net................................ (850) (1,050) 685
-------- -------- --------
Income Before Income Tax Expense........................ 44,447 21,528 50,413
Income Tax Expense...................................... 6,765 6,560 15,145
-------- -------- --------
Net Income.............................................. $ 37,682 $ 14,968 $ 35,268
======== ======== ========
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Net Income.............................................. $ 37,682 $ 14,968 $ 35,268
-------- -------- --------
Other comprehensive (loss)/income, net of tax:
Unrealized (losses)/gains on securities............... (110) (123) 22
Minimum pension liability adjustments................. (43) - -
-------- -------- --------
Comprehensive Income.................................... $ 37,529 $ 14,845 $ 35,290
======== ======== ========
|
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
Capital Other
Common Surplus, Retained Comprehensive Total
Stock Paid In Earnings Income/(Loss) (a)
----------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Balance at January 1, 2000........................ $ 26,812 $171,691 $ 38,712 $ 160 $237,375
Net income for 2000........................... 35,268 35,268
Cash dividends on preferred stock............. (2,798) (2,798)
Cash dividends on common stock................ (12,002) (12,002)
Repurchase of common stock.................... (12,060) (77,940) (90,000)
Capital stock expenses, net................... 259 259
Allocation of benefits - ESOP (b)............. 3,772 3,772
Other comprehensive income.................... 22 22
-------- -------- -------- ----- --------
Balance at December 31, 2000...................... 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.................... (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...................... 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.................... (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...................... $ 10,866 $ 69,712 $ 77,476 $ (94) $157,960
======== ======== ======== ===== ========
|
(a) The company has no dividend restrictions. However, the company has two tests it must meet before it can pay out any dividends. The most restrictive of which limits the company to paying out no greater than $77.5 million of equity at December 31, 2002.
(b) In June 1999, WMECO paid NU parent $6.9 million for NU shares issued from 1992 through 1998 on behalf of its employees in accordance with NU's 401(k) plan. This transaction resulted in a reduction of the NU parent loss and a tax benefit to WMECO. The amount in 2000 represents the remaining previously unallocated 1993 through 1999 NU parent losses.
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, 2002 2001 2000
------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Operating Activities:
Net income...................................................... $ 37,682 $ 14,968 $ 35,268
Adjustments to reconcile to net cash flows
provided by operating activities:
Depreciation.................................................. 14,381 13,818 17,693
Deferred income taxes and investment tax credits, net......... (26,952) 5,281 (11,549)
Net (deferral)/amortization of recoverable energy costs....... (529) 3,179 9,386
Amortization of regulatory assets, net........................ 39,712 131,876 47,775
Gain on sale of utility plant................................. - (119,775) -
Prepaid pension............................................... (13,290) (8,453) (45,773)
Net other (uses)/sources of cash.............................. (8,221) (988) 26,570
Changes in working capital:
Receivables and unbilled revenues, net........................ 1,199 15,017 (24,637)
Fuel, materials and supplies.................................. (365) 149 1,491
Accounts payable.............................................. (13,989) 4,043 17,727
Accrued taxes................................................. 643 (4,780) 7,882
Other working capital (excludes cash)......................... (2,351) 3,204 (7,321)
-------- --------- --------
Net cash flows provided by operating activities................... 27,920 57,539 74,512
-------- --------- --------
Investing Activities:
Investments in plant:
Electric utility plant........................................ (23,428) (30,921) (27,267)
Nuclear fuel.................................................. - (140) (7,848)
-------- --------- --------
Cash flows used for investments in plant........................ (23,428) (31,061) (35,115)
NU system Money Pool borrowing/(lending)........................ 76,700 8,600 (8,800)
Investments in nuclear decommissioning trusts................... - (23,037) (3,437)
Net proceeds from the sale of utility plant..................... - 175,154 185,787
Buyout of IPP contract.......................................... - (80,000) -
Other investment activities, net................................ 937 817 3,589
-------- --------- --------
Net cash flows provided by investing activities................... 54,209 50,473 142,024
-------- --------- --------
Financing Activities:
Repurchase of common stock...................................... (13,999) (15,000) (90,000)
Issuance of rate reduction bonds................................ - 155,000 -
Retirement of rate reduction bonds.............................. (9,575) (2,683) -
Net decrease in short-term debt................................. (43,000) (60,000) (13,000)
Reacquisitions and retirements of long-term debt................ - (100,000) (94,150)
Reacquisitions and retirements of preferred stock............... - (36,500) (1,500)
Retirement of capital lease obligation.......................... - (34,200) -
Cash dividends on preferred stock............................... - (404) (2,798)
Cash dividends on common stock.................................. (16,009) (22,000) (12,002)
Other financing activities, net................................. (22) 7,389 (3,051)
-------- --------- --------
Net cash flows used in financing activities....................... (82,605) (108,398) (216,501)
-------- --------- --------
Net (decrease)/increase in cash................................... (476) (386) 35
Cash - beginning of year.......................................... 599 985 950
-------- --------- ---------
Cash - end of year................................................ $ 123 $ 599 $ 985
========= ========= =========
Supplemental Cash Flow Information:
Cash paid during the year for:
Interest, net of amounts capitalized............................ $ 14,934 $ 17,939 $ 26,055
======== ========= ========
Income taxes.................................................... $ 32,522 $ 6,314 $ 18,554
======== ========= ========
|
The accompanying notes are an integral part of these consolidated financial statements.
Notes to Consolidated Financial Statements
1. Summary of Significant Accounting Policies
A. About Western Massachusetts Electric Company Western Massachusetts Electric Company (WMECO or the company) along with The Connecticut Light and Power Company (CL&P), and Public Service Company of New Hampshire (PSNH), North Atlantic Energy Corporation (NAEC), Holyoke Water Power Company (HWP) and Yankee Energy System, Inc. (Yankee) are the operating companies comprising the Northeast Utilities system and are wholly owned by Northeast Utilities (NU). WMECO furnishes franchised retail electric service in western Massachusetts, while CL&P and PSNH furnish franchised retail electric service in Connecticut and New Hampshire. NAEC previously sold all of its entitlement to the capacity and output of the Seabrook Station 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. NU's other subsidiaries include HWP, a company engaged in the production of electric power, Yankee, the parent company of Yankee Gas Services Company (Yankee Gas), Connecticut's largest natural gas distribution system, and several other competitive subsidiaries including Select Energy, Inc., Northeast Generation Company, Northeast Generation Services Company, and Select Energy Services, Inc.
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).
Several wholly owned subsidiaries of NU provide support services for NU's companies, including WMECO, and in some cases, for other New England utilities. Northeast Utilities Service Company (NUSCO) provides centralized accounting, administrative, engineering, financial, information resources, legal, operational, planning, purchasing, and other services to NU's companies. Until the sale of Seabrook on November 1, 2002, North Atlantic Energy Service Corporation had operational responsibility for Seabrook. Three other subsidiaries construct, acquire or lease some of the property and facilities used by NU's companies.
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 contingent liabilities 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.
C. New Accounting Standards Asset Retirement Obligations: In June 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (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 is effective on January 1, 2003, for WMECO. Management has completed its review process for potential asset retirement obligations (AROs) and has not identified any material AROs which have been incurred. However, management has identified certain removal obligations which arise in the ordinary course of business that either have a low probability of occurring or are not material in nature. 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.
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, 2002, WMECO maintained approximately $16.6 million in total cost of removal regulatory liabilities, which are included in the accumulated provision for depreciation.
Guarantees: In November 2002, the FASB issued Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others." Interpretation No. 45 requires that disclosures be made by a guarantor in its interim and annual financial statements about its obligations under certain guarantees that it has issued and clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. Interpretation No. 45 does not apply to certain guarantee contracts, such as residual value guarantees provided by lessees in capital leases, guarantees that are accounted for as derivatives, guarantees that represent contingent consideration in a business combination, guarantees issued between either parents and their subsidiaries or corporations under common control, a parent's guarantee of a subsidiary's debt to a third party, and a subsidiary's guarantee of the debt owed to a third party by either its parent or another subsidiary of that parent. The initial recognition and initial measurement provisions of Interpretation No. 45 are applicable to WMECO on a prospective basis to guarantees issued or modified after January 1, 2003. Currently, management does not expect the adoption of the initial recognition and initial measurement provisions of Interpretation No. 45 to have a material impact on WMECO's consolidated financial statements.
Consolidation of Variable Interest Entities: In January 2003, the FASB issued Interpretation No. 46, "Consolidation of Variable Interest Entities." Interpretation No. 46 addresses the consolidation and disclosure requirements for companies that hold an equity interest in a variable interest entity (VIE), regardless of the date on which the VIE was created. Interpretation No. 46 requires consolidation of a VIE's assets, liabilities and noncontrolling interests at fair value when a company is the primary beneficiary, which is defined as a company that absorbs a majority of the expected losses, risks and revenues from the VIE as a result of holding a contractual or other financial interest in the VIE. Consolidation is not required under Interpretation No. 46 for those companies that hold a significant equity interest in a VIE but are not the primary beneficiary. Interpretation No. 46 is effective for WMECO beginning in the third quarter of 2003. At December 31, 2002, WMECO held equity interests in various VIEs, for which WMECO was not the primary beneficiary, as WMECO does not absorb a majority of the expected losses, risks and revenues from the VIEs or provide a substantial portion of financial support. As a result, management does not expect the adoption of Interpretation No. 46 to have a material impact on WMECO's consolidated financial statements. For further information regarding WMECO's investments in its VIEs, see Note 1D, "Equity Investments and Jointly Owned Electric Utility Plant" to the consolidated financial statements.
D. Equity Investments and Jointly Owned Electric Utility Plant Regional Nuclear Generating Companies: WMECO owns common stock in four regional nuclear companies (Yankee Companies). WMECO's ownership interests in the Yankee Companies at December 31, 2002 and 2001, which are accounted for on the equity method are 9.5 percent of the Connecticut Yankee Atomic Power Company (CYAPC), 7 percent of the Yankee Atomic Electric Company (YAEC), 3 percent of the Maine Yankee Atomic Power Company (MYAPC), and 2.6 percent of the Vermont Yankee Nuclear Power Corporation (VYNPC). WMECO's total equity investment in the Yankee Companies and its exposure to loss as a result of these investments at December 31, 2002 and 2001, is $8.6 million and $9.3 million, respectively. These investments are VIEs under FASB Interpretation No. 46. Excluding VYNPC, which sold its nuclear generating plant, each Yankee Company owns a single decommissioned nuclear generating plant. On July 31, 2002, VYNPC consummated the sale of its nuclear generating plant to a subsidiary of Entergy Corporation for approximately $180 million.
E. 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. The depreciation rates for the several classes of electric plant-in-service are equivalent to a composite rate of 2.3 percent in 2002 and 2001 and 2.2 percent in 2000.
F. Revenues Revenues are based on rates approved by the DTE. These regulated rates are applied to customer's accounts based on their use of energy. In general, rates can only be changed through formal proceedings with the DTE.
The determination of the energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is estimated. This unbilled revenue is estimated each month based on generation volumes, estimated customer usage by class, line losses, and applicable customer rates.
G. Regulatory Accounting and Assets 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."
WMECO's transmission and distribution businesses 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 also believes it is probable that WMECO will recover its investments in long-lived assets, including regulatory assets. In addition, all material regulatory assets are earning a return, except for securitized regulatory assets. The components of WMECO's regulatory assets are as follows:
--------------------------------------------------------------------------
At December 31,
--------------------------------------------------------------------------
(Millions of Dollars) 2002 2001
--------------------------------------------------------------------------
Recoverable nuclear costs $ 38.0 $ 38.5
Securitized regulatory assets 141.9 149.6
Income taxes, net 54.2 57.3
Unrecovered contractual
obligations 63.8 37.4
Recoverable energy costs, net 4.3 3.8
Other (18.5) 33.6
--------------------------------------------------------------------------
Totals $283.7 $320.2
--------------------------------------------------------------------------
|
At December 31, 2002, other regulatory assets included a regulatory liability in the amount of $29.8 million, related to the WMECO rate cap deferral.
In March 2001, WMECO sold its ownership interest in the Millstone units. The gain on this sale of approximately $119.8 million was used to offset recoverable nuclear costs, resulting in a total unamortized balance of $7.1 million and $3.2 million at December 31, 2002 and 2001, respectively. Also included in recoverable nuclear costs for 2002 and 2001 are $30.9 million and $35.3 million, respectively, primarily related to Millstone 1 recoverable nuclear costs associated with the recoverable portion of the undepreciated plant and related assets.
In May 2001, WMECO issued $155 million in rate reduction certificates and used $80 million of those proceeds to buyout an independent power producer contract. The majority of the payment to buyout this contract was recorded as a securitized regulatory asset.
WMECO, 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, 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.
WMECO, under the Energy Policy Act of 1992 (Energy Act), 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) when they owned nuclear generating plants. 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 is currently recovering these costs through rates. At December 31, 2002 and 2001, WMECO's total D&D Assessment deferrals were $4.3 million and $3.8 million, respectively, and have been recorded as recoverable energy costs, net.
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, "Accounting for Income Taxes."
The tax effect of temporary differences, including timing differences accrued under previously approved accounting standards, that give rise to the accumulated deferred tax obligation is as follows:
--------------------------------------------------------------------------
At December 31,
--------------------------------------------------------------------------
(Millions of Dollars) 2002 2001
--------------------------------------------------------------------------
Accelerated depreciation and
other plant-related differences $ 66.6 $107.5
Regulatory assets:
Nuclear stranded investment and
other asset divestitures 57.3 52.3
Securitized contract termination
costs and other 34.8 38.4
Income tax gross-up 21.1 19.0
Other 42.3 12.7
--------------------------------------------------------------------------
Totals $222.1 $229.9
--------------------------------------------------------------------------
|
I. Other Income/(Loss), Net The components of WMECO's other income/(loss), net items are as follows:
--------------------------------------------------------------------------
For the Years Ended December 31,
--------------------------------------------------------------------------
(Millions of Dollars) 2002 2001 2000
--------------------------------------------------------------------------
Investment income $ 1.6 $ 0.9 $ 3.6
Other, net (2.5) (2.0) (2.9)
--------------------------------------------------------------------------
Totals $(0.9) $(1.1) $ 0.7
--------------------------------------------------------------------------
|
2. Short-Term Debt
Limits: The amount of short-term borrowings that may be incurred by WMECO is subject to periodic approval by either the SEC under the 1935 Act or by the DTE. Currently, SEC authorization allows WMECO to incur total short-term borrowings up to a maximum of $250 million.
Credit Agreement: On November 12, 2002, WMECO, CL&P, PSNH, and Yankee Gas entered into a 364-day unsecured revolving credit facility for $300 million. This facility replaced a $350 million facility for WMECO, CL&P, PSNH and Yankee Gas, which expired on November 15, 2002. WMECO may draw up to $100 million under this facility. Unless extended, the credit facility will expire on November 11, 2003. At December 31, 2002 and 2001, there were $7 million and $50 million in borrowings, respectively, under these 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, 2002 and 2001, were 4.25 percent and 2.98 percent, respectively.
This credit agreement provides that 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. WMECO currently is and expects to remain in compliance with these covenants.
Money Pool: Certain subsidiaries of NU, including WMECO, are members of the Northeast Utilities System Money Pool (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, 2002 and 2001, WMECO had $85.9 million and $9.2 million, respectively, of borrowings from the Pool. The interest rate on borrowings from the Pool at December 31, 2002 and 2001, was 1.2 percent and 1.5 percent, respectively.
3. Pension Benefits and Postretirement Benefits Other Than Pensions
Pension Benefits: WMECO participates in a uniform noncontributory defined benefit retirement plan (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, approximately 30 percent of which was credited to utility plant, was $12.1 million in 2002, $13.7 million in 2001 and $12.4 million in 2000. These amounts exclude pension settlements, curtailments and net special termination expenses of $1.2 million in income in 2002, $0.3 million in expense in 2001 and $6.6 million in income in 2000. Pension income attributable to earnings is as follows:
--------------------------------------------------------------------------
For Years Ended December 31,
--------------------------------------------------------------------------
(Millions of Dollars) 2002 2001 2000
--------------------------------------------------------------------------
Pension income before
settlements, curtailments
and special termination benefits $(12.1) $(13.7) $(12.4)
Net pension income
capitalized as utility plant (a) 3.6 4.1 3.7
--------------------------------------------------------------------------
Net pension income before
settlements, curtailments
and special termination benefits (8.5) (9.6) (8.7)
Settlements, curtailments and
special termination benefits
reflected in earnings - 0.7 -
--------------------------------------------------------------------------
Total pension income
included in earnings $ (8.5) $ (8.9) $ (8.7)
--------------------------------------------------------------------------
|
(a) Net pension income capitalized as utility plant was calculated utilizing an average of 30 percent.
In conjunction with the Voluntary Separation Program (VSP) that was announced in December 2000, WMECO recorded $0.2 million in settlement income. 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 five 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 and $0.4 million was deferred as a regulatory liability and has been returned to customers.
Additionally, in conjunction with the divestiture of its generation assets, WMECO recorded $1.2 million in curtailment income in 2002 and $6.6 million of curtailment income in 2000.
Postretirement Benefits Other Than Pensions (PBOP): The NU subsidiaries, including WMECO, also provide certain health care benefits, primarily medical and dental, and life insurance benefits through a benefit plan to retired employees. 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. WMECO annually funds postretirement costs through external trusts with amounts that have been rate-recovered and which also are tax deductible.
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 regulated utility rates in 2002.
Additionally, in conjunction with the divestiture of its generation assets, WMECO recorded $0.4 million in special termination benefits income in 2000.
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 $2.8 million decrease in WMECO's benefit obligation under the PBOP plan at December 31, 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) 2002 2001 2002 2001
------------------------------------------------------------------------------------------------
Change in benefit obligation
Benefit obligation at beginning of year $(121.3) $(121.1) $(35.5) $(29.3)
Service cost (2.2) (1.9) (0.4) (0.4)
Interest cost (8.7) (8.5) (2.9) (2.4)
Plan amendment (1.1) - 2.8 -
Transfers (0.2) 4.9 (4.8) -
Actuarial loss (8.2) (3.0) (4.2) (7.0)
Benefits paid - excluding lump sum payments 8.1 8.0 3.6 3.6
Benefits paid - lump sum payments - 0.7 - -
Curtailments and settlements - 0.1 - -
Special termination benefits - (0.5) - -
------------------------------------------------------------------------------------------------
Benefit obligation at end of year $(133.6) $(121.3) $(41.4) $(35.5)
------------------------------------------------------------------------------------------------
Change in plan assets
Fair value of plan assets at beginning of year $ 191.2 $ 214.3 $ 14.7 $ 17.3
Actual return on plan assets (20.9) (9.5) (1.5) (1.6)
Employer contribution - - 3.6 2.6
Benefits paid - excluding lump sum payments (8.1) (8.0) (3.6) (3.6)
Benefits paid - lump sum payments - (0.7) - -
Transfers 0.2 (4.9) 2.2 -
------------------------------------------------------------------------------------------------
Fair value of plan assets at end of year $ 162.4 $ 191.2 $ 15.4 $ 14.7
------------------------------------------------------------------------------------------------
Funded status at December 31 $ 28.8 $ 69.9 $(26.0) $(20.8)
Unrecognized transition (asset)/obligation (0.5) (0.7) 13.8 17.4
Unrecognized prior service cost 6.4 6.0 (0.7) -
Unrecognized net loss/(gain) 32.8 (21.0) 11.7 3.8
------------------------------------------------------------------------------------------------
Prepaid/(accrued) benefit cost $ 67.5 $ 54.2 $ (1.2) $ 0.4
------------------------------------------------------------------------------------------------
|
The following actuarial assumptions were used in calculating the plans' year end funded status:
-------------------------------------------------------------------------------
At December 31,
-------------------------------------------------------------------------------
Pension Benefits Postretirement Benefits
-------------------------------------------------------------------------------
2002 2001 2002 2001
-------------------------------------------------------------------------------
Discount rate 6.75% 7.25% 6.75% 7.25%
Compensation/progression rate 4.00% 4.25% 4.00% 4.25%
Health care cost trend rate (a) N/A N/A 10.00% 11.00%
-------------------------------------------------------------------------------
|
(a) The annual per capita cost of covered health care benefits was assumed to decrease to 5.00 percent by 2007.
The components of net periodic benefit (income)/expense are:
-----------------------------------------------------------------------------------------------------
For the Years Ended December 31,
-----------------------------------------------------------------------------------------------------
Pension Benefits Postretirement Benefits
-----------------------------------------------------------------------------------------------------
(Millions of Dollars) 2002 2001 2000 2002 2001 2000
-----------------------------------------------------------------------------------------------------
Service cost $ 2.2 $ 1.9 $ 2.2 $ 0.4 $ 0.4 $ 0.4
Interest cost 8.7 8.5 8.9 2.9 2.3 2.2
Expected return on plan assets (19.9) (20.0) (19.0) (1.5) (1.4) (1.3)
Amortization of unrecognized net
transition (asset)/obligation (0.2) (0.2) (0.2) 1.5 1.6 1.6
Amortization of prior service cost 0.7 0.6 0.6 - - -
Amortization of actuarial gain (3.6) (4.5) (4.9) - - -
Other amortization, net - - - 0.2 (0.4) (0.4)
-----------------------------------------------------------------------------------------------------
Net periodic (income)/expense - before
settlements, curtailments and special
termination benefits (12.1) (13.7) (12.4) 3.5 2.5 2.5
-----------------------------------------------------------------------------------------------------
Settlement income - (0.2) - - - -
Curtailment income (1.2) - (6.6) - - -
Special termination benefits expense/(income) - 0.5 - - 0.1 (0.4)
-----------------------------------------------------------------------------------------------------
Total - settlements, curtailments and special
termination benefits (1.2) 0.3 (6.6) - 0.1 (0.4)
-----------------------------------------------------------------------------------------------------
Total - net periodic (income)/expense $(13.3) $(13.4) $(19.0) $ 3.5 $ 2.6 $ 2.1
-----------------------------------------------------------------------------------------------------
|
For calculating pension and postretirement benefit costs, the following assumptions were used:
-----------------------------------------------------------------------------------------
For the Years Ended December 31,
-----------------------------------------------------------------------------------------
Pension Benefits Postretirement Benefits
-----------------------------------------------------------------------------------------
2002 2001 2000 2002 2001 2000
-----------------------------------------------------------------------------------------
Discount rate 7.25% 7.50% 7.75% 7.25% 7.50% 7.75%
Expected long-term rate of return 9.25% 9.50% 9.50% N/A N/A N/A
Compensation/progression rate 4.25% 4.50% 4.75% 4.25% 4.50% 4.75%
Long-term rate of return -
Health assets, net of tax N/A N/A N/A 7.25% 7.50% 7.50%
Life assets N/A N/A N/A 9.25% 9.50% 9.50%
-----------------------------------------------------------------------------------------
|
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 $1.3 $(1.1)
--------------------------------------------------------------------------
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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.
Pension and trust assets are invested primarily in domestic and international equity securities and bonds.
The trust holding the postretirement health plan assets is subject to federal income taxes.
4. Nuclear Generation Asset Divestitures
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. Under the terms of the sale, WMECO will continue to buy 2.5 percent of the plant's output through March 2012 at a range of fixed prices.
Millstone: On March 31, 2001, WMECO and CL&P consummated the sale of Millstone 1 and 2 to a subsidiary of Dominion Resources, Inc. (Dominion). WMECO, CL&P and PSNH sold their ownership interests in Millstone 3 to Dominion along with all of the unaffiliated joint ownership interests in Millstone 3. WMECO received approximately $175 million of cash proceeds from the sale and applied the proceeds to taxes and reductions of debt and equity. As part of the sale, Dominion assumed responsibility for decommissioning the three Millstone units. In connection with the sale, WMECO recorded a gain in the amount of approximately $119.8 million, which was used to offset stranded costs.
5. Commitments and Contingencies
A. Restructuring and Rate Matters On March 30, 2001, WMECO filed its second annual stranded cost reconciliation with the DTE for calendar year 2000. On March 29, 2002, WMECO filed its 2001 annual transition cost reconciliation with the DTE. This filing reconciled the recovery of stranded generation costs for calendar year 2001 and includes sales proceeds from WMECO's portion of the Millstone units, the impact of securitization and approximately a $13 million benefit to ratepayers from WMECO's nuclear performance-based ratemaking process.
WMECO and the office of the Massachusetts Attorney General reached a settlement resolving all transition charge issues for the 1998 through 2001 reconciliations. The DTE approved this settlement on December 27, 2002. The settlement had a positive impact of $9 million on WMECO 2002 pre-tax earnings.
B. Environmental Matters 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. As such, WMECO has active environmental auditing and training programs and believes it is substantially in compliance with the current laws and regulations.
However, the normal course of operations may involve activities and substances that expose WMECO to potential liabilities of which management cannot determine the outcome. Additionally, management cannot determine the outcome for liabilities that may be imposed for past acts, even though such past acts may have been lawful at the time they occurred. Management does not believe, however, that this will have a material impact on WMECO's consolidated financial statements.
Based upon currently available information for the estimated remediation costs as of December 31, 2002 and 2001, the liability recorded by WMECO for its estimated environmental remediation costs amounted to $0.8 million and $5.3 million, respectively.
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. As of December 31, 2002 and 2001, fees due to the DOE for the disposal of Prior Period Fuel were $48.2 million and $47.4 million, respectively, including interest costs of $32.6 million and $31.8 million, respectively.
Fees for nuclear fuel burned on or after April 7, 1983, were billed currently to customers and paid to the DOE on a quarterly basis. At December 31, 2002, as WMECO's ownership share of Millstone has been sold, WMECO is no longer responsible for fees relating to current fuel burned at this facility.
D. Nuclear Insurance Contingencies In conjunction with the divestiture of Millstone in 2001, NU and WMECO terminated their nuclear insurance related to these plants, 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 and VYNPC, 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, operation and maintenance (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 $4.3 million in 2002, $4.1 million in 2001 and $4 million in 2000.
Electricity Procurement Contract: WMECO entered into an arrangement for the purchase of electricity. The total cost of purchases under this arrangement amounted to $2.5 million in 2002, $14.5 million in 2001 and $28.5 million in 2000. These amounts are for independent power producer 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) 2003 2004 2005 2006 2007 ------------------------------------------------------------------------------- VYNPC $ 4.8 $ 4.6 $4.2 $4.4 $4.3 Electricity Procurement Contract 2.8 2.8 2.8 2.8 2.8 Hydro-Quebec 3.0 2.9 2.9 2.6 2.5 ------------------------------------------------------------------------------- Totals $10.6 $10.3 $9.9 $9.8 $9.6 ------------------------------------------------------------------------------- |
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.
During 2002, NU, along with the other joint owners, were notified by the Yankee Companies that the estimated cost of decommissioning the units owned by CYAPC, YAEC and MYAPC increased in total by approximately $380 million over prior estimates due to higher anticipated costs for spent fuel storage, security and liability and property insurance. WMECO's share of this increase totals $32.4 million. Following rate cases to be filed by the Yankee Companies with the FERC, NU will seek recovery of the higher decommissioning costs from retail customers through the appropriate state regulatory agency. At December 31, 2002 and 2001, WMECO's remaining estimated obligations, for decommissioning for the units owned by CYAPC, YAEC and MYAPC, which have been shut down, were $63.8 million and $37.4 million, respectively.
6. Fair Value of Financial Instruments
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, 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
-------------------------------------------------------------------------------
-------------------------------------------------------------------------------
At December 31, 2001
-------------------------------------------------------------------------------
(Millions of Dollars) Carrying Amount Fair Value
-------------------------------------------------------------------------------
Long-term debt -
Other long-term debt $101.2 $101.0
Rate reduction bonds 152.3 154.1
-------------------------------------------------------------------------------
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Other Financial Instruments: The carrying value of financial instruments included in current assets and current liabilities, approximates their fair value.
7. Leases
WMECO has entered into lease agreements for the use of data processing and office equipment, vehicles, nuclear control room simulators, and office space. The provisions of these lease agreements generally provide for renewal options.
Capital lease rental payments charged to operating expense were $1.9 million and $9.6 million for 2001 and 2000, respectively. Interest included in capital lease rental payments was $0.7 million in 2001 and $2.8 million in 2000. Operating lease rental payments charged to expense were $2.3 million in 2002, $2.5 million in 2001, and $3.2 million in 2000.
Future minimum rental payments, excluding executory costs such as property taxes, state use taxes, insurance, and maintenance, under long-term noncancelable operating leases, as of December 31, 2002, are as follows:
-----------------------------------------------------------
Year
-----------------------------------------------------------
(Millions of Dollars)
-----------------------------------------------------------
2003 $ 3.5
2004 3.4
2005 3.2
2006 2.9
2007 2.3
After 2007 10.5
-----------------------------------------------------------
Future minimum lease payments $25.8
-----------------------------------------------------------
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8. Accumulated Other Comprehensive Income/(Loss)
The accumulated balance for each other comprehensive income/(loss) item is as follows:
--------------------------------------------------------------------------
Current
December 31, Period December 31,
(Millions of Dollars) 2001 Change 2002
--------------------------------------------------------------------------
Unrealized
gains/(losses)
on securities $0.1 $(0.1) $ -
Minimum pension
liability adjustments - (0.1) (0.1)
--------------------------------------------------------------------------
Accumulated other
comprehensive
income/(loss) $0.1 $(0.2) $(0.1)
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Current
December 31, Period December 31,
(Millions of Dollars) 2000 Change 2001
--------------------------------------------------------------------------
Unrealized
gains/(losses)
on securities $0.2 $0.1 $0.1
--------------------------------------------------------------------------
Accumulated other
comprehensive
income/(loss) $0.2 $0.1 $0.1
--------------------------------------------------------------------------
|
The changes in the components of other comprehensive income/(loss) are reported net of the following income tax effects:
-------------------------------------------------------------------------- (Millions of Dollars) 2002 2001 2000 -------------------------------------------------------------------------- Unrealized gains/(losses) on securities $0.1 $0.1 $ - Minimum pension liability adjustments - - - -------------------------------------------------------------------------- Accumulated other comprehensive income/(loss) $0.1 $0.1 $ - -------------------------------------------------------------------------- |
9. Long-Term Debt
Details of long-term debt outstanding are as follows:
--------------------------------------------------------------------------
At December 31, 2002 2001
--------------------------------------------------------------------------
(Millions of Dollars)
Pollution Control Notes:
Tax Exempt 1993 Series A,
5.85% due 2028 $ 53.8 $ 53.8
Fees and interest due for spent
nuclear fuel disposal costs 48.2 47.4
Less amounts due within one year - -
--------------------------------------------------------------------------
Long-term debt $102.0 $101.2
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WMECO has secured $53.8 million of pollution control notes with second mortgage liens on transmission assets.
10. Income Tax Expense
The components of the federal and state income tax provisions are as follows:
-------------------------------------------------------------------------------
For the Years Ended
December 31, 2002 2001 2000
-------------------------------------------------------------------------------
(Millions of Dollars)
Current income taxes:
Federal $ 27.9 $ 0.3 $15.8
State 5.8 1.0 10.9
------ ----- -----
Total current 33.7 1.3 26.7
------ ----- -----
Deferred income taxes, net:
Federal (13.5) 5.3 (0.8)
State 0.1 0.6 (8.6)
------ ----- -----
Total deferred (13.4) 5.9 (9.4)
------ ----- -----
Investment tax credits, net (13.5) (0.6) (2.1)
-------------------------------------------------------------------------------
Total income tax expense $ 6.8 $ 6.6 $15.2
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Deferred income taxes are comprised of the tax effects of temporary differences as follows:
-------------------------------------------------------------------------------
For the Years Ended
December 31, 2002 2001 2000
-------------------------------------------------------------------------------
(Millions of Dollars)
Depreciation, leased nuclear
fuel, settlement credits and
disposal costs $ 1.5 $ (0.6) $ 0.9
Regulatory deferral (6.0) (3.7) (16.4)
Sale of generation assets (2.0) (30.5) -
Pension accruals 2.6 1.0 5.9
Securitized contract
termination
costs and other (3.6) 38.4 -
Other (5.9) 1.3 0.2
-------------------------------------------------------------------------------
Deferred income taxes, net $(13.4) $ 5.9 $ (9.4)
-------------------------------------------------------------------------------
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A reconciliation between income tax expense and the expected tax expense at the statutory rate is as follows:
-------------------------------------------------------------------------------
For the Years Ended
December 31, 2002 2001 2000
-------------------------------------------------------------------------------
(Millions of Dollars)
Expected federal income tax $15.5 $ 7.5 $17.6
Tax effect of differences:
Depreciation 0.5 - (1.2)
Amortization of
regulatory assets - 1.2 1.3
Investment tax credit
amortization (13.5) (0.6) (2.1)
State income taxes,
net of federal benefit 3.8 1.1 1.5
Other, net 0.5 (2.6) (1.9)
-------------------------------------------------------------------------------
Total income tax expense $ 6.8 $ 6.6 $15.2
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11. Segment Information
NU is organized between regulated utilities (electric and gas since the March 1, 2000 acquisition of Yankee) and competitive energy subsidiaries. WMECO is included in the regulated utilities segment of NU and has no other reportable segments.
--------------------------------------------------------------------------------------------------- Selected Consolidated Financial Data --------------------------------------------------------------------------------------------------- (Thousands of Dollars) 2002 2001 2000 1999 1998 --------------------------------------------------------------------------------------------------- Operating Revenues $369,487 $478,869 $ 513,678 $ 414,231 $ 393,322 Net Income/(Loss) 37,682 14,968 35,268 2,887 (9,579) Cash Dividends on Common Stock 16,009 22,000 12,002 - - Total Assets 836,661 852,662 1,047,818 1,253,604 1,287,682 Rate Reduction Bonds 142,742 152,317 - - - Long-Term Debt (a) 101,991 101,170 199,425 290,279 389,314 Preferred Stock Not Subject to Mandatory Redemption - - 20,000 20,000 20,000 Preferred Stock Subject to Mandatory Redemption (a) - - 16,500 18,000 19,500 Obligations Under Capital Leases (a) 87 110 26,921 29,972 34,093 --------------------------------------------------------------------------------------------------- |
(Thousands of Dollars) Quarter Ended ------------------------------------------------------------------------------- 2002 March 31 June 30 September 30 December 31 ------------------------------------------------------------------------------- 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 ------------------------------------------------------------------------------- 2001 ------------------------------------------------------------------------------- Operating Revenues $143,300 $106,866 $120,679 $108,024 Operating Income $ 11,876 $ 6,406 $ 14,821 $ 4,786 Net Income $ 3,319 $ 1,518 $ 3,880 $ 6,251 ------------------------------------------------------------------------------- |
(a) Includes portions due within one year.
Gross Electric
Utility Plant Average Annual
December 31, Use Per Electric
(Thousands of kWh Sales Residential Customers Employees
Dollars) (a) (Millions) Customer (kWh) (Average) December 31,
-------------------------------------------------------------------------------
2002 $ 602,013 4,102 7,921 203,760 400
2001 583,183 4,712 7,476 200,166 405
2000 1,153,514 7,278 7,371 198,372 406
1999 1,216,015 4,654 7,423 198,012 482
1998 1,256,046 4,009 6,979 196,339 533
|
(a) Amount includes construction work in progress.
EXHIBIT 13.4
2002 Annual Report
Public Service Company of New Hampshire and Subsidiaries
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.............................................. 8 Consolidated Balance Sheets....................................... 10-11 Consolidated Statements of Income................................. 12 Consolidated Statements of Comprehensive Income................... 12 Consolidated Statements of Common Stockholder's Equity............ 13 Consolidated Statements of Cash Flows............................. 14 Notes to Consolidated Financial Statements........................ 15 Selected Consolidated Financial Data.............................. 24 Consolidated Quarterly Financial Data (Unaudited)................. 24 Consolidated Statistics (Unaudited)............................... 25 Preferred Stockholder and 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 $62.9 million in 2002 compared
with $81.8 million in 2001. 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 (WMECO), 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's revenues during 2002 decreased to $1 billion from $1.2 billion during 2001. The decrease in revenues primarily relates to lower retail and wholesale revenues. Retail revenues decreased primarily due to an 11 percent rate decrease that was effective May 1, 2001. Wholesale revenues decreased due to a reduction in prices and a lower volume of bilateral transactions and sales of excess capacity and energy.
Future Outlook
PSNH is expected to have reduced earnings in 2003 compared to 2002. The
primary reasons for the reduction in 2003 earnings include a significant
reduction in rate base due to the gain on the sale of Seabrook in 2002 and a
significant increase in the projected level of pension expense in 2003 and
forward. In addition, PSNH earnings are expected to be reduced due to the
2002 amortization of investment tax credits, the elimination of certain
operating reserves and the positive settlement of certain previously disputed
sales transactions in 2002.
PSNH recorded $0.6 million in pre-tax pension expense in 2002, approximately 35 percent of which was capitalized and reflected as an increase to the cost of capital expenditures with the remainder being recognized in the consolidated statements of income as operating expenses. In 2003, as a result of continued poor performance in the equity markets, PSNH is projecting the total level of pre-tax pension expense to increase to approximately $7 million, with a similar percentage being reflected as a increase to the cost of capital expenditures. Pension expense/income is annually adjusted during the second quarter based upon updated actuarial valuations, at which time the 2003 estimate may be modified.
Liquidity
On November 1, 2002, NAEC consummated the sale of its 35.98 percent ownership
interest in Seabrook. 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, to return a portion of NAEC's
equity to NU and will be used to pay approximately $95 million in taxes. The
remaining proceeds received by NAEC were refunded to PSNH through the
Seabrook Power Contracts.
In January 2002, PSNH issued an additional $50 million in rate reduction bonds and used the proceeds to repay short-term debt that was incurred to buyout a purchased-power contract in December 2001.
In November 2002, PSNH, along with NU's other regulated utilities, renewed their $300 million credit line, under terms similar to the arrangement that expired in November 2002. A previous credit line had provided up to $350 million for the regulated companies. PSNH had no borrowings on this credit line at December 31, 2002.
Rate reduction bonds are included on the consolidated balance sheets of PSNH, even though the debt is nonrecourse to PSNH. At December 31, 2002, PSNH had a total of $510.8 million in rate reduction bonds outstanding, compared with $507.4 million outstanding at December 31, 2001. All outstanding rate reduction bonds of PSNH are scheduled to be fully amortized by May 1, 2013. Interest on the rate reduction bonds totaled $30.5 million in 2002, compared with $20.7 million in 2001. Amortization of the rate reduction bonds totaled $46.5 million in 2002, compared with $17.6 million in 2001. PSNH fully recovered the amortization and interest payments from customers in 2002 and the bonds had no impact on net income. Moreover, because the debt is nonrecourse to PSNH, the three rating agencies that rate PSNH's debt do not include the revenues, expenses, or outstanding securities related to the rate reduction bonds in establishing the credit ratings of PSNH.
PSNH funded its capital expenditures through internally generated cash flows and through proceeds returned from NAEC as a result of the sale of Seabrook. PSNH returned $37 million in equity capital to NU in 2002. PSNH's capital expenditures are expected to total $116.3 million in 2003 and remain largely funded through internally generated cash flows.
PSNH's net cash flows provided by operating activities increased to $326 million in 2002, compared with $272.6 million in 2001. Cash flows provided by operating activities increased 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 lower level of financing activities in 2002 as compared to 2001, primarily due to the issuance and retirements of long-term debt, issuance and retirements of rate reduction bonds and the buyout of independent power producer contracts in 2001. The level of common dividends totaled $45 million in 2002, as compared to $27 million in 2001.
Business Development and Capital Expenditures The expectation that PSNH will retain its generation assets, at least through 2004, will result in higher near-term capital expenditures at PSNH. PSNH's capital expenditures, excluding nuclear fuel, totaled $109.8 million in 2002, compared with $92.6 million in 2001. Capital expenditures are expected to total $116.3 million in 2003, as PSNH continues to upgrade and expand its distribution and transmission system and upgrade its generation plants. The expenditures will be funded primarily through internally generated cash flows.
On December 5, 2002, PSNH announced an agreement to acquire the franchise and electric system of Connecticut Valley Electric Company, Inc. (CVEC), a subsidiary of Central Vermont Public Service Corporation (CVPS) that serves approximately 10,000 customers in western New Hampshire. Under the agreement, PSNH will pay CVPS approximately $9 million for its assets and an additional $21 million to terminate a wholesale power contract between CVPS and CVEC. Customers of CVEC will become customers of PSNH, whose residential rates are now approximately 20 percent lower than those of CVEC. PSNH will be allowed to recover the $21 million payment with a return consistent with Part 3 stranded cost treatment under the "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. The sale agreement is supported by the New Hampshire Governor's Office, New Hampshire Public Utilities Commission (NHPUC) staff, the state Office of Consumer Advocate, the City of Claremont, and New Hampshire Legal Assistance. The Federal Energy Regulatory Commission (FERC) and the NHPUC must approve the sale, which is expected to become effective on January 1, 2004.
Regional Transmission Organization
The FERC has required all transmission owning utilities, including PSNH, to
voluntarily start forming Regional Transmission Organizations (RTO) or to
state why this process has not begun.
PSNH has been discussing with the other transmission owners in New England the potential to form an Independent Transmission Company (ITC). If formed, the ITC would be a for-profit entity and would perform certain transmission functions required by the FERC, including tariff control, system planning and system operations. The remaining functions required by the FERC would be performed by the Independent System Operator (ISO) regarding the energy market and short-term reliability. Together, the ITC, if formed, and ISO would form the FERC-desired RTO.
In January 2002, the New York and New England ISOs announced their intention to form an RTO. On November 22, 2002, the two ISOs withdrew their joint petition to FERC. The New England ISO intends to make an RTO filing with the transmission owners in New England in 2003. The agreements needed to create the RTO and to define the working relationships among the ISO and the transmission owners should be created in 2003, and will allow the RTO to begin operation shortly thereafter. The agreements are expected to include provisions for the future creation of one or more ITCs within the RTO. The creation of the RTO will require a FERC rate case, and the impact on PSNH's return on equity as a result of this rate case cannot be estimated at this time. At December 31, 2002, PSNH capitalized $0.3 million related to RTO formation activities.
Restructuring and Rate Matters
In July 2001, the NHPUC opened a docket to review the fuel and purchased-
power adjustment clause (FPPAC) costs incurred between August 2, 1999 and
April 30, 2001. Under the Restructuring Settlement, FPPAC deferrals are
recovered as a Part 3 stranded cost through the stranded cost recovery
charge. On December 31, 2002, the NHPUC issued its final order allowing
recovery of virtually all such costs.
On June 28, 2002, PSNH made its first stranded cost recovery charge reconciliation filing with the NHPUC for the period May 1, 2001, through December 31, 2001. This filing reconciles stranded cost revenues against actual stranded cost charges with any difference being credited against stranded costs or deferred for future recovery. Included in the stranded cost charges are the generation costs for the filing period. The generation costs included in this filing were subject to a prudence review by the NHPUC. In January 2003, PSNH entered into a settlement agreement with the Office of Consumer Advocate and the staff of the NHPUC that resolved all outstanding issues. In conjunction with the settlement agreement, the NHPUC staff recommended no disallowances resulting from their review of the outages at PSNH's generating plants. A final order approving the settlement agreement was issued by the NHPUC in February 2003. The NHPUC order approved PSNH's reconciliation of stranded costs as outlined within the settlement agreement and had no impact on PSNH's earnings.
On September 12, 2002, the NHPUC issued a final decision approving the auction results in the sale of Seabrook to FPL. On November 1, 2002, the sale was consummated. The proceeds received by NAEC, after NAEC repaid its outstanding debt, were refunded to PSNH through the Seabrook Power Contracts. PSNH used the proceeds received from NAEC to recover stranded costs and repay debt with the remaining proceeds to be returned to NU. As a result of the Seabrook sale, PSNH expects its wholesale electric sales to decline significantly in 2003. However, PSNH expects to generate most of the electricity it needs to serve retail customers from its own generating plants or purchased-power obligations and to purchase the remainder in the wholesale market.
On February 1, 2003, in accordance with the Restructuring Settlement, PSNH raised the transition service rate for residential and small commercial customers to $0.0460 per kWh from $0.0440 per kWh. On the same date, PSNH also raised its transition service rate for large commercial and industrial customers to $0.0467 per kWh from $0.0440 per kWh. PSNH expects these 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, those overrecoveries will be credited against PSNH's Part 3 stranded cost balance. If actual costs exceed those recoveries, PSNH will defer those costs for future recovery from customers through its Stranded Cost Recovery Charge.
PSNH's delivery rates are fixed until February 1, 2004. Under the Restructuring Settlement, PSNH must file a rate case by December 31, 2003, for the purpose of commencing a review of PSNH's delivery rates. Also, under New Hampshire electric industry restructuring statutes, PSNH cannot divest its nonnuclear generation assets until at least February 1, 2004. At this time, management does not expect PSNH to propose selling its 1,200 megawatts of generation assets.
For further information regarding commitments and contingencies related to restructuring, see Note 6A, "Commitments and Contingencies - Restructuring and Rate Matters," to the consolidated financial statements.
Nuclear Generation Asset Divestitures
Seabrook: On November 1, 2002, CL&P, NAEC, and certain other joint owners
consummated the sale of their ownership interest in Seabrook. NAEC formerly
sold all of its entitlement in Seabrook to PSNH and billed PSNH all costs
related to the entitlement under the terms of the Seabrook Power Contracts.
VYNPC: On July 31, 2002, Vermont Yankee Nuclear Power Corporation (VYNPC) consummated the sale of its nuclear generating unit. PSNH owns 4.3 percent of VYNPC.
Millstone: On March 31, 2001, PSNH, CL&P and WMECO sold their ownership interests in Millstone 3.
Under the terms of these asset divestitures, the purchasers agreed to assume responsibility for decommissioning their respective units. For further information regarding these divestitures and nuclear decommissioning, see Note 5, "Nuclear Generation Asset Divestitures," and Note 6E, "Nuclear Decommissioning and Plant Closure Costs," to the consolidated financial statements.
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 condition of PSNH. The following describes 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 upon which significant control is maintained and 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, Maine Yankee Atomic Power Company, VYNPC, and two companies that transmit electricity imported from the Hydro-Quebec system, which are classified as variable interest entities under Financial Accounting Standards Board Interpretation No. 46, "Consolidation of Variable Interest Entities," and for which PSNH was not classified as the primary beneficiary. As a result, management does not expect the adoption of Interpretation No. 46 to result in the consolidation of any currently unconsolidated entities or to have any other material impacts on PSNH's consolidated financial statements.
Revenue Recognition: Revenues are based on rates approved by the NHPUC. These regulated rates are applied to customers' accounts based on their use of energy. In general, rates can only be changed through formal proceedings with the NHPUC.
The determination of the energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is estimated. This unbilled revenue is estimated each month based on generation volumes, estimated customer usage by class, line losses, and applicable customer rates.
Regulatory Accounting and Assets: The accounting policies of PSNH historically reflect the effects of the rate-making process in accordance with Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." PSNH's transmission, distribution and generation businesses continue to be cost-of-service rate regulated, and management believes the application of SFAS No. 71 continues to be appropriate.
On May 22, 2001, the Governor of New Hampshire signed a bill modifying the
state's electric utility industry restructuring laws delaying the sale of
PSNH's fossil and hydroelectric generation assets until at least February 1,
2004. Since then there has been no regulatory action, and management
currently has no plans to divest these generation assets. The NHPUC has
allowed and is expected to continue to allow rate recovery of a return of and
on these generation assets, as well as all operating expenses.
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 businesses 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 regulatory assets. Such a write-off could have a
material impact on PSNH's consolidated financial statements.
The application of SFAS No. 71 results in the deferral of costs as regulatory assets that, in some cases, have not yet been approved for recovery by the applicable regulatory commission. Management must conclude that any costs deferred as regulatory assets are probable of future recovery in rates. However, the regulatory commission can reach different conclusions about the recovery of costs, which can have a material impact on PSNH's consolidated financial statements. Management believes it is probable that PSNH will recover its investments in long-lived assets, including regulatory assets.
Pension and Postretirement Benefit Obligations: PSNH participates in a uniform noncontributory defined benefit retirement plan (Plan) covering substantially all regular NU employees and also provides 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 resultant 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.
PSNH's pre-tax periodic pension expense/income for the Plan, excluding settlements, curtailments, and special termination benefits, totaled $0.6 million in expense and $3.9 million in income for the years ended December 31, 2002 and 2001, respectively. Pension expense or income is calculated based upon a number of actuarial assumptions, including an expected long-term rate of return on Plan assets of 9.25 percent for 2002 and 9.5 percent for 2001. PSNH expects to use a long-term rate of return assumption of 8.75 percent for 2003. 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 and the sale of the Millstone and Seabrook nuclear units. Net SFAS No. 88 expenses totaled $1.3 million for the year ended December 31, 2001. Approximately 35 percent of net pension expense/income is capitalized as additions or reductions to capital additions to utility plant.
In developing the expected long-term rate of return assumption, PSNH evaluated input from actuaries, consultants and economists as well as long- term inflation assumptions and NU's historical 20-year compounded return of 10.7 percent. NU's expected long-term rate of return on Plan assets is based on target asset allocation assumptions of 45 percent in United States equities and 14 percent in non-United States equities, both with expected long-term rates of return of 9.25 percent, 3 percent in emerging market equities with an expected long-term return of 10.25 percent, 20 percent in fixed income securities with an expected long-term rate of return of 5.5 percent, 5 percent in high yield fixed income securities with expected long- term rates of return of 7.5 percent, 8 percent in private equities with expected long-term rates of return of 14.25 percent, and 5 percent in real estate with expected long-term rates of return of 7.5 percent. The combination of these target allocations and expected returns results in the overall assumed long-term rate of return of 8.75 percent for 2003. The actual asset allocation at December 31, 2002, was close to these target asset allocations, and NU regularly reviews the actual asset allocations and periodically rebalances the investments to the targeted allocation when appropriate. NU reduced the long-term rate of return assumption by 0.5 percent and 0.25 percent, respectively, each of the last two years due to lower rate of return assumptions for most asset classes. PSNH believes that 8.75 percent is a reasonable long-term rate of return on Plan assets for 2003. 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.
PSNH bases the actuarial determination of Plan pension income/expense on a market-related valuation of assets, which reduces year-to-year volatility. This market-related valuation 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 value of assets 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 Plan assets. At December 31, 2002, PSNH's portion of the Plan had cumulative unrecognized investment losses of $50.9 million, which will increase Plan expense over the next four years by reducing the expected return on Plan assets. At December 31, 2002, PSNH's portion of the Plan also had cumulative unrecognized actuarial gains of $8.2 million, which will reduce Plan expenses over the expected future working lifetime of active Plan participants, or approximately 13 years. The combined total of unrecognized investment losses and actuarial gains at December 31, 2002 is $42.7 million. This amount impacts the actuarially determined prepaid pension amount recorded on the consolidated balance sheet but has no impact on expected Plan funding.
The discount rate that is utilized in determining future pension 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 Plan's longer duration 0.25 percent was added to this rating. The discount rate determined on this basis has decreased from 7.25 percent at December 31, 2001 to 6.75 percent at December 31, 2002.
Due to the effect of the unrecognized actuarial losses and based on an expected rate of return on Plan assets of 8.75 percent, a discount rate of 6.75 percent and various other assumptions, PSNH estimates that pension expense for the Plan will be approximately $7 million, approximately $11 million and approximately $15 million in 2003, 2004 and 2005, respectively. 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 plan.
The value of PSNH's portion of the Plan assets has decreased from $196.6 million at December 31, 2001 to $163.5 million at December 31, 2002. The investment performance returns and declining discount rates have reduced the funded status of PSNH's portion of the Plan, on a projected benefit obligation (PBO) basis, from an underfunded position of $31.3 million at December 31, 2001 to $97.4 million at December 31, 2002. The PBO includes expectations of future employee service and compensation increases. The significant deterioration in the funded position of the Plan will likely result in Plan contributions sooner than previously expected. PSNH has not made contributions since 1991. This deterioration could also lead to the requirement under defined benefit plan accounting to record an additional minimum liability. The total accumulated benefit obligation (ABO) of the entire Plan was $78 million less than Plan assets at December 31, 2002. The ABO is the obligation for employee service provided through December 31, 2002. If the ABO exceeds Plan assets, PSNH may need to record an additional minimum liability in 2003.
Income Taxes: Income tax expense is calculated for each period for which a statement of income is presented. 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 of expenses for tax and book accounting purposes. These differences result in deferred tax assets and liabilities, which are included in the consolidated balance sheets. PSNH must also assess the likelihood that the 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. 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. This asset amounted to $96.5 million and $87.9 million at December 31, 2002 and 2001, respectively.
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.
Environmental Matters: At December 31, 2002, PSNH has recorded a reserve for various environmental liabilities. PSNH's environmental liabilities are based on the best estimate of the amounts to be incurred for the investigation, remediation and monitoring of the remediation sites. It is possible that future cost estimates will either increase or decrease as additional information becomes known. Changes in future cost estimates will have a smaller impact on PSNH, because they have a regulatory mechanism in place to recover environmental remediation costs.
Special Purpose Entities: PSNH has two special purpose entities, both of which are currently consolidated in the financial statements. During 2001 and 2002, to facilitate the issuance of rate reduction bonds and certificates intended to finance certain stranded costs, PSNH established PSNH Funding LLC and PSNH Funding LLC 2 (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 become involved in such bankruptcy proceedings.
For further information regarding these types of activities, see Note 1, "Summary of Significant Accounting Policies," Note 4, "Pension Benefits and Postretirement Benefits Other Than Pensions," Note 6B, "Commitments and Contingencies - Environmental Matters," and Note 11, "Income Tax Expense," to the consolidated financial statements.
Other Matters
Other 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 PSNH's contractual obligations and commercial commitments at December 31, 2002, is summarized through 2007 as follows:
----------------------------------------------------------------------- (Millions of Dollars) 2003 2004 2005 2006 2007 ----------------------------------------------------------------------- Capital leases $ 0.5 $ 0.4 $ 0.4 $ 0.3 $ 0.2 Operating leases 4.6 4.1 3.4 3.1 1.7 Long-term contractual arrangements 154.6 157.6 158.4 154.3 77.2 ----------------------------------------------------------------------- Totals $159.7 $162.1 $162.2 $157.7 $79.1 ----------------------------------------------------------------------- |
Rate reduction bond amounts are not included in this table. For further information regarding NU's contractual obligations and commercial commitments, see Note 8, "Leases," and Note 6D, "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, 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.
Results of Operations
The components of significant income statement variances for the past two years are provided in the table below.
---------------------------------------------------------------------------------------
2002 over/(under)2001 2001 over/(under) 2000
Income Statement Variances --------------------- ----------------------
(Millions of Dollars) Amount Percent Amount Percent
---------------------------------------------------------------------------------------
Operating Revenues $(125) (11)% $(120) (9)%
Operating Expenses:
Fuel, purchased and net
interchange power (326) (46) (140) (16)
Other operation 3 2 1 1
Maintenance 8 14 9 19
Depreciation 1 3 (4) (9)
Amortization of regulatory assets, net 174 (a) 20 43
Taxes other than income taxes (4) (11) (4) (9)
---------------------------------------------------------------------------------------
Total operating expenses (144) (14) (118) (10)
---------------------------------------------------------------------------------------
Operating Income 19 14 (2) (1)
Interest expense, net (2) (4) 13 36
Other income/(loss), net (38) (a) 22 (a)
---------------------------------------------------------------------------------------
Income before income tax expense (17) (14) 7 7
Income tax expense 2 4 (7) (15)
Income before extraordinary loss (19) (23) 14 21
Extraordinary loss - - 214 (a)
---------------------------------------------------------------------------------------
Net income/(loss) $ (19) (23)% $ 228 (a)%
=======================================================================================
|
(a) Percent greater than 100.
Operating Revenues
Operating revenue decreased $125 million or 11 percent in 2002, primarily due
to lower retail and wholesale revenues. Retail revenues decreased $24
million, primarily due to the May 2001 rate decrease. Retail kilowatt-hour
sales were essentially flat with a 0.1 percent decrease. Wholesale revenues
decreased $100 million due to a reduction in prices and a lower volume of
bilateral transactions and sales of excess capacity and energy.
Operating revenue decreased $120 million or 9 percent in 2001, primarily due to lower retail and wholesale revenues. Retail revenues decreased $75 million, primarily due to 5 and 11 percent rate decreases that were effective October 1, 2000 and May 1, 2001, respectively ($89 million) as part of PSNH restructuring, which was partially offset by higher retail sales ($14 million). Retail kilowatt-hour sales increased 1.2 percent. Wholesale revenues decreased $43 million due to lower capacity and energy sales.
Fuel, Purchased and Net Interchange Power Fuel, purchased and net interchange power expense decreased $326 million in 2002, primarily due to the gain on the sale of utility plant resulting from the sale of Seabrook Station recorded on NAEC's books which was transferred to PSNH through the Seabrook Power Contracts ($171 million), lower purchased power from NAEC ($67 million), and lower expenses resulting from the decrease in wholesale energy sales.
Fuel, purchased and net interchange power expense decreased in 2001, primarily due to lower purchased power expenses and lower expenses from NAEC as a result of the buydown of the Seabrook Power Contracts.
Other Operation and Maintenance
Other operation and maintenance (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).
Other O&M expenses increased $10 million in 2001, primarily due to higher fossil/hydro production expense ($12 million) and higher transmission and distribution expense ($2 million), partially offset by lower nuclear expense ($2 million) and administrative and general expense ($1 million).
Depreciation
Depreciation increased $1 million in 2002, primarily due to the construction
of the new corporate headquarters.
Depreciation expense decreased in 2001, primarily due to the sale of Millstone unit three at the end of the first quarter 2001.
Amortization of Regulatory Assets, Net
Amortization of regulatory assets, net increased $174 million primarily due
to recovery of stranded costs associated with the sale of the Seabrook
Station.
Amortization of regulatory assets, net increased in 2001, primarily due to higher amortization related to restructuring.
Taxes Other Than Income Taxes
Taxes other than income taxes decreased $4 million in 2002, primarily due to
the discontinuance of New Hampshire franchise taxes in 2001.
Taxes other than income taxes decreased in 2001, primarily due to lower New Hampshire franchise taxes in 2001.
Interest Expense, Net
Interest expense, net decreased in 2002 primarily due to the December 2001
refinancing of long-term debt at lower rates.
Interest expense, net increased in 2001 primarily due to interest associated with the issuance of rate reduction bonds in 2001, partially offset by lower interest on long-term debt resulting from the retirement and refinancing of long-term debt.
Other Income/(Loss), Net
Other Income/(loss), net decreased 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).
Other Income/(loss), net increased in 2001 as a result of PSNH's sale of its ownership in Millstone 3.
Income Tax Expense
Income tax expense increased in 2002 primarily as a result of reduced
investment tax credit amortization, partially offset by the tax consequences
of lower acquisition premium amortization. Income tax expense decreased in
2001, primarily due to the acceleration of investment tax credits associated
with Seabrook due to the expected sale.
Extraordinary Loss, Net of Tax Benefit
Extraordinary loss in 2000 is due to an after-tax write-off by PSNH of
approximately $225 million of stranded costs under the Restructuring
Settlement with the state of New Hampshire, combined with other positive
effects relating to the discontinuation of SFAS No. 71 ($11 million).
To the Board of Directors of
Public Service Company of New Hampshire:
We have audited the accompanying consolidated balance sheet 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, 2002, and the related consolidated statements of income, comprehensive income, common stockholder's equity, and cash flows for the year then ended. The consolidated financial statements of the Company as of December 31, 2001 and 2000, and for the years 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. 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 audit.
We conducted our audit 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 audit provides a reasonable basis for our opinion.
In our opinion, the 2002 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, 2002, and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America.
/s/ DELOITTE & TOUCHE LLP
---------------------
DELOITTE & TOUCHE LLP
Hartford, Connecticut
January 28, 2003
|
To the Board of Directors
of Public Service Company of New Hampshire:
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) 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 Public Service Company of New Hampshire and subsidiaries 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.
PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
----------------------------------------------------------------------------------------------
At December 31, 2002 2001
----------------------------------------------------------------------------------------------
(Thousands of Dollars)
ASSETS
------
Current Assets:
Cash....................................................... $ 5,319 $ 1,479
Receivables, less provision for uncollectible
accounts of $1,990 in 2002 and $1,737 in 2001............ 68,204 70,540
Accounts receivable from affiliated companies.............. 9,667 13,055
Unbilled revenues.......................................... 32,004 29,268
Notes receivable from affiliated companies................. 23,000 -
Fuel, materials and supplies, at average cost.............. 49,182 42,047
Prepayments and other...................................... 10,032 10,211
----------- -----------
197,408 166,600
----------- -----------
Property, Plant and Equipment:
Electric utility........................................... 1,431,710 1,447,955
Other...................................................... 6,195 6,221
----------- -----------
1,437,905 1,454,176
Less: Accumulated depreciation.......................... 715,736 689,397
----------- -----------
722,169 764,779
Construction work in progress.............................. 50,547 44,961
----------- -----------
772,716 809,740
----------- -----------
Deferred Debits and Other Assets:
Regulatory assets.......................................... 859,871 1,046,760
Other ..................................................... 92,280 71,414
----------- -----------
952,151 1,118,174
----------- -----------
Total Assets................................................ $ 1,922,275 $ 2,094,514
=========== ===========
|
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, 2002 2001
---------------------------------------------------------------------------------------------
(Thousands of Dollars)
LIABILITIES AND CAPITALIZATION
------------------------------
Current Liabilities:
Notes payable to banks.................................... $ - $ 60,500
Notes payable to affiliated companies..................... - 23,000
Obligations under Seabrook Power Contracts
and other capital leases - current portion.............. 206 24,164
Accounts payable.......................................... 54,588 32,285
Accounts payable to affiliated companies.................. 4,008 18,727
Accrued taxes............................................. 65,317 2,281
Accrued interest.......................................... 11,333 9,428
Overcollections on rate reduction bonds................... 25,555 12,479
Other..................................................... 12,468 12,685
---------- -----------
173,475 195,549
---------- -----------
Rate Reduction Bonds........................................ 510,841 507,381
---------- -----------
Obligations under Seabrook Power Contracts
and Other Capital Leases.................................. 986 86,111
---------- -----------
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes......................... 359,910 423,050
Accumulated deferred investment tax credits............... 2,680 12,015
Deferred contractual obligations.......................... 56,165 37,712
Accrued pension........................................... 37,933 37,326
Other..................................................... 51,170 46,260
---------- -----------
507,858 556,363
---------- -----------
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 2002 and 388 shares in 2001......................... - -
Capital surplus, paid in................................ 126,937 165,000
Retained earnings....................................... 194,998 176,419
Accumulated other comprehensive (loss)/income........... (105) 406
---------- -----------
Common Stockholder's Equity............................... 321,830 341,825
---------- -----------
Total Capitalization........................................ 729,115 749,110
---------- -----------
Commitments and Contingencies (Note 6)
Total Liabilities and Capitalization....................... $ 1,922,275 $ 2,094,514
=========== ===========
|
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, 2002 2001 2000
------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Operating Revenues...................................... $ 1,046,738 $ 1,171,686 $ 1,291,332
----------- ----------- -----------
Operating Expenses:
Operation -
Fuel, purchased and net interchange power.......... 387,987 713,668 853,563
Other.............................................. 126,506 123,533 122,268
Maintenance........................................... 64,146 56,276 47,429
Depreciation.......................................... 40,941 39,741 43,873
Amortization of regulatory assets, net................ 238,960 65,445 45,874
Taxes other than income taxes......................... 34,226 38,375 42,321
----------- ----------- -----------
Total operating expenses............................ 892,766 1,037,038 1,155,328
----------- ----------- -----------
Operating Income........................................ 153,972 134,648 136,004
Interest Expense:
Interest on long-term debt............................ 16,752 29,308 37,086
Interest on rate reduction bonds...................... 30,499 20,721 -
Other interest........................................ 1,874 915 471
----------- ----------- -----------
Interest expense, net............................... 49,125 50,944 37,557
----------- ----------- -----------
Other (Loss)/Income, Net................................ (1,671) 36,643 14,360
----------- ----------- -----------
Income Before Income Tax Expense........................ 103,176 120,347 112,807
Income Tax Expense...................................... 40,279 38,571 45,256
----------- ----------- -----------
Income Before Extraordinary Loss........................ 62,897 81,776 67,551
Extraordinary loss, net of tax benefit
of $155,783........................................... - - (214,217)
----------- ----------- -----------
Net Income/(Loss)....................................... $ 62,897 $ 81,776 $ (146,666)
=========== =========== ===========
STATEMENTS OF COMPREHENSIVE INCOME
Net Income/(Loss)....................................... $ 62,897 $ 81,776 $ (146,666)
----------- ----------- -----------
Other comprehensive (loss)/income, net of tax:
Unrealized (losses)/gains on securities............... (620) (801) 133
Minimum pension liability adjustments................. 109 - -
----------- ----------- -----------
Comprehensive Income/(Loss)............................. $ 62,386 $ 80,975 $ (146,533)
=========== =========== ===========
|
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
Capital Other
Common Surplus, Retained Comprehensive Total
Stock Paid In Earnings Income/(Loss) (a)
-------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Balance at January 1, 2000........................ $ 1 $424,654 $319,938 $1,074 $745,667
Net loss for 2000............................. (146,666) (146,666)
Cash dividends on preferred stock............. (3,962) (3,962)
Cash dividends on common stock................ (50,000) (50,000)
Capital stock expenses, net................... 255 255
Allocation of benefits - ESOP (b)............. 3,867 3,867
Other comprehensive income.................... 133 133
------- -------- -------- ------ --------
Balance at December 31, 2000...................... 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.................... (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...................... - 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.................... (37,000) (37,000)
Allocation of benefits - ESOP................. (1,063) 682 (381)
Other comprehensive loss...................... (511) (511)
------- -------- -------- ------ --------
Balance at December 31, 2002...................... $ - $126,937 $194,998 $ (105) $321,830
======= ======== ======== ====== ========
|
(a) The company has no dividend restrictions. However, the company has two tests it must meet before it can pay out any dividends. The most restrictive of which limits the company to paying out no greater than $195.0 million of equity at December 31, 2002.
(b) In June 1999, PSNH paid NU parent $10.6 million for NU shares issued from 1992 through 1998 on behalf of its employees in accordance with NU's 401(k) plan. This transaction resulted in a reduction of the NU parent loss and a tax benefit to PSNH. The amount in 2000 represents the remaining previously allocated 1993 through 1999 NU parent losses.
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, 2002 2001 2000
--------------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Operating activities:
Income before extraordinary loss............................... $ 62,897 $ 81,776 $ 67,551
Adjustments to reconcile to net cash flows
provided by operating activities:
Depreciation................................................. 40,941 39,741 43,873
Deferred income taxes and investment tax credits, net........ (79,866) 195,422 (521)
Net amortization/(deferral) of recoverable energy costs...... 9,859 (21,234) (35,860)
Amortization of regulatory assets, net....................... 238,960 65,445 45,874
Net other (uses)/sources of cash............................. (27,703) (62,298) 140,308
Changes in working capital:
Receivables and unbilled revenues, net....................... 2,989 3,212 20,597
Fuel, materials and supplies................................. (7,135) (13,287) 9,316
Accounts payable............................................. 7,583 (48,888) 23,110
Accrued taxes................................................ 63,036 1,624 (33,048)
Other working capital (excludes cash)........................ 14,432 31,095 6,646
--------- --------- ---------
Net cash flows provided by operating activities.................. 325,993 272,608 287,846
--------- --------- ---------
Investing Activities:
Investments in plant:
Electric utility plant....................................... (109,770) (92,626) (69,500)
Nuclear fuel................................................. - (37) (1,153)
--------- --------- ---------
Cash flows used for investments in plant....................... (109,770) (92,663) (70,653)
NU system Money Pool (lending)/borrowing....................... (46,000) 23,000 -
Investments in nuclear decommissioning trusts.................. - (137) (686)
Net proceeds from sale of utility plant........................ - 24,888 -
Buyout of IPP contracts........................................ (5,152) (48,164) -
Other investment activities, net............................... (8,269) (30,906) 2,268
---------- --------- ---------
Net cash flows used in investing activities...................... (169,191) (123,982) (69,071)
---------- --------- ---------
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............................. (46,540) (17,619) -
Net (decrease)/increase in short-term debt..................... (60,500) 60,500 -
Reacquisitions and retirements of long-term debt............... - (287,485) (109,200)
Reacquisitions and retirements of preferred stock.............. - (24,268) (25,732)
Buydown of capital lease obligation............................ - (497,508) -
Cash dividends on preferred stock.............................. - (1,286) (3,962)
Cash dividends on common stock................................. (45,000) (27,000) (50,000)
Other financing activities, net................................ (13,922) (21,448) (96,922)
--------- --------- ---------
Net cash flows used in financing activities...................... (152,962) (263,629) (285,816)
--------- --------- ---------
Net increase/(decrease) in cash.................................. 3,840 (115,003) (67,041)
Cash - beginning of year......................................... 1,479 116,482 183,523
--------- --------- ---------
Cash - end of year............................................... $ 5,319 $ 1,479 $ 116,482
========= ========= =========
Supplemental Cash Flow Information:
Cash paid during the year for:
Interest, net of amounts capitalized........................... $ 47,506 $ 47,369 $ 38,819
========= ========= =========
Income taxes................................................... $ 56,458 $ 168,021 $ 22,575
========= ========= =========
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The accompanying notes are an integral part of these consolidated financial statements.
Notes to Consolidated Financial Statements
1. Summary of Significant Accounting Policies
A. About Public Service Company of New Hampshire Public Service Company of New Hampshire (PSNH or the company) along with The Connecticut Light and Power Company (CL&P), and Western Massachusetts Electric Company (WMECO), North Atlantic Energy Corporation (NAEC), Holyoke Water Power Company (HWP) and Yankee Energy System, Inc. (Yankee) are the operating companies comprising the Northeast Utilities system and are wholly owned by Northeast Utilities (NU). PSNH furnishes franchised retail electric service in New Hampshire and CL&P and WMECO furnish franchised retail electric service in Connecticut and western Massachusetts. NAEC previously sold all of its entitlement to the capacity and output of the Seabrook Station 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. NU's other subsidiaries include HWP, a company engaged in the production of electric power, Yankee, the parent company of Yankee Gas Services Company (Yankee Gas), Connecticut's largest natural gas distribution system, and several other competitive subsidiaries including Select Energy, Inc., Northeast Generation Company, Northeast Generation Services Company, and Select Energy Services, Inc.
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).
Several wholly owned subsidiaries of NU provide support services for various NU's companies, and, in some cases, for other New England utilities. Northeast Utilities Service Company (NUSCO) provides centralized accounting, administrative, engineering, financial, information resources, legal, operational, planning, purchasing, and other services to NU's companies. Until the sale of Seabrook on November 1, 2002, North Atlantic Energy Service Corporation had operational responsibility for Seabrook. Three other subsidiaries construct, acquire or lease some of the property and facilities used by NU's companies.
B. Presentation The consolidated financial statements of PSNH include the accounts of all 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 contingent liabilities 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.
C. New Accounting Standards Asset Retirement Obligations: In June 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (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 is effective on January 1, 2003, for PSNH. Management has completed its review process for potential asset retirement obligations (AROs) and has not identified any material AROs which have been incurred. However, management has identified certain removal obligations which arise in the ordinary course of business that either have a low probability of occurring or are not material in nature. 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.
A portion of PSNH's rates are intended to recover the cost of removal of certain utility assets. The amounts recovered do not represent AROs. At December 31, 2002, PSNH maintained approximately $66.6 million in cost of removal regulatory liabilities, which are included in the accumulated provision for depreciation.
Guarantees: In November 2002, the FASB issued Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others." Interpretation No. 45 requires that disclosures be made by a guarantor in its interim and annual financial statements about its obligations under certain guarantees that it has issued and clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. Interpretation No. 45 does not apply to certain guarantee contracts, such as residual value guarantees provided by lessees in capital leases, guarantees that are accounted for as derivatives, guarantees that represent contingent consideration in a business combination, guarantees issued between either parents and their subsidiaries or corporations under common control, a parent's guarantee of a subsidiary's debt to a third party, and a subsidiary's guarantee of the debt owed to a third party by either its parent or another subsidiary of that parent. The initial recognition and initial measurement provisions of Interpretation No. 45 are applicable to PSNH on a prospective basis to guarantees issued or modified after January 1, 2003. Currently, management does not expect the adoption of the initial recognition and initial measurement provisions of Interpretation No. 45 to have a material impact on PSNH's consolidated financial statements.
Consolidation of Variable Interest Entities: In January 2003, the FASB issued Interpretation No. 46, "Consolidation of Variable Interest Entities." Interpretation No. 46 addresses the consolidation and disclosure requirements for companies that hold an equity interest in a variable interest entity (VIE), regardless of the date on which the VIE was created. Interpretation No. 46 requires consolidation of a VIE's assets, liabilities and noncontrolling interests at fair value when a company is the primary beneficiary, which is defined as a company that absorbs a majority of the expected losses, risks and revenues from the VIE as a result of holding a contractual or other financial interest in the VIE. Consolidation is not required under Interpretation No. 46 for those companies that hold a significant equity interest in a VIE but are not the primary beneficiary. Interpretation No. 46 is effective for PSNH beginning in the third quarter of 2003. At December 31, 2002, PSNH held equity interests in various VIEs, for which PSNH was not the primary beneficiary, as PSNH does not absorb a majority of the expected losses, risks and revenues from the VIEs or provide a substantial portion of financial support. As a result, management does not expect the adoption of Interpretation No. 46 to have a material impact on PSNH's consolidated financial statements. For further information regarding PSNH's investments in its VIEs, see Note 1D, "Equity Investments and Jointly Owned Electric Utility Plant" to the consolidated financial statements.
D. Equity Investments and Jointly Owned Electric Utility Plant Regional Nuclear Generating Companies: PSNH owns common stock in four regional nuclear companies (Yankee Companies). PSNH's ownership interests in the Yankee Companies at December 31, 2002 and 2001, which are accounted for on the equity method are 5 percent of the Connecticut Yankee Atomic Power Company (CYAPC), 7 percent of the Yankee Atomic Electric Company (YAEC), 5 percent of Maine Yankee Atomic Power Company (MYAPC), and 4.3 percent of Vermont Yankee Nuclear Power Corporation (VYNPC). PSNH's total equity investment in the Yankee Companies and its exposure to loss as a result of these investments at December 31, 2002 and 2001, is $8 million and $8.5 million, respectively. These investments are VIEs under FASB Interpretation No. 46. Excluding VYNPC, which sold its nuclear generating plant, each Yankee Company owns a single decommissioned nuclear generating plant. On July 31, 2002, VYNPC consummated the sale of its nuclear generating plant to a subsidiary of Entergy Corporation for approximately $180 million.
Wyman Unit 4: PSNH has a 3.14 percent ownership interest in Wyman Unit 4, a 632 megawatt oil-fired generating unit. At December 31, 2002 and 2001, plant- in-service included $6.2 million and $6.1 million, respectively, net of the accumulated provision for depreciation of $4.7 million and $4.5 million, respectively.
E. Depreciation The provision for depreciation is calculated using the straight-line method based on the estimated remaining useful lives of depreciable utility 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 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. The depreciation rates for the several classes of electric utility plant-in- service are equivalent to a composite rate of 3 percent in 2002 and 2001 and 3.2 percent in 2000.
F. Revenues Revenues are based on rates approved by the state regulatory commissions. These regulated rates are applied to customer's accounts based on their use of energy. In general, rates can only be changed through formal proceedings with the NHPUC.
The determination of the energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is estimated. This unbilled revenue is estimated each month based on generation volumes, estimated customer usage by class, line losses, and applicable customer rates.
G. Regulatory Accounting and Assets 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."
PSNH's transmission and distribution businesses 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 believes it is probable that PSNH will recover its investments in long-lived assets, including regulatory assets. In addition, all material regulatory assets are earning a return, except for securitized regulatory assets. The components of PSNH's regulatory assets are as follows:
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At December 31,
---------------------------------------------------------------------
(Millions of Dollars) 2002 2001
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Recoverable nuclear costs $ 36.8 $ 40.5
Securitized regulatory assets 505.4 498.2
Income taxes, net 96.5 87.9
Unrecovered contractual obligations 58.7 38.8
Recoverable energy costs, net 241.7 251.6
Other (79.2) 129.8
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Total $859.9 $1,046.8
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At December 31, 2002, other regulatory assets included a regulatory liability in the amount of $166.2 million, related primarily to the gain on the sale of Seabrook.
In 2000, PSNH discontinued the application of SFAS No. 71 for its generation business and created a regulatory asset for Seabrook over market generation. In April 2001, PSNH issued rate reduction bonds in the amount of $525 million. PSNH used the majority of this amount to buydown its power contracts with NAEC. The Seabrook over market generation was securitized at that time and is reflected in securitized regulatory assets at December 31, 2002 and 2001. On May 22, 2001, the Governor of New Hampshire signed a bill modifying the state's electric utility industry restructuring laws delaying the sale of PSNH's fossil and hydroelectric generation assets until at least February 1, 2004. Since then there has been no regulatory action, 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 of and on these generation assets, as well as all operating expenses, PSNH again meets the criteria for the application of SFAS No. 71 for the generation portion of its business. Accordingly, costs related to the 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.
In January 2002, PSNH issued an additional $50 million in rate reduction bonds and used the proceeds from this issuance to repay short-term debt that was incurred to buyout a purchased-power contract in December 2001. The majority of the payments to buyout or buydown these contracts were recorded as securitized regulatory assets.
PSNH, 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 remaining amounts are recorded as unrecovered contractual obligations and 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.
PSNH, under the Energy Policy Act of 1992 (Energy Act), was assessed for its proportionate share of the costs of decontaminating and decommissioning uranium enrichment plants owned by the United States Department of Energy (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. PSNH is currently recovering these costs through rates. No D&D Assessment deferrals were outstanding at December 31, 2002. At December 31, 2001, PSNH's total D&D Assessment deferrals were $0.2 million and have been recorded as recoverable energy costs, net.
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, 2002 and 2001, PSNH had $179.6 million and $183.3 million, respectively, of recoverable energy costs deferred under the FPPAC, including previous deferrals of purchases from independent power producers. 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 independent power producers that had previously been included in the FPPAC. These costs are treated as Part 3 stranded costs and amounted to $62.1 million and $68.1 million at December 31, 2002 and 2001, respectively.
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, "Accounting for Income Taxes."
The tax effect of temporary differences, including timing differences accrued under previously approved accounting standards, that give rise to the accumulated deferred tax obligation is as follows:
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At December 31,
--------------------------------------------------------------------------
(Millions of Dollars) 2002 2001
--------------------------------------------------------------------------
Accelerated depreciation and
other plant-related differences $ 73.3 $ 85.8
Regulatory assets:
Securitized contract termination
costs and other 163.0 177.9
Income tax gross-up 36.8 37.8
Other 86.8 121.6
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Totals $359.9 $423.1
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I. Other (Loss)/Income, Net The pre-tax components of PSNH's other (loss)/income, net items are as follows:
--------------------------------------------------------------------------
For the Years Ended December 31,
--------------------------------------------------------------------------
(Millions of Dollars) 2002 2001 2000
--------------------------------------------------------------------------
Gain related to Millstone sale $ - $25.9 $ -
Investment income 1.2 2.3 14.9
Other, net (2.9) 8.4 (0.5)
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Totals $(1.7) $36.6 $14.4
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2. Seabrook Power Contracts
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 operation and maintenance (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. With the sale of NAEC's ownership interest in Seabrook, sales of capacity and output under the Seabrook Power Contracts ended.
3. Short-Term Debt
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. PSNH is authorized by the NHPUC to incur short-term borrowings up to a maximum of $100 million.
Credit Agreement: On November 12, 2002, PSNH, CL&P, WMECO and Yankee Gas entered into a new unsecured 364-day revolving credit facility for $300 million. This facility replaced a $350 million facility for PSNH, CL&P, WMECO and Yankee Gas, which expired on November 15, 2002. PSNH may draw up to $100 million under this facility. Unless extended, the credit facility will expire on November 11, 2003. At December 31, 2002 and 2001, there were no borrowings and $60.5 million, in borrowings, respectively, under these 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, 2001 was 2.9 percent.
This credit agreement provides that PSNH must comply with certain financial and nonfinancial covenants as are customarily included in such agreements, including, but not limited to, consolidated debt ratios and interest coverage ratios. PSNH currently is and expects to remain in compliance with these covenants.
Money Pool: Certain subsidiaries of NU, including PSNH, are members of the Northeast Utilities System Money Pool (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, 2002 and 2001, PSNH had $23 million of lendings to and $23 million of borrowings from the Pool, respectively. The interest rate on lendings to and borrowings from the Pool at December 31, 2002 and 2001 was 1.2 percent and 1.5 percent, respectively.
4. Pension Benefits and Postretirement Benefits Other Than Pensions
PSNH participates in a uniform noncontributory defined benefit retirement 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, approximately 35 percent of which was recorded as utility plant, was $0.6 million in expense in 2002, $3.9 million in income in 2001 and $4.3 million in income in 2000. These amounts exclude pension settlements, curtailments and net special termination expenses of $1.3 million in 2001.
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 five 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 expense, of which $1.2 million was included in operating expenses and $0.1 million was deferred as a regulatory liability and returned to the customers.
Postretirement Benefits Other Than Pensions (PBOP): NU's subsidiaries, including PSNH, also provide certain health care benefits, primarily medical and dental, and life insurance benefits through a benefit plan to retired employees. 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 annually funds postretirement costs through external trusts with amounts that have been rate-recovered and which also are tax deductible.
In 2001, PSNH recorded PBOP special termination benefits expense of $0.2
million in connection with the VSP. This amount was recorded as a regulatory
asset and collected through regulated utility rates in 2002.
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.
The following table represents information on the plans' benefit obligation, fair value of plan assets, and the respective plans' funded status:
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At December 31,
-------------------------------------------------------------------------------------------------
Pension Benefits Postretirement Benefits
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(Millions of Dollars) 2002 2001 2002 2001
-------------------------------------------------------------------------------------------------
Change in benefit obligation
Benefit obligation at beginning of year $(227.9) $(211.1) $(65.4) $(52.9)
Service cost (5.8) (5.0) (1.1) (1.1)
Interest cost (16.8) (15.8) (4.6) (4.3)
Plan amendment (1.8) - 4.6 -
Transfers (0.5) 0.1 - -
Actuarial loss (20.6) (9.5) (4.1) (12.4)
Benefits paid - excluding lump sum payments 12.3 11.9 6.9 5.4
Benefits paid - lump sum payments 0.2 3.2 - -
Curtailments and settlements - 0.4 - (0.1)
Special termination benefits - (2.1) - -
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Benefit obligation at end of year $(260.9) $(227.9) $(63.7) $(65.4)
-------------------------------------------------------------------------------------------------
Change in plan assets
Fair value of plan assets at beginning of year $ 196.6 $ 221.8 $ 28.4 $ 32.4
Actual return on plan assets (21.1) (10.0) (2.5) (2.9)
Employer contribution - - 5.4 4.3
Transfers 0.5 (0.1) - -
Benefits paid - excluding lump sum payments (12.3) (11.9) (6.9) (5.4)
Benefits paid - lump sum payments (0.2) (3.2) - -
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Fair value of plan assets at end of year $ 163.5 $ 196.6 $ 24.4 $ 28.4
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Funded status at December 31 $ (97.4) $ (31.3) $(39.3) $(37.0)
Unrecognized transition obligation 2.3 2.7 24.8 32.2
Unrecognized prior service cost 14.5 14.1 - -
Unrecognized net loss/(gain) 42.7 (22.8) 14.4 4.6
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Accrued benefit cost $ (37.9) $ (37.3) $ (0.1) $ (0.2)
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The following actuarial assumptions were used in calculating the plans' year end funded status:
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At December 31,
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Pension Benefits Postretirement Benefits
-------------------------------------------------------------------------------
2002 2001 2002 2001
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Discount rate 6.75% 7.25% 6.75% 7.25%
Compensation/progression rate 4.00% 4.25% 4.00% 4.25%
Health care cost trend rate (a) N/A N/A 10.00% 11.00%
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(a) The annual per capita cost of covered health care benefits was assumed to decrease to 5.00 percent by 2007.
The components of net periodic benefit (income)/expense are:
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At December 31,
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Pension Benefits Postretirement Benefits
----------------------------------------------------------------------------------------------------------
(Millions of Dollars) 2002 2001 2000 2002 2001 2000
----------------------------------------------------------------------------------------------------------
Service cost $ 5.8 $ 5.0 $ 4.8 $ 1.1 $ 1.1 $ 0.9
Interest cost 16.8 15.8 15.0 4.6 4.3 3.9
Expected return on plan assets (20.3) (20.9) (19.7) (2.9) (2.9) (2.6)
Amortization of unrecognized net
transition obligation 0.3 0.3 0.3 2.8 2.9 2.9
Amortization of prior service cost 1.4 1.3 1.3 - - -
Amortization of actuarial gain (3.4) (5.4) (6.0) - - -
Other amortization, net - - - (0.3) (1.1) (0.6)
----------------------------------------------------------------------------------------------------------
Net periodic expense/(income) - before
settlements, curtailments and special
termination benefits 0.6 (3.9) (4.3) 5.3 4.3 4.5
----------------------------------------------------------------------------------------------------------
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 expense/(income) $ 0.6 $ (2.6) $(4.3) $ 5.3 $ 4.5 $ 4.5
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For calculating pension and postretirement benefit costs, the following assumptions were used:
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For the Years Ended December 31,
-----------------------------------------------------------------------------------------
Pension Benefits Postretirement Benefits
-----------------------------------------------------------------------------------------
2002 2001 2000 2002 2001 2000
-----------------------------------------------------------------------------------------
Discount rate 7.25% 7.50% 7.75% 7.25% 7.50% 7.75%
Expected long-term rate of return 9.25% 9.50% 9.50% N/A N/A N/A
Compensation/progression rate 4.25% 4.50% 4.75% 4.25% 4.50% 4.75%
Long-term rate of return -
Health assets, net of tax N/A N/A N/A 7.25% 7.50% 7.50%
Life assets N/A N/A N/A 9.25% 9.50% 9.50%
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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 $1.9 $(1.7)
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|
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.
Pension and trust assets are invested primarily in domestic and international equity securities and bonds.
The trust holding the post retirement benefit health plan assets is subject to federal income taxes.
5. Nuclear Generation Asset Divestitures
Seabrook: On November 1, 2002, NAEC consummated the sale of its 35.98 percent 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. 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, to return a portion of NAEC's equity to NU and will be used to pay approximately $95 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. Under the terms of the sale, PSNH will continue to buy 4 percent of the plant's output through March 2012 at a range of fixed prices.
Millstone: On March 31, 2001, CL&P, PSNH and WMECO sold their ownership interests in Millstone 3 to a subsidiary of Dominion Resources, Inc. (Dominion). CL&P, PSNH and WMECO sold their ownership interests in Millstone 3 to Dominion along with all of the unaffiliated joint ownership interests in Millstone 3. PSNH received approximately $25 million of cash proceeds from the sale and applied the proceeds to taxes and reductions of debt and equity. As part of the sale, Dominion assumed responsibility for decommissioning the three Millstone units.
6. Commitments and Contingencies
A. Restructuring and Rate Matters In July 2001, the NHPUC opened a docket to review the FPPAC costs incurred between August 2, 1999, and April 30, 2001. Under the Restructuring Settlement, FPPAC deferrals are recovered as a Part 3 stranded cost through the stranded cost recovery charge. On December 31, 2002, the NHPUC issued its final order allowing recovery of virtually all such costs.
On June 28, 2002, PSNH made its first stranded cost recovery charge reconciliation filing with the NHPUC for the period May 1, 2001, through December 31, 2001. This filing reconciles stranded cost revenues against actual stranded cost charges with any difference being credited against stranded costs or deferred for future recovery. Included in the stranded cost charges are the generation costs for the filing period. The generation costs included in this filing were subject to a prudence review by the NHPUC. In January 2003, PSNH entered into a settlement agreement with the Office of Consumer Advocate and the staff of the NHPUC which resolved all outstanding issues. In conjunction with the settlement agreement, the NHPUC staff recommended no disallowances resulting from their review of the outages at PSNH's generating plants. A final order approving the settlement agreement was issued by the NHPUC in February 2003. The NHPUC order approved PSNH's reconciliation of stranded costs as outlined within the settlement agreement and had no impact on PSNH's earnings.
B. Environmental Matters 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. As such, PSNH has active environmental auditing and training programs and believes it is substantially in compliance with the current laws and regulations.
However, the normal course of operations may necessarily involve activities and substances that expose PSNH to potential liabilities of which management cannot determine the outcome. Additionally, management cannot determine the outcome for liabilities that may be imposed for past acts, even though such past acts may have been lawful at the time they occurred. Management does not believe, however, that this will have a material impact on PSNH's consolidated financial statements.
Based upon currently available information for the estimated remediation costs as of December 31, 2002 and 2001, the liability recorded by PSNH for its estimated environmental remediation costs amounted to $10.8 million and $11.4 million, respectively. These amounts include $8.7 million and $9.3 million at December 31, 2002 and 2001, respectively, for remediation of former manufactured gas plants.
PSNH has a regulatory recovery mechanism for environmental costs. Accordingly, regulatory assets have been recorded for certain environmental liabilities.
C. Nuclear Insurance Contingencies In conjunction with the divestiture of Millstone in 2001 and Seabrook in 2002, NU and PSNH terminated their 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 and VYNPC, 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 their agreements, 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. PSNH's cost of purchases under contracts with VYNPC amounted to $6.9 million in 2002, $6.5 million in 2001, and $6.4 million in 2000.
Electricity Procurement Obligations: PSNH has entered into various arrangements for the purchase of electricity. The total cost of purchases under these arrangements amounted to $121.2 million in 2002, $144.4 million in 2001, and $144.9 million in 2000. 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) 2003 2004 2005 2006 2007 ------------------------------------------------------------------------------- VYNPC $ 7.7 $ 7.3 $ 6.8 $ 7.1 $ 6.8 Electricity Procurement Obligations 138.7 142.3 143.8 140.2 63.7 Hydro-Quebec 8.2 8.0 7.8 7.0 6.7 ------------------------------------------------------------------------------- Totals $154.6 $157.6 $158.4 $154.3 $77.2 ------------------------------------------------------------------------------- |
E. 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.
During 2002, NU, along with the other joint owners, were notified by the Yankee Companies that the estimated cost of decommissioning the units owned by CYAPC, YAEC and MYAPC increased in total by approximately $380 million over prior estimates due to higher anticipated costs for spent fuel storage, security and liability and property insurance. PSNH's share of this increase would total $23.6 million. Following rate cases to be filed by the Yankee Companies with the FERC, NU will seek recovery of the higher decommissioning costs from retail customers through the appropriate state regulatory agency. At December 31, 2002 and 2001, PSNH's remaining estimated obligations, for decommissioning for the units owned by CYAPC, YAEC and MYAPC, which have been shut down were $56.2 million and $37.7 million, respectively.
7. Fair Value of Financial Instruments
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, 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
-------------------------------------------------------------------------------
-------------------------------------------------------------------------------
At December 31, 2001
-------------------------------------------------------------------------------
(Millions of Dollars) Carrying Amount Fair Value
-------------------------------------------------------------------------------
Long-term debt -
Other long-term debt $407.3 $410.0
Rate reduction bonds 507.4 519.4
-------------------------------------------------------------------------------
|
Other Financial Instruments: The carrying value of financial instruments included in current assets and current liabilities approximates their fair value.
8. Leases
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 $0.4 million in 2002, $0.7 million in 2001, and $1 million in 2000. Interest included in capital lease rental payments was $0.3 million in 2002, 2001 and 2000. Operating lease rental payments charged to expense were $2.6 million in 2002, $3.9 million in 2001, and $3.5 million in 2000.
Future minimum rental payments, excluding executory costs, such as property taxes, state use taxes, insurance, and maintenance, under long-term noncancelable leases, as of December 31, 2002, are as follows:
-------------------------------------------------------------------------- (Millions of Dollars) Capital Operating Year Leases Leases -------------------------------------------------------------------------- 2003 $0.5 $ 4.6 2004 0.4 4.1 2005 0.4 3.4 2006 0.3 3.1 2007 0.2 1.7 After 2007 0.2 3.4 -------------------------------------------------------------------------- Future minimum lease payments $2.0 $20.3 Less amount representing interest 0.8 -------------------------------------------------------------------------- Present value of future minimum lease payments $1.2 -------------------------------------------------------------------------- |
9. Accumulated Other Comprehensive Income/(Loss)
The accumulated balance for each other comprehensive income/(loss) item is as follows:
--------------------------------------------------------------------------
Current
December 31, Period December 31,
(Millions of Dollars) 2001 Change 2002
--------------------------------------------------------------------------
Unrealized
gains/(losses)
on securities $0.6 $(0.6) $ -
Minimum pension
liability adjustments (0.2) 0.1 (0.1)
--------------------------------------------------------------------------
Accumulated other
comprehensive
income/(loss) $0.4 $(0.5) $(0.1)
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Current
December 31, Period December 31,
(Millions of Dollars) 2000 Change 2001
--------------------------------------------------------------------------
Unrealized
gains/(losses)
on securities $1.4 $(0.8) $ 0.6
Minimum pension
liability adjustments (0.2) - (0.2)
--------------------------------------------------------------------------
Accumulated other
comprehensive
income/(loss) $1.2 $(0.8) $ 0.4
--------------------------------------------------------------------------
|
The changes in the components of other comprehensive income/(loss) are reported net of the following income tax effects:
-------------------------------------------------------------------------- (Millions of Dollars) 2002 2001 2000 -------------------------------------------------------------------------- Unrealized gains/(losses) on securities $0.3 $0.4 $ - Minimum pension liability - - - adjustments -------------------------------------------------------------------------- Accumulated other comprehensive income/(loss) $0.3 $0.4 $ - -------------------------------------------------------------------------- |
10. Long-Term Debt
Details of long-term debt outstanding are as follows:
--------------------------------------------------------------------------
At December 31, 2002 2001
--------------------------------------------------------------------------
(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 2003 through 2007. 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 the 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 rates on the variable-rate pollution control notes was 1.6 percent in 2002 and 2001.
11. Income Tax Expense
The components of the federal and state income tax provisions are as follows:
--------------------------------------------------------------------------
For the Years
Ended December 31, 2002 2001 2000
--------------------------------------------------------------------------
(Millions of Dollars)
Current income taxes:
Federal $101.1 $(143.5) $41.8
State 19.0 (13.4) 4.0
------ ------- -----
Total current 120.1 (156.9) 45.8
------ ------- -----
Deferred income taxes, net:
Federal (65.0) 197.3 6.7
State (5.5) 13.5 0.8
------ ------- -----
Total deferred (70.5) 210.8 7.5
Investment tax credits, net (9.3) (15.3) (8.0)
--------------------------------------------------------------------------
Total income tax expense $ 40.3 $ 38.6 $45.3
--------------------------------------------------------------------------
|
Deferred income taxes are comprised of the tax effects of temporary differences as follows:
--------------------------------------------------------------------------
For the Years
Ended December 31, 2002 2001 2000
--------------------------------------------------------------------------
(Millions of Dollars)
Depreciation $ 7.7 $ 1.9 $(1.0)
Regulatory deferral (65.3) 13.3 6.9
Regulatory disallowance - 2.3 -
Contractual settlements - 6.7 -
Securitized contract
termination
costs and other (13.5) 177.9 -
Other 0.6 8.7 1.6
--------------------------------------------------------------------------
Deferred income taxes, net $(70.5) $210.8 $ 7.5
--------------------------------------------------------------------------
|
A reconciliation between income tax expense and the expected tax expense at the statutory rate is as follows:
--------------------------------------------------------------------------
For the Years
Ended December 31, 2002 2001 2000
--------------------------------------------------------------------------
(Millions of Dollars)
Expected federal income tax $36.1 $42.1 $39.4
Tax effect of differences:
Depreciation 1.9 0.7 0.3
Amortization of
regulatory assets 1.2 6.3 9.9
Investment tax credit
amortization (9.3) (15.3) (8.0)
State income taxes,
net of federal benefit 8.8 0.1 2.9
Other, net 1.6 4.7 0.8
--------------------------------------------------------------------------
Total income tax expense $40.3 $38.6 $45.3
--------------------------------------------------------------------------
|
12. Segment Information
NU is organized between regulated utilities (electric and gas since the March 1, 2000 acquisition of Yankee) and competitive energy subsidiaries. PSNH is included in the regulated utilities segment of NU and has no other reportable segments.
-------------------------------------------------------------------------------------------------------- Selected Consolidated Financial Data -------------------------------------------------------------------------------------------------------- (Thousands of Dollars) 2002 2001 2000 1999 1998 -------------------------------------------------------------------------------------------------------- Operating Revenues $1,046,738 $1,171,686 $1,291,332 $1,160,589 $1,087,247 Net Income/(Loss) 62,897 81,776 (146,666) 84,209 91,686 Cash Dividends on Common Stock 45,000 27,000 50,000 - - Total Assets 1,922,275 2,094,514 2,082,296 2,622,433 2,681,595 Rate Reduction Bonds 510,841 507,381 - - - Long-Term Debt (a) 407,285 407,285 407,285 516,485 516,485 Preferred Stock Subject to Mandatory Redemption (a) - - 24,268 50,000 75,000 Obligations Under Seabrook Power Contracts and Other Capital Leases (a) 1,192 110,275 629,230 726,153 842,223 -------------------------------------------------------------------------------------------------------- |
(Thousands of Dollars) Quarter Ended ------------------------------------------------------------------------------- 2002 March 31 June 30 September 30 December 31 ------------------------------------------------------------------------------- Operating Revenues $242,381 $248,914 $324,818 $230,625 Operating Income $ 30,750 $ 37,004 $ 40,929 $ 45,289 Net Income $ 11,729 $ 15,231 $ 19,482 $ 16,455 ------------------------------------------------------------------------------- 2001 ------------------------------------------------------------------------------- Operating Revenues $340,835 $286,799 $299,711 $ 244,341 Operating Income $ 23,222 $ 31,008 $ 45,564 $ 34,854 Net Income $ 28,362 $ 15,517 $ 21,630 $ 16,267 ------------------------------------------------------------------------------- |
(a) Includes portions due within one year.
Gross Electric
Utility Plant Average Annual
December 31, Use Per Electric
(Thousands of kWh Sales Residential Customers Employees
Dollars) (a) (Millions) Customer (kWh) (Average) December 31,
-------------------------------------------------------------------------------
2002 $1,488,452 14,123 7,208 447,614 1,243
2001 1,499,137 14,953 6,868 439,750 1,241
2000 1,535,343 17,143 6,644 433,937 1,227
1999 2,283,187 12,827 6,665 427,694 1,258
1998 2,302,254 12,576 6,347 421,602 1,265
|
(a) Amount includes construction work in progress.
Exhibit 4.2.8.1
AMENDMENT NO. 2
TO AMENDED AND RESTATED RECEIVABLES PURCHASE AND SALE
AGREEMENT
AMENDMENT AGREEMENT, dated as of July 10, 2002, among CL&P RECEIVABLES CORPORATION, a Connecticut corporation (the "Seller"), THE CONNECTICUT LIGHT AND POWER COMPANY, a Connecticut corporation, ("CL&P") as Collection Agent and Originator, CORPORATE ASSET FUNDING COMPANY, INC., a Delaware corporation ("CAFCO"), CITIBANK, N.A. ("Citibank") and CITICORP NORTH AMERICA, INC., a Delaware corporation ("CNAI"), as agent ("Agent").
Preliminary Statements. (1) The Seller, CL&P, CAFCO, Citibank and CNAI, as Agent, are parties to an Amended and Restated Receivables Purchase and Sale Agreement dated as of September 30, 1997, as amended and restated as of March 30, 2001 and as further amended as of July 11, 2001, (the "Agreement"; capitalized terms not otherwise defined herein shall have the meanings attributed to them in the Agreement), pursuant to which the Seller is prepared to sell undivided fractional ownership interests of its Receivables to the Conduit and the Banks; and
(2) The Seller, CL&P, CAFCO, Citibank and CNAI, as Agent, desire to amend the Agreement.
NOW, THEREFORE, the parties hereto hereby agree as follows:
SECTION 1. Amendments to Agreement. Subject to the condition precedent set forth in Section 2 hereof, Section 1.01 to the Agreement is amended effective as of the date set forth above by deleting the date "July 10, 2002" in line one (1) of the definition of "Commitment Termination Date" and replacing it with the date "July 9, 2003".
SECTION 2. Condition Precedent. The effectiveness of this Amendment Agreement and the obligations of the Conduit and the Banks to make any Purchase on or after July 10, 2002 is conditioned upon the receipt by the Agent of evidence satisfactory to it that (a) the DPUC and the Securities and Exchange Commission have granted such approvals as may be necessary in connection with the implementation of this Amendment Agreement, or (b) such approvals required in connection herewith as have heretofore been granted remain in full force and effect thus requiring no further approvals.
SECTION 3. Confirmation of Agreement. Except as herein expressly amended, the Agreement is ratified and confirmed in all respects and shall remain in full force and effect in accordance with its terms. Each reference in the Agreement to "this Agreement," "hereof" or words of like import shall mean the Agreement as amended by this Amendment Agreement and as hereinafter amended or restated.
SECTION 4. GOVERNING LAW. THIS AMENDMENT AGREEMENT SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAW OF THE STATE OF NEW YORK.
SECTION 5. Execution in Counterparts. This Amendment Agreement may be executed in any number of counterparts and by different parties hereto in separate counterparts, each of which when so executed shall be deemed to be an original and all of which when taken together shall constitute one and the same Amendment Agreement. Delivery of an executed counterpart of a signature page to this Amendment Agreement by facsimile shall be effective as delivery of a manually executed counterpart of this Amendment Agreement.
SECTION 6. Seller's Representations and Warranties. The Seller represents and warrants that this Amendment Agreement has been duly authorized, executed and delivered by the Seller pursuant to its corporate powers and constitutes the legal, valid and binding obligation of the Seller. The Seller also makes each of the representations and warranties contained in Section 4.01 of the Agreement (after giving effect to this Amendment Agreement) as of the date hereof.
[Remainder of page intentionally left blank]
IN WITNESS WHEREOF, the parties have caused this Amendment Agreement No. 2 to be executed by their respective officers thereunto duly authorized, as of the date first above written.
CL&P RECEIVABLES CORPORATION
By: /s/ Randy A. Shoop Name: Randy A. Shoop Title: Treasurer |
THE CONNECTICUT LIGHT AND
POWER COMPANY
By: /s/ Randy A. Shoop Name: Randy A. Shoop Title: Treasurer |
CORPORATE ASSET FUNDING COMPANY, INC.
By: Citicorp North America, Inc.,
as Attorney-in-Fact
By: /s/ Richard C. Simons
Name: Richard C. Simons
Title: Managing Director
Global Securitized Markets
388 Greenwich St. - 19th FL
(212) 816-0778
|
CITIBANK, N.A.
By: /s/ Richard C. Simons
Name: Richard C. Simons
Title: Managing Director
Global Securitized Markets
388 Greenwich St. - 19th FL
(212) 816-0778
|
CITICORP NORTH AMERICA, INC., as Agent
By: /s/ Richard C. Simons
Name: Richard C. Simons
Title: Managing Director
Global Securitized Markets
388 Greenwich St. - 19th FL
(212) 816-0778
|
Exhibit 4.2.9.1
AMENDMENT NO. 2
AMENDMENT AGREEMENT, dated as of July 11, 2001, between THE CONNECTICUT LIGHT AND POWER COMPANY, a Connecticut corporation (the "Seller"), and CL&P RECEIVABLES CORPORATION, a Connecticut corporation (the "Purchaser").
Preliminary Statements. (1) The Seller and Purchaser to a Purchase and Contribution Agreement dated as of September 30, 1997, as amended by Amendment No. 1, dated as of March 30, 2001 (the "Agreement"; capitalized terms not otherwise defined herein shall have the meanings attributed to them in the Agreement), pursuant to which the Seller is prepared to sell certain of its Receivables to the Purchaser, the Purchaser is prepared to purchase such Receivables from the Seller, and the Seller also wishes to contribute Receivables not sold to the capital of the Purchaser; and
(2) The Seller and Purchaser, desire to amend the Agreement.
NOW, THEREFORE, the parties hereto hereby agree as follows:
SECTION 1. Amendment to Agreement. Section 1.01 of the Agreement is amended by amending the definition of "Facility Termination Date" by deleting the date "July 11, 2001" where it appears in line one (1) thereof and replacing it with the date "July 8, 2004".
SECTION 2. Confirmation of Agreement. Except as herein expressly amended, the Agreement is ratified and confirmed in all respects and shall remain in full force and effect in accordance with its terms. Each reference in the Agreement to "this Agreement," "hereof" or words of like import shall mean the Agreement as amended by this Amendment Agreement and as hereinafter amended or restated.
SECTION 3. GOVERNING LAW. THIS AMENDMENT AGREEMENT SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAW OF THE STATE OF CONNECTICUT (WITHOUT GIVING EFFECT TO THE CONFLICT OF LAWS PRINCIPLES THEREOF).
SECTION 4. Execution in Counterparts. This Amendment Agreement may be executed in any number of counterparts and by different parties hereto in separate counterparts, each of which when so executed shall be deemed to be an original and all of which when taken together shall constitute one and the same Amendment Agreement. Delivery of an executed counterpart of a signature page to this Amendment Agreement by facsimile shall be effective as delivery of a manually executed counterpart of this Amendment Agreement.
SECTION 5. Seller's Representations and Warranties. The Seller represents and warrants that this Amendment Agreement has been duly authorized, executed and delivered by the Seller pursuant to its corporate powers and constitutes the legal, valid and binding obligation of the Seller. The Seller also makes each of the representations and warranties contained in Section 4.01 of the Agreement (after giving effect to this Amendment Agreement) as of the date hereof.
[Remainder of page intentionally left blank]
IN WITNESS WHEREOF, the parties have caused this Amendment Agreement to be executed by their respective officers thereunto duly authorized, as of the date first above written.
THE CONNECTICUT LIGHT AND POWER COMPANY
By: /s/ Randy A. Shoop
Name: Randy A. Shoop
Title: Assistant Treasurer - Finance
|
CL&P RECEIVABLES CORPORATION
By: /s/ Randy A. Shoop
Name: Randy A. Shoop
Title: Assistant Treasurer - Finance
|
Exhibit 10.10.10
Composite/Conformed Copy
2001 Amendatory Agreement
This 2001 Amendatory Agreement, dated as of September 21,
2001 between VERMONT YANKEE NUCLEAR POWER CORPORATION ("Vermont
Yankee"), a Vermont corporation, and [each of Cambridge Electric
Light Company, a Massachusetts corporation, Central Maine Power
Company, a Maine corporation, Central Vermont Public Service
Corporation, a Vermont corporation, The Connecticut Light and
Power Company, a Connecticut corporation, Green Mountain Power
Corporation, a Vermont corporation, New England Power Company, a
Massachusetts corporation, Public Service Company of New
Hampshire, a New Hampshire corporation, and Western Massachusetts
Electric Company, a Massachusetts corporation] (the
"Purchaser"), amending both the Power Contract, dated February 1,
1968, as heretofore amended by eight amendments dated June 1,
1972, April 15, 1983, April 24, 1985, June 1, 1985, May 6, 1988,
June 15, 1989 and December 1, 1989 between Vermont Yankee and the
Purchaser (the "Power Contract") and the Additional Power
Contract, dated as of February 1, 1984, between Vermont Yankee
and the Purchaser (the "Additional Power Contract").
For good and valuable consideration, the receipt of which is hereby acknowledged, it is agreed as follows:
1. Basic Understandings.
Vermont Yankee was organized in 1966 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 510 megawatts electric (the "Unit") at a site in Vernon, Vermont. Vermont Yankee was issued a full-term, Facility Operating License for the Unit by the Atomic Energy Commission (now the Nuclear Regulatory Commission, which, together with any successor agencies, is hereafter called the "NRC"), which license is now stated to expire on March 21, 2012 (the "End of License Term"). The Unit has been in commercial operation since December 1, 1972 and continues to operate.
The names of the Purchasers of Vermont Yankee and their respective interests ("entitlement percentages") in Vermont Yankee and the net capacity and output of the Unit are as follows:
Purchaser Entitlement Percentage
Central Vermont Public Service Corporation 35.0%
Green Mountain Power Corporation 20.0%
New England Power Company 22.5%
The Connecticut Light and Power Company 9.5%
Central Maine Power Company 4.0%
Public Service Company of New Hampshire 4.0%
Western Massachusetts Electric Company 2.5%
Cambridge Electric Light Company 2.5%
|
The Unit was conceived to supply economic power on a cost of service formula basis to the Purchasers. Pursuant to the Power Contract, Vermont Yankee has agreed to supply to the Purchaser and, pursuant to separate power contracts substantially identical to the Power Contract except for the names of the parties (collectively, as amended through the date hereof, the "Initial Power Contracts"), to the other Purchasers all of the capacity and the electric energy available from the Unit for a thirty year term extending through November 30, 2002.
Pursuant to the Additional Power Contract, Vermont Yankee has agreed to supply to the Purchaser, and pursuant to separate additional power contracts substantially identical to the Additional Power Contract except for the names of the parties (collectively, as amended through the date hereof, the "Additional Power Contracts"), to the other Purchasers all the capacity and electric energy available from the Unit during an operative term stated to commence on December 1, 2002 (when the Initial Power Contracts terminate) and extending until a date which is 30 days after the later of the date on which the last of the financial obligations of Vermont Yankee has been extinguished or the date on which Vermont 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, that the decommissioning cost obligation and the other applicable provisions of the Additional Power Contracts shall remain in effect to permit final billings of costs incurred prior to such cancellation.
Pursuant to the Initial Power Contracts and the Additional Power Contracts, the Purchasers are entitled and obligated to take their respective entitlement percentages of the capacity and net electrical output of the Unit during the service life of the Unit and are obligated to pay therefor monthly their respective entitlement percentages of Vermont Yankee's cost of service, including decommissioning costs, whether or not the Unit is operated.
On August 14, 2001, the Board of Directors of Vermont Yankee, which includes representatives of the Purchasers (including the Purchaser), after conducting a thorough review of the economics of continued operation of the Unit until End of License Term in comparison to other alternatives (including the early shut-down of the Unit) available to Vermont Yankee and evaluating the competing bids received in a formal auction of the Unit commenced in April, 2001, voted to approve a Purchase and Sale Agreement (the "PSA"), dated as of August 15, 2001, among Vermont Yankee and Entergy Nuclear Vermont Yankee, LLC ("ENVY") and Entergy Corporation, as guarantor, pursuant to which the Unit and related assets of Vermont Yankee, including a pre-funded decommissioning trust, would be sold to ENVY. The PSA also provided that Vermont Yankee would enter into a Power Purchase Agreement (the "PPA") with ENVY to purchase 100% of the actual net output of the Unit up to its present operating level of approximately 510 megawatts electric, together with the related ancillary products available from the Unit, for a period from the Effective Date (as hereinafter defined) to the End of License Term or the earlier shutdown of the Unit, all such energy and ancillary products to be resold at wholesale by Vermont Yankee to the Purchasers pursuant to the Initial Power Contracts and the Additional Power Contracts as amended hereby.
As a consequence of the PSA and the PPA, Vermont Yankee and the Purchaser propose to further amend the Power Contract and the Additional Power Contract in various respects in order (i) to release Vermont Yankee from any further obligations under said contracts with respect to the operation and decommissioning of the Unit, (ii) to clarify and confirm provisions for the recovery under said contracts of the remaining unamortized costs previously incurred by Vermont Yankee in providing capacity and energy from the Unit prior to the Effective Date, (iii) to provide for the recovery of any costs or liabilities assumed by Vermont Yankee under the PSA and PPA and of Vermont Yankee's on- going administrative expenses, and (iv) to provide for the resale at cost by Vermont Yankee to the Purchaser of the Purchaser's entitlement percentage of the aforesaid output and ancillary products of the Unit to be purchased by Vermont Yankee from ENVY pursuant to the PPA.
Vermont Yankee and the Purchaser have agreed to enter into this 2001 Amendatory Agreement. Concurrently herewith each of the other Purchasers is entering into an amendatory agreement which is identical hereto except for the necessary changes in the names of the parties.
2. Parties' Contractual Commitments.
Vermont Yankee and the Purchaser each acknowledge that the other has faithfully performed its obligations under the Power Contract. The Purchaser hereby reconfirms its obligations under the Power Contract and the Additional Power Contract to pay its entitlement percentage of Vermont Yankee's unamortized costs of the Unit as deferred payment in connection with the capacity and net electrical output of the Unit previously delivered by Vermont Yankee and agrees that the decision to sell the Unit as described in Section 1 hereof did not give rise to any cancellation right under Section 9 of the Power Contract or Section 10 of the Additional Power Contract. Vermont Yankee and the Purchaser further agree that the Purchaser shall continue to be entitled and obligated to purchase its entitlement percentage of the aforesaid output and ancillary products available from the Unit during the terms of the Power Contract and Additional Power Contract as hereinafter provided, and to pay a like percentage of Vermont Yankee's costs therefor, and that Vermont Yankee shall continue to be obligated to resell such output and ancillary products to the Purchaser during such terms. Recognizing that the PSA, by transferring ownership and operating responsibility for the Unit, changes the nature of the costs that Vermont Yankee will incur, including those to obtain such output and ancillary products from the Unit of which a portion is being resold hereunder to the Purchaser, Vermont Yankee and the Purchaser further agree that this Amendatory Agreement sets forth the necessary and appropriate provisions for the continuation of the foregoing entitlements and obligations.
Except as expressly modified by this Amendatory Agreement, the provisions of the Power Contract and the Additional Power Contract remain in full force and effect.
3. Effective Date.
Subject to receipt of FERC approval, this 2001 Amendatory Agreement shall become effective concurrently with the Closing under the PSA (the "Effective Date").
4. Power Contract Amendments.
The Power Contract is hereby amended as follows:
(a) In recognition of the sale of the Unit being effected pursuant to the PSA and the intention of the parties to release Vermont Yankee from any further obligations with respect to operation of the Unit, the text of each of Sections 3, 4, 5, 6, 8, 9 and 10 of the Power Contract is hereby deleted and, in lieu thereof in each instance the words "Intentionally Deleted and This Section Left Blank" shall be inserted; provided, however, that the pre-existing text shall remain in effect for purposes of settling any accounts between the parties for periods prior to the Effective Date.
(b) A new section 10A is hereby inserted immediately following Section 10 to read as follows:
"10A. Definitions.
Unless the context otherwise specifies or requires, capitalized terms not otherwise defined herein shall have the meanings provided in the PPA and each term defined below, when used in this contract, shall have the meaning indicated below:
"Closing" means the Closing as defined in the PSA.
"Effective Date" has the meaning provided in
Section 3 hereof.
"End of License Term" means March 21, 2012.
"End of Term Date" means the earlier of the End of License Term or the date on which the Unit is permanently removed from service.
"ENVY" means Entergy Nuclear Vermont Yankee, LLC, a Delaware limited liability company.
"Entitlement percentage" has the meaning provided in Section 1 hereof.
"Future Power" means the aggregate energy, capacity and ancillary products actually produced by, or available from, the Unit in accordance with the PPA.
"Net capacity" means for any period the actual level at which the Unit is operated, less station service use, transformer losses and generator lead losses.
"PPA" means the Power Purchase Agreement, dated as of August 15, 2001, between Vermont Yankee, as buyer, and ENVY, as seller, a complete copy of which is attached hereto as Exhibit B.
"PPA Entitlement Percentage" means the Sub- Entitlement or, if applicable, the portion of the post-Uprate Company Entitlement (as those terms are defined in the PPA) allocated to the Purchaser in accordance with the PPA.
"PPA Obligations" means the obligations of Vermont Yankee to ENVY under the PPA other than the purchase price payable pursuant to Article 5 thereof, a schedule of which is set forth on Exhibit A hereto.
"PSA" means the Purchase and Sale Agreement, dated as of August 15, 2001, among Vermont Yankee, ENVY and Entergy Corporation, as guarantor, as amended from time to time.
"PSA Obligations" means the obligations of Vermont Yankee to ENVY under the PSA, a schedule of which is set forth on Exhibit A hereto.
"PSA Transactions" means the conduct of the auction process commenced in 2001 to sell the Unit, the proceedings to obtain regulatory approval of the transactions resulting from such auction, and the services of consultants, advisors and legal counsel with respect thereto.
"Purchasers" means the sponsoring utilities named in
Section 1 hereof or their respective successors or
assigns.
(c) In recognition of the Purchaser's continuing obligation to reimburse Vermont Yankee for its entitlement percentage of certain of Vermont Yankee's costs as deferred payment for the capacity and net electrical output of the Unit previously delivered by Vermont Yankee and to reflect the change in the manner in which Vermont Yankee will incur costs to supply the Purchaser with its aliquot share of the Future Power to be purchased pursuant to the PPA by Vermont Yankee from ENVY, the provisions of Sections 7 and 7A of the Power Contract are hereby deleted and new Sections 7, 7A and 7B are inserted in lieu thereof as follows:
"7. Reimbursed Costs
With respect to each month during the balance of the term of this contract, the Purchaser will pay Vermont Yankee an amount equal to the Purchaser's entitlement percentage of each of (A) the portion of Vermont Yankee's Closing Net Unit Investment allocable to such month, if any, together with one-twelfth of the composite percentage for such month of the Closing Net Unit Investment as most recently determined in accordance with this Section 7, (B) Vermont Yankee's Total Transaction Costs Obligation, if any, for such month, (C) Vermont Yankee's total operating expenses for such month, (D) Vermont Yankee's PSA Obligations, if any, for such month, (E) Vermont Yankee's PPA Obligations, if any, for such month, (F) Vermont Yankee's Total Revolver Costs for such month, if any, and (G) to the extent not duplicative of any payment made under clause (A) above, an amount equal to one- twelfth of the equity percentage for such month of the Purchaser's entitlement percentage of the equity investment, as most recently determined in accordance with this Section 7.
"Composite percentage" shall be computed as of the Effective Date and as of the last day of each month thereafter (the "computation date") and for any month the composite percentage shall be that computed as of the most recent computation date. "Composite percentage" as of a computation date shall be the sum of (i) the equity percentage as of such date multiplied by the percentage which equity investment as of such date is of the total capital as of such date, plus (ii) the stated interest rate per annum of each principal amount of indebtedness bearing a particular rate of interest outstanding on such date for money borrowed from persons other than Purchasers multiplied by the percentage which such principal amount is of total capital as of such date.
"Equity percentage" as of any date shall be whatever percentage per annum may be authorized from time to time by FERC.
"Common stock equity investment" as of any date shall consist of equity investment as of such date less the aggregate par value of all issues of preferred stock outstanding on such date.
"Equity investment" as of any date shall consist of the sum of (i) all amounts theretofore paid to Vermont Yankee for all capital stock theretofore issued (taken at the total par value thereof plus the total of all amounts in an excess of such par value paid thereon); plus all capital contributions, loans and advances theretofore made to Vermont Yankee by the Purchasers, less the sum of any amounts distributed by Vermont Yankee to the Purchasers or stockholders in the form of stock repurchases or redemptions, return of capital or repayments of loans and advances; plus (ii) any credit balance in the capital surplus account (not included under (i)) and in earned surplus account on the books of Vermont Yankee as of such date.
"Total capital" as of any date shall be the equity investment plus the total of all indebtedness then outstanding for money borrowed from other than the Purchasers.
"Uniform System" shall mean the Uniform System of Accounts prescribed by the Federal Power Commission for Class A and Class B Public Utilities and Licensees as in effect on the date of this contract and as said System may be hereafter amended to take account of private ownership of special nuclear material.
Vermont Yankee's "operating expenses" shall include all expenses incurred by Vermont Yankee after the Effective Date (i) for administrative and general expenses which would be properly chargeable by an operating electric utility, less any applicable credits thereto, in accordance with the Uniform System and (ii) for expenses, if any, resulting from the settlement of claims of dissenting shareholders.
The "net Unit investment" shall consist, in each case with respect to the Unit, of (i) the aggregate amount properly chargeable at the time in accordance with the Uniform System of Vermont Yankee's electric plant accounts (including construction work in progress), less the sum of (x) the aggregate amount included in operating expenses from the plant completion date to the date in question on account of depreciation accruals (and amortization, if any, of property losses) reduced by the aggregate of all amounts charged during such period against the accumulated provision for depreciation plus (y) the amount of net available cash; plus (ii) the aggregate amount properly chargeable at the time in accordance with the Uniform System to accounts representing fuel assemblies and components (including nuclear materials) and other materials and supplies, less the balance, if any, at the time of the accumulated amortization thereof; plus (iii) such reasonable allowances for prepaid items and cash working capital as may from time to time be determined by Vermont Yankee; less (z) the net proceeds received from the sale of any assets properly included in said electric plant accounts. However, for purposes of this contract, the net amount included at any date after the plant completion date in net Unit investment under clause (i) of the immediately preceding sentence shall in no event be less than the excess of:
(a) the amount properly chargeable at the plant
completion date in accordance with the Uniform
System to electric plant accounts (including
construction work in progress) with respect to the
Unit,
over
(b) the sum of (x) the aggregate minimum amount
required by this Section 7 to be included in
operating expenses from the plant completion date
to the date in question on account of depreciation
accruals (and amortization, if any, or property
losses) plus (y) the amount of net available cash.
The net Unit investment shall be determined as of the plant completion date and thereafter as of the commencement of each calendar year, or, if Vermont Yankee elects, at more frequent intervals.
"Closing Net Unit Investment" means the amount of net Unit investment determined as of the Effective Date, which amount shall be amortized in equal monthly amounts during the period beginning on the Effective Date and ending on the End of License Term.
"Net available cash" means, at any date as of which the amount thereof is to be determined, the excess of (a) the aggregate amount received by Vermont Yankee after the plant completion date and prior to two years before the determination date as insurance proceeds on account of loss or damage to the Unit or as the proceeds of a sale or condemnation of a portion of the Unit, over (b) the aggregate amount expended after the plant completion date and prior to the determination date on account of rebuilding, repairs, replacements and additions to the Unit, provided that insurance proceeds received with respect to a particular loss shall be taken into account for purposes of the foregoing computation only if the amount received with respect to the loss exceeds $150,000.
"Closing Expenses" means the funds, if any, required to defray any closing adjustments payable by Vermont Yankee in accordance with the PSA.
"Sale Costs" means the funds, if any, required to defray the costs incurred in connection with the pre- 2001 efforts to sell the Unit and the PSA Transactions, including the refunding of such costs to the Purchasers to the extent previously billed to, and paid by, the Purchasers.
"Transaction Costs" means the sum of (a) the Closing Expenses plus (b) the Sales Costs.
"Total Transaction Costs Obligation" for any month shall mean the amount attributable to such month for the payment of principal and interest, if any, on the Transaction Costs, calculated on the basis of amortizing such liability in equal monthly amounts over the period from the Effective Date to the End of License Term.
"Short-term Revolver" means one or more borrowings by Vermont Yankee during the term of this contract to obtain funds to meet short-term operating cash needs.
"Total Revolver Costs" for any month means the amount attributable to such month for the payment of principal, interest and other fees, if any, due on the Short-term Revolver.
7A. Purchase of Future Power, Delivery and Payments.
(a) Purchase of Future Power: With respect to each month during the period commencing on the Effective Date and ending on the earlier of the End of Term Date or the end of the operative term of this contract, the Purchaser will be entitled and obligated to take its PPA Entitlement Percentage of the Future Power. The Purchaser's PPA Entitlement Percentage of the Future Power will be delivered to and accepted by it at the Producer's Delivery Point (as defined in the PPA). All deliveries will be made in the form of 3- phase, 60 cycle, alternating current at a nominal voltage of 345,000 volts. The Purchaser will make its own arrangements for the transmission of its share of the Future Power. In accordance with the PPA, ENVY will be responsible for maintaining metering and telemetering with respect to the Future Power.
With respect to each month during the aforesaid period, Purchaser will pay Vermont Yankee for the Future Power actually delivered to the Purchaser an amount equal to its PPA Entitlement Percentage of (a) the purchase price calculated pursuant to Article 5 of the PPA plus (b) any applicable Governmental Charges allocable to Vermont Yankee pursuant to Section 18(b) of the PPA.
(b) Contingent Option to Terminate Purchase. Pursuant to Article 4(c) of the PPA, Vermont Yankee was granted an option to negotiate for release from all or part of its obligations to purchase power under the PPA effective as of February 28, 2005 and a further option to negotiate for release of any balance of such obligations effective December 31, 2007, each such option being exercisable by written notice to the ENVY at least 180 days prior to its effective date (each such notice date being referred to herein as an "exercise date"). Those options affect the Sub- Entitlements of each of the Purchasers. Vermont Yankee hereby grants the Purchaser the right to direct Vermont Yankee to exercise such option with respect to the Purchaser's Sub-Entitlement as follows:
If the Purchaser desires to direct Vermont Yankee to negotiate the release of the Purchaser's Sub- Entitlement under the PPA pursuant to such option, the Purchaser shall give written notice to that effect to Vermont Yankee at least 90 days in advance of the relevant exercise date. Upon receipt of such notice from the Purchaser, Vermont Yankee shall confer with all other Purchasers giving similar notices to ascertain the scope of negotiating discretion granted by such Purchasers and shall thereafter give timely written notice to the ENVY indicating Vermont Yankee's desire to negotiate the release of the Sub-Entitlements of those Purchasers that have given Vermont Yankee the required notice. Vermont Yankee shall thereafter negotiate in good faith with the ENVY for release of said Sub-Entitlements from the PPA and shall maintain close coordination with the Purchaser and other affected Purchasers to assure that the terms of such release are acceptable. Any final release agreement between Vermont Yankee and the ENVY shall be subject to ratification by each of the Purchasers affected thereby. If the Purchaser fails to ratify the release agreement within the time provided by such agreement, its Sub-Entitlement shall be excluded from the release agreement.
Vermont Yankee and the Purchaser hereby further agree that: (a) after such a release agreement has been ratified by the Purchaser, the Purchaser will pay to Vermont Yankee the Purchaser's proportionate share of the payments, if any, due to the ENVY in connection with such release; and (b) from and after the effective date of any release affecting the Purchaser's Sub- Entitlement Percentage, the Purchaser shall no longer be obligated, pursuant to clause (a) above, to take and pay for any Future Power delivered after such effective date.
(c) ISO Filing. Vermont Yankee agrees to submit this contract to the market system maintained by the Independent System Operator of New England provided for in the NEPOOL Agreement.
(d) Adequate Assurance. In the event that ENVY exercises its right under Article 7(h) of the PPA to request adequate assurance with respect to Purchaser's PPA Entitlement Percentage of the Future Power, then Vermont Yankee shall be deemed to have commercially reasonably grounds for insecurity concerning Purchaser's ability to perform its obligations under this Section 7A and may provide Purchaser with written notice requesting adequate assurance ("Adequate Assurance") of due performance of Purchaser's obligations under this Section 7A for the benefit of Vermont Yankee and/or ENVY. Upon receipt of such notice by mail postage prepaid, facsimile, telecopy or hand delivery, Purchaser shall have twelve (12) Business Days to provide such Adequate Assurance to Vermont Yankee and ENVY.
7B. Billing.
Vermont Yankee will submit, by telecopy or other agreeable same day delivery mechanism, to the Purchaser, as soon as practicable after the end of each month, an invoice for the aggregate amount payable by the Purchaser pursuant to Sections 7 and 7A hereof with respect to the particular month. Such bills will be rendered in such detail as the Purchaser may reasonably request and may be rendered on an estimated basis subject to corrective adjustments in subsequent billing periods. All payments shown to be due on such invoice, except amount in dispute, shall be due and payable by wire transfer per instructions on the invoice on or before the later of the eighteenth (18th) day of each month, or the eighth (8th) day after receipt of the invoice, or if either such day is not a Business Day, then on the next Business Day.
(d) Section 14 of the Power Contract is hereby amended by adding the following at the end thereof:
"Notwithstanding the foregoing, (a) Purchaser
(or its assigns) may assign its interest
under Section 7A of this contract only (i) to
a third party that has a credit rating equal
to the higher of that of the assignor or of
investment grade as determined by a
nationally rated service, or (ii) to a single
purpose entity whose obligations hereunder
are guaranteed by a parent that has such a
credit rating, or (iii) in connection with a
merger, consolidation or sale of
substantially all its assets to another party
that has a credit rating at least equal to
that of the Purchaser (or its assigns).
The Purchaser hereby consents to
Vermont Yankee creating a security interest
in Vermont Yankee's interest in this contract
for the benefit of ENVY and/or the lenders
under the Short-term Revolver and agrees that
Purchaser's obligations hereunder shall not
be affected thereby."
(e) Section 20 of the Power Contract is hereby amended by deleting the first sentence thereof and deleting the word "other" from the second sentence thereof.
5. Additional Power Contract Amendments.
The Additional Power Contract is hereby amended as follows:
(a) In recognition of the sale of the Unit being effected pursuant to the PSA and, the intention of the parties to release Vermont Yankee from any further obligations with respect to operation of the Unit, the text of each of Sections 3, 4, 5, 6, 8, 9, 10 and 11 of the Additional Power Contract is hereby deleted and, in lieu thereof in each instance the words "Intentionally Deleted and This Section Left Blank" shall be inserted.
(b) A new section 10A is hereby inserted immediately following Section 10 to read as follows:
"10A. Definitions.
Unless the context otherwise specifies or requires, capitalized terms not otherwise defined herein shall have the meanings provided in the PPA and each term defined below, when used in this contract, shall have the meaning indicated below:
"Closing" means the Closing as defined in the
PSA.
"Effective Date" has the meaning provided in
Section 3 hereof.
"End of License Term" means March 21, 2012.
"End of Term Date" means the earlier of the End of License Term or the date on which the Unit is permanently removed from service.
"ENVY" means Entergy Nuclear Vermont Yankee, LLC, a Delaware limited liability company.
"Entitlement percentage" has the meaning provided in Section 1 hereof.
"Future Power" means the aggregate energy, capacity and ancillary actually produced by, or available from, the Unit in accordance with the PPA.
"Initial Power Contracts" means the several Power Contracts, dated as of February 1, 1968, as amended, between Vermont Yankee and each of the Purchasers.
"Net capacity" means for any period the actual level at which the Unit is operated, less station service use, transformer losses and generator lead losses.
"Operative term" has the meaning provided in Section 2 hereof.
"PPA" means the Power Purchase Agreement, dated as of August 15, 2001, between Vermont Yankee, as buyer, and ENVY, as seller, a complete copy of which is attached hereto as Exhibit B.
"PPA Entitlement Percentage" means the Sub-Entitlement or, if applicable, the portion of the post-Uprate Company Entitlement (as those terms are defined in the PPA) allocated to the Purchaser in accordance with the PPA.
"PPA Obligations" means the obligations of Vermont Yankee to ENVY under the PPA other than the purchase price payable pursuant to Article 5 thereof, a schedule of which is set forth on Exhibit A hereto.
"PSA" means the Purchase and Sale Agreement, dated as of August 15, 2001, among Vermont Yankee, ENVY and Entergy Corporation, as guarantor, as amended from time to time.
"PSA Obligations" means the obligations of Vermont Yankee to ENVY, a schedule of which is set forth on Exhibit A hereto.
"PSA Transactions" means the conduct of the auction process commenced in 2001 to sell the Unit, the proceedings to obtain regulatory approval of the transactions resulting from such auction, and the services of consultants, advisors and legal counsel with respect thereto.
"Purchasers" means the sponsoring utilities named in Section 1 hereof or their respective successors or assigns.
(c) Section 2 of the Additional Power Contract is hereby amended in full to read as follows:
"The operative term of this contract shall commence on December 1, 2002 notwithstanding the fact that the Unit has been sold to ENVY and shall terminate 30 days after the date on which the last of the respective financial obligations of Vermont Yankee and the Purchaser which constitute elements of the reimbursed costs calculated pursuant to Section 7 hereof and the purchase price for Future Power calculated pursuant to Section 7A hereof has been extinguished."
(d) In recognition of the Purchaser's continuing obligation to reimburse Vermont Yankee for its aliquot share of certain of Vermont Yankee's costs as deferred payment for the capacity and net electrical output of the Unit previously delivered by Vermont Yankee and to reflect the change in the manner in which Vermont Yankee will incur costs to supply the Purchaser with its entitlement percentage of the Future Power to be purchased pursuant to the PPA by Vermont Yankee from ENVY, the provisions of Section 7 of the Additional Power Contract are hereby deleted and new Sections 7, 7A and 7B are inserted in lieu thereof as follows:
"7. Reimbursed Costs
With respect to each month during the operative term of this contract, the Purchaser will pay Vermont Yankee an amount equal to the Purchaser's entitlement percentage of each of (A) the portion of Vermont Yankee's Closing Net Unit Investment applicable to such month, if any, together with one-twelfth of the composite percentage for such month of the Closing Net Unit Investment as most recently determined in accordance with this Section 7, (B) Vermont Yankee's Total Transaction Costs Obligation, if any, for such month, (C) Vermont Yankee's total operating expenses for such month, (D) Vermont Yankee's PSA Obligations, if any, for such month, (E) Vermont Yankee's PPA Obligations, if any, for such month, (F) Vermont Yankee's Total Revolver Costs for such month, if any, and (G) to the extent not duplicative of any payment made under clause (A) above, an amount equal to one- twelfth of the equity percentage for such month of the Purchaser's entitlement percentage of the equity investment, as most recently determined in accordance with this Section 7.
"Composite percentage" shall be computed as of the Effective Date and as of the last day of each month thereafter (the "computation date") and for any month the composite percentage shall be that computed as of the most recent computation date. "Composite percentage" as of a computation date shall be the sum of (i) the equity percentage as of such date multiplied by the percentage which equity investment as of such date is of the total capital as of such date, plus (ii) the stated interest rate per annum of each principal amount of indebtedness bearing a particular rate of interest outstanding on such date for money borrowed from persons other than Purchasers multiplied by the percentage which such principal amount is of total capital as of such date.
"Equity percentage" as of any date shall be whatever percentage per annum may be authorized from time to time by FERC.
"Common stock equity investment" as of any date shall consist of equity investment as of such date less the aggregate par value of all issues of preferred stock outstanding on such date.
"Equity investment" as of any date shall consist of the sum of (i) all amounts theretofore paid to Vermont Yankee for all capital stock theretofore issued (taken at the total par value thereof plus the total of all amounts in an excess of such par value paid thereon); plus all capital contributions, loans and advances theretofore made to Vermont Yankee by the Purchasers, less the sum of any amounts distributed by Vermont Yankee to the Purchasers or stockholders in the form of stock repurchases or redemptions, return of capital or repayments of loans and advances; plus (ii) any credit balance in the capital surplus account (not included under (i)) and in earned surplus account on the books of Vermont Yankee as of such date.
"Total capital" as of any date shall be the equity investment plus the total of all indebtedness then outstanding for money borrowed from other than the Purchasers.
"Uniform System" shall mean the Uniform System of Accounts prescribed by the Federal Power Commission for Class A and Class B Public Utilities and Licensees as in effect on the date of this contract and as said System may be hereafter amended to take account of private ownership of special nuclear material.
Vermont Yankee's "operating expenses" shall include all ordinary and necessary expenses incurred by Vermont Yankee during the term of this contract (i) for administrative and general expenses which would be properly chargeable by an operating electric utility, less any applicable credits thereto, in accordance with the Uniform System and (ii) for expenses, if any, resulting from the settlement of claims of dissenting shareholders.
The "net Unit investment" shall consist, in each case with respect to the Unit, of (i) the aggregate amount properly chargeable at the time in accordance with the Uniform System of Vermont Yankee's electric plant accounts (including construction work in progress), less the sum of (x) the aggregate amount included in operating expenses from the plant completion date to the date in question on account of depreciation accruals (and amortization, if any, of property losses) reduced by the aggregate of all amounts charged during such period against the accumulated provision for depreciation plus (y) the amount of net available cash; plus (ii) the aggregate amount properly chargeable at the time in accordance with the Uniform System to accounts representing fuel assemblies and components (including nuclear materials) and other materials and supplies, less the balance, if any, at the time of the accumulated amortization thereof; plus (iii) such reasonable allowances for prepaid items and cash working capital as may from time to time be determined by Vermont Yankee; less (z) the net proceeds received from the sale of any assets properly included in said electric plant accounts. However, for purposes of this contract, the net amount included at any date after the plant completion date in net Unit investment under clause (i) of the immediately preceding sentence shall in no event be less than the excess of:
(a) the amount properly chargeable at the plant
completion date in accordance with the Uniform
System to electric plant accounts (including
construction work in progress) with respect to the
Unit),
over
(b) the sum of (x) the aggregate minimum amount
required by this Section 7 to be included in
operating expenses from the plant completion date
to the date in question on account of depreciation
accruals (and amortization, if any, or property
losses) plus (y) the amount of net available cash.
The net Unit investment shall be determined as of the plant completion date and thereafter as of the commencement of each calendar year, or, if Vermont Yankee elects, at more frequent intervals.
"Closing Net Unit Investment" means the amount of net Unit investment determined as of the Effective Date, which amount shall be amortized in equal monthly amounts during the period commencing on the Effective Date and ending on the End of License Date.
"Net available cash" means, at any date as of which the amount thereof is to be determined, the excess of (a) the aggregate amount received by Vermont Yankee after the plant completion date and prior to two years before the determination date as insurance proceeds on account of loss or damage to the Unit or as the proceeds of a sale or condemnation of a portion of the Unit, over (b) the aggregate amount expended after the plant completion date and prior to the determination date on account of rebuilding, repairs, replacements and additions to the Unit, provided that insurance proceeds received with respect to a particular loss shall be taken into account for purposes of the foregoing computation only if the amount received with respect to the loss exceeds $150,000.
"Closing Expenses" means the funds, if any, required to defray other closing adjustments under the PSA.
"Sales Costs" means the funds, if any, to defray the costs incurred in connection with pre-2001 efforts to sell the Unit and the PSA Transactions, including the refunding of such costs to the Purchasers to the extent previously billed to, and paid by, the Purchasers.
"Transaction Costs" means the sum of (a) the Closing Expenses plus (b) the Sale Costs.
"Total Transaction Costs Obligation" for any month shall mean the amount attributable to such month for the payment of principal and interest, if any, on the Transaction Costs, calculated on the basis of amortizing such liability in equal monthly amounts over the period from the Effective Date to the End of License Term.
"Short-term Revolver" means one or more borrowings by Vermont Yankee during the term of this contract to obtain funds to meet short-term operating cash needs.
"Total Revolver Costs" for any month means the amount attributable to such month for payment of principal, interest and other fees, if any, due on the Short-term Revolver.
7A. Purchase of Future Power, Delivery and Payments.
(a) Purchase of Future Power: With respect to each month during the period commencing on December 1, 2002 and ending on the End of Term Date, the Purchaser will be entitled and obligated to take its PPA Entitlement Percentage of the Future Power. The Purchaser's PPA Entitlement Percentage of the Future Power will be delivered to and accepted by it at the Producer's Delivery Point (as defined in the PPA). All deliveries will be made in the form of 3-phase, 60 cycle, alternating current at a nominal voltage of 345,000 volts. The Purchaser will make its own arrangements for the transmission of its shares of the Future Power. In accordance with the PPA, ENVY will be responsible for maintaining metering and telemetering with respect to the Future Power.
With respect to each month during the aforesaid period, Purchaser will pay Vermont Yankee for the Future Power actually delivered to the Purchaser an amount equal to its PPA Entitlement Percentage of (a) the purchase price calculated pursuant to Article 5 of the PPA plus (b) any applicable Governmental Charges allocable to Vermont Yankee pursuant to Section 18(b) of the PPA.
(b) Contingent Option to Terminate Purchase. Pursuant to Article 4(c) of the PPA, Vermont Yankee was granted an option to negotiate for release from all or part of its obligations to purchase power under the PPA effective as of February 28, 2005 and a further option to negotiate for release of any balance of such obligations effective December 31, 2007, each such option being exercisable by written notice to the ENVY at least 180 days prior to its effective date (each such notice date being referred to herein as an "exercise date"). Those options affect the Sub- Entitlements of each of the Purchasers. Vermont Yankee hereby grants the Purchaser the right to direct Vermont Yankee to exercise such option with respect to the Purchaser's Sub-Entitlement as follows:
If the Purchaser desires to direct Vermont Yankee to negotiate the release of the Purchaser's Sub- Entitlement under the PPA pursuant to such option, the Purchaser shall give written notice to that effect to Vermont Yankee at least 90 days in advance of the relevant exercise date. Upon receipt of such notice from the Purchaser, Vermont Yankee shall confer with all other Purchasers giving similar notices to ascertain the scope of negotiating discretion granted by such Purchasers and shall thereafter give timely written notice to the ENVY indicating Vermont Yankee's desire to negotiate the release of the Sub-Entitlements of those Purchasers that have given Vermont Yankee the required notice. Vermont Yankee shall thereafter negotiate in good faith with the ENVY for release of said Sub-Entitlements from the PPA and shall maintain close coordination with the Purchaser and other affected Purchasers to assure that the terms of such release are acceptable. Any final release agreement between Vermont Yankee and the ENVY shall be subject to ratification by each of the Purchasers affected thereby. If the Purchaser fails to ratify the release agreement within the time provided by such agreement, its Sub-Entitlement shall be excluded from the release agreement.
Vermont Yankee and the Purchaser hereby further agree that: (a) after such a release agreement has been ratified by the Purchaser, the Purchaser will pay to Vermont Yankee the Purchaser's proportionate share of the payments, if any, due to the ENVY in connection with such release; and (b) from and after the effective date of any release affecting the Purchaser's Sub- Entitlement Percentage, the Purchaser shall no longer be obligated, pursuant to clause (a) above, to take and pay for any Future Power delivered after such effective date.
(c) ISO Filing. Vermont Yankee agrees to submit this contract to the market system maintained by the Independent System Operator of New England provided for in the NEPOOL Agreement.
(d) Adequate Assurance. In the event that ENVY exercises its right under Article 7(h) of the PPA to request adequate assurance with respect to Purchaser's PPA Entitlement Percentage of the Future Power, then Vermont Yankee shall be deemed to have commercially reasonably grounds for insecurity concerning Purchaser's ability to perform its obligations under this Section 7A and may provide Purchaser with written notice requesting adequate assurance ("Adequate Assurance") of due performance of Purchaser's obligations under this Section 7A for the benefit of Vermont Yankee and/or ENVY. Upon receipt of such notice by mail postage prepaid, facsimile, telecopy or hand delivery, Purchaser shall have twelve (12) Business Days to provide such Adequate Assurance to Vermont Yankee and ENVY.
7B. Billing.
Vermont Yankee will submit, by telecopy or other
agreeable same day delivery mechanism, to the
Purchaser, as soon as practicable after the
end of each month, an invoice for the aggregate amount
payable by the Purchaser pursuant to Sections 7 and 7B
hereof with respect to the particular month. Such
bills will be rendered in such detail as the Purchaser
may reasonably request and may be rendered on an
estimated basis subject to corrective adjustments in
subsequent billing periods. All payments shown to be
due on such invoice, except amounts in dispute, shall
be due and payable by wire transfer per instructions on
the invoice on or before the later of the eighteenth
(18th) day of each month, or the eighth (8th) day after
receipt of the invoice, or if either such day is not a
Business Day, then on the next Business Day.
(e) Section 15 of the Additional Power Contract is hereby amended by adding the following to the end thereof:
"Notwithstanding the foregoing, (a) Purchaser (or its
assigns) may assign its interest under Section 7A of
this contract only (i) to a third party that has a
credit rating equal to the higher of that of the
assignor or of investment grade as determined by a
nationally rated service, or (ii) to a single purpose
entity whose obligations hereunder are guaranteed by a
parent that has such a credit rating, or (iii) in
connection with a merger, consolidation or sale of
substantially all its assets, to another party that has
a credit rating at least equal to that of the Purchaser
(or its assigns).
The Purchaser hereby consents to Vermont Yankee
creating a security interest in Vermont Yankee's
interest in this contract for the benefit of ENVY
and/or the lenders under the Short-term Revolver and
agrees that Purchaser's obligations hereunder shall not
be affected by thereby."
(f) Section 17 of the Additional Power Contract is hereby amended by deleting the first sentence thereof and deleting the word "other" from the second sentence thereof.
6. Government Regulation. This Amendatory Agreement and all rights and obligations of the Parties hereunder are subject to all applicable federal, state and local laws and all duly promulgated orders and duly authorized actions of governmental authorities having proper and valid jurisdiction over the terms of this Amendatory Agreement. Purchaser will be obligated to make all payments to Vermont Yankee for purchases at wholesale of capacity, energy and ancillary products hereunder regardless of whether or not the Purchaser is permitted to pass along or recover those payments from its customers. Each of Vermont Yankee and Purchaser shall not propose, advance or support, and shall vigorously oppose and defend against, any action by any legislature, agency, commission, (including the Federal Energy Regulatory Commission), entity or court that would adversely affect the Parties' rights and benefits hereunder and each of Vermont Yankee and the Purchaser will vigorously pursue all actions and remedies to overturn or cure any such action. In addition, the rates, terms, and conditions contained in this Amendatory Agreement are not subject to change under Sections 205 or 206 of the Federal Power Act, as either section may be amended or superseded, absent the mutual written agreement of the Parties or a finding by the Federal Energy Regulatory Commission, that this Amendatory Agreement is not in the public interest.
7. Confidentiality. Except as otherwise required by law or for implementation of this Amendatory Agreement, the Parties must keep confidential the transactions undertaken pursuant hereto; provided, however, that the Purchaser may disclose such information on a confidential basis to third parties in connection with good faith negotiation for the assignment of Purchaser's interests hereunder. Nothing herein shall preclude the Purchaser from disclosing the substance of this Amendatory Agreement to third parties on a confidential basis in connection with the negotiation of the assignment of any of its interests herein. Any information provided by either Party to the other Party pursuant to this Amendatory Agreement and labeled "CONFIDENTIAL" will be used by the receiving Party solely in connection with the purposes of this Amendatory Agreement and will not be disclosed by the receiving Party to any third party, except with the providing Party's consent. This Section 7 of this Amendatory Agreement will not prevent either Party from providing any confidential information received from the other Party to any court or in accordance with a proper discovery request or in response to the reasonable request of any governmental agency with jurisdiction to regulate or investigate the disclosing Party's affairs, provided that, if feasible, the disclosing Party will give prior notice to the other Party of such disclosure and, if so requested by such other Party, will have used all reasonable efforts to oppose or resist the requested disclosure, as appropriate under the circumstances, or to otherwise make such disclosure pursuant to a protective order or other similar arrangement for confidentiality.
8. Miscellaneous.
(a) Mitigation of Damages. In the event of any default by Purchaser, Vermont Yankee shall have the right to sell the Purchaser's entitlement percentage of any energy and ancillary products and apply the proceeds thereof against the amounts owing from the Purchaser.
(b) Counterparts. This Agreement may be executed in two or more counterparts, each of which shall be deemed an original, but all of which together shall constitute one and the same instrument.
IN WITNESS WHEREOF, the parties have executed this Amendment by their respective officers hereto duly authorized, as of the date first above written.
VERMONT YANKEE NUCLEAR POWER
CORPORATION
By /s/ Bruce W. Wiggett
Bruce W. Wiggett
Senior Vice President of Finance
and Administration
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Address: Box 169, Ferry Road Brattleboro, VT 05301
CAMBRIDGE ELECTRIC LIGHT COMPANY
By /s/ Russell D. Wright
Russell D. Wright
President
|
Address: 800 Boylston Street Boston, MA 02199
CENTRAL MAINE POWER COMPANY
By /s/ Curtis I. Call
Curtis I. Call
Treasurer
|
Address: 83 Edison Drive Augusta, ME 04336
THE CONNECTICUT LIGHT AND POWER
COMPANY
By /s/ John B. Keane
John B. Keane
Vice President/Administration
|
Address: P. O. Box 270 Hartford, CT 06141-0270
GREEN MOUNTAIN POWER CORPORATION
By /s/ C. L. Dutton
C. L. Dutton
President and Chief Executive
Officer
|
Address: 163 Acorn Lane Colchester, VT 05446
CENTRAL VERMONT PUBLIC SERVICE
CORPORATION
By /s/ Kent R. Brown
Kent R. Brown
Senior Vice President,
Engineering & Operations
|
Address:: 77 Grove Street Rutland, VT 05701
NEW ENGLAND POWER COMPANY
By /s/ Terry L. Schwennesen
Terry L. Schwennesen
Vice President
|
Address:
PUBLIC SERVICE COMPANY OF
NEW HAMPSHIRE
By /s/ John B. Keane
John B. Keane
Vice President - Administration
|
Address:: P. O. Box 270 Hartford, CT 06141-0270
WESTERN MASSACHUSETTS ELECTRIC
COMPANY
By /s/ John B. Keane
John B. Keane
Vice President - Administration
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Address:: P. O. Box 270 Hartford, CT 06141-0270
Exhibit A
to
2001 Amendatory Agreement
I. PSA Obligations:
The PSA Obligations comprise those set forth in the following sections of the PSA:
Section 2.4 Excluded Liabilities
Section 6.11(b) One-time fee due to DOE under the DOE Standard Contract
Section 6.12 DOE Decontamination and Decommissioning fees
Section 9.1 Indemnification obligations
II. PPA Obligations:
The PPA Obligations comprise those set forth in the following sections of the PPA:
Section 3(g) Transmission charges for Station Use Energy.
Section 7(h) Adequate assurance
Section 9 Indemnification obligations
Exhibit B
to
2001 Amendatory Agreement
[Attach copy of PPA]
Exhibit 10.25.1.1
EXECUTION COPY
AMENDMENT NO. 3 TO
INTERIM INDEPENDENT SYSTEM OPERATOR AGREEMENT
This Amendment No. 3 to Interim Independent System Operator Agreement (this "Amendment") is made and entered into as of this 30th day of April, 2002 by and between the entities which are the participants in the New England Power Pool pursuant to the Restated New England Power Pool Agreement dated as of September 1, 1971, as amended and restated to date ("Restated NEPOOL Agreement"), acting herein by and through the NEPOOL Participants Committee, as successor to the NEPOOL Management Committee (collectively, the "NEPOOL Participants" or "NEPOOL"), on the one hand, and ISO New England Inc. (the "ISO", and together with the NEPOOL Participants, the "Parties"), on the other.
WHEREAS, the NEPOOL Participants and the ISO are parties to that certain Interim Independent System Operator Agreement dated as of July 1, 1997 (the "ISO Agreement"); and
WHEREAS, the term of the ISO Agreement expires on June 30, 2002; and
WHEREAS, the NEPOOL Participants and the ISO desire to extend the term of the ISO Agreement;
NOW, THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the NEPOOL Participants and the ISO agree as follows:
1. Amendment of Section 3. The heading of Section 3 of the ISO Agreement
is amended to read "Term; Automatic Extension; Additional Modifications" and
Section 3 is replaced in its entirety so that it reads as follows:
3. TERM; AUTOMATIC EXTENSION; ADDITIONAL MODIFICATIONS
3.1 Term. The term of this Agreement shall begin on
the Effective Date and (subject to the provisions of
Section 3.2 concerning automatic extension) shall
continue until March 31, 2003, unless this Agreement is
otherwise terminated in accordance with the provisions
of Section 13.
3.2 Automatic Extension of Term. The term of this Agreement shall be automatically extended to December 31, 2003 ("Automatic Extension"), unless sooner terminated in accordance with the provisions of Section 13, subject to satisfaction on or before November 1, 2002 of the following two (2) conditions:
(a) The ISO has made a filing with the FERC (either alone or with others) that outlines a proposed structure for a regional transmission organization ("RTO") that includes at least the NEPOOL Control Area (whether such RTO is formed through a consolidation of the New York and New England markets or otherwise). This condition will be deemed to be satisfied if such filing minimally includes the following:
(i) The results of the cost/benefit analysis that is being performed as of the date of this Amendment with respect to a potential combination of the New York and New England markets, and a detailed explanation of the rationale for such proposal;
(ii) A discussion of the proposed rights, responsibilities and authorities of the RTO, the customers, and any other organizations that are to be accommodated under the new structure (e.g., an independent transmission company);
(iii) An identification of any changes in the market design in New England from the NEPOOL Standard Market Design proposed as of March 1, 2002;
(iv) A projected work plan and timeline for the creation of the new RTO including entities proposed to accomplish each of the tasks in the work plan; and
(v) A discussion of why the ISO believes that the proposed RTO meets each of the requirements of FERC Order No. 2000.
(b) The NEPOOL Participants Committee has taken a vote after the ISO has filed its RTO proposal in accordance with Section 3.2(a) in which at least 50% of the aggregate Sector Voting Shares, as determined in accordance with the provisions of Section 6.9 of the Restated NEPOOL Agreement, are in favor of the Automatic Extension.
3.3 Additional Modifications. Should the two conditions identified in Section 3.2 above not be satisfied on or before November 1, 2002, NEPOOL and the ISO undertake to agree on additional modifications to this Agreement, which modifications shall be filed with the FERC on or before February 1, 2003.
2. Continuing Effect. Except as specifically amended hereby, all terms and provisions contained in the ISO Agreement shall remain unchanged and in full force and effect.
3. Reservation of Rights. Nothing set forth in this Amendment shall be
construed to alter, restrict, prejudice, or in any way be inconsistent with
(i) the rights of the NEPOOL Transmission Owners set forth in Section 17A
of the Restated NEPOOL Agreement or (ii) the rights, if any, of any Party
with respect to facilities which are subject to the RTO.
4. Counterparts. Two or more counterparts of this Amendment may be signed by the parties, each of which shall be an original but all of which together shall constitute one and the same instrument.
5. Governing Law. This Amendment shall be governed by and enforced in accordance with the laws of the State of Connecticut.
6. Miscellaneous. Terms used in this Amendment that are not defined herein shall have the meanings ascribed to them in the ISO Agreement or the Restated NEPOOL Agreement.
[The next page is the signature page.]
IN WITNESS WHEREOF, the NEPOOL Participants and the ISO have caused this Amendment to be executed by their duly authorized representatives as of the date first written above.
NEPOOL PARTICIPANTS ISO NEW ENGLAND INC.
By: /s/ Roberto R. Denis By: /s/ G. van Welie
Name: Roberto R. Denis Name: G. van Welie
Title: Chairman, NEPOOL Title: President & CEO
Participants Committee
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Exhibit 10.25.12
EIGHTY-SECOND AGREEMENT AMENDING
NEW ENGLAND POWER POOL AGREEMENT
(AMENDMENT TO SCHEDULE 16)
THIS EIGHTY-SECOND AGREEMENT AMENDING NEW ENGLAND POWER
POOL AGREEMENT, dated as of January 18, 2002 ("Eighty-
Second Agreement"), amends the New England Power Pool
Agreement (the "NEPOOL Agreement"), as amended.
WHEREAS, the NEPOOL Agreement as in effect on December 1, 1996 was amended and restated by the Thirty-Third Agreement Amending New England Power Pool Agreement dated as of December 1, 1996 (the "Thirty-Third Agreement") in the form of the Restated New England Power Pool Agreement ("Restated NEPOOL Agreement") attached to the Thirty-Third Agreement as Exhibit A thereto, and the Thirty-Third Agreement also provided for the NEPOOL Open Access Transmission Tariff (the "NEPOOL Tariff") which is Attachment B to the Restated NEPOOL Agreement; and
WHEREAS, the Restated NEPOOL Agreement and the NEPOOL Tariff have subsequently been amended numerous times, with such amendments most recently consolidated, respectively, in FERC Electric Third Revised Rate Schedule No. 5, submitted in Docket No. ER00-2894-000, and FERC Electric Tariff, Fourth Revised Volume No. 1, submitted in Docket Nos. EL00- 62-000, et al.; and
WHEREAS, the Participants desire to amend the NEPOOL Tariff as heretofore amended, to reflect the revisions detailed herein.
NOW, THEREFORE, upon approval of this Eighty-Second Agreement by the NEPOOL Participants Committee in accordance with the procedures set forth in the NEPOOL Agreement, the Participants agree as follows:
SECTION 1
AMENDMENTS TO NEPOOL TARIFF
1.1 The first paragraph of Exhibit 1 to Supplement 1 to Schedule 16 of the NEPOOL Tariff is amended by adding the following new sentence at the end of the existing text:
However, if a generator is recovering its black start costs under retail rates, it may recover its Black Start Revenue Requirement under this rate structure provided the generator credits the revenues collected herein against the costs collected in retail rates for Black Start service.
1.2 The definition of the term "Plant Allocation Factor" as used in the definition of the term "Black Start Related Accumulated Deferred Taxes" in Section A.1.a.d of Supplement 1 to Schedule 16 of the NEPOOL Tariff is amended to read as follows:
. . . multiplied by the ratio of total investment in Black Start Plant plus Black Start Related General Plant to total plant in service.
SECTION 2
MISCELLANEOUS
2.1 Conforming changes shall be made to the corresponding provisions of the System Restoration & Planning Service Billing Procedure and are also approved.
2.2 This Eighty-Second Agreement shall become effective on April 1, 2002 or on such other date as the Commission shall provide that the amendments reflected herein shall become effective.
2.3 Terms used in this Eighty-Second Agreement that are not defined herein shall have the meanings ascribed to them in the NEPOOL Agreement.
Exhibit 10.25.13
EIGHTY-THIRD AGREEMENT AMENDING
NEW ENGLAND POWER POOL AGREEMENT
(FINANCIAL ASSURANCE AND
BILLING POLICIES)
THIS EIGHTY-THIRD AGREEMENT AMENDING NEW ENGLAND POWER POOL AGREEMENT, dated as of March 8, 2002 ("Eighty-Third Agreement"), amends the New England Power Pool Agreement (the "NEPOOL Agreement"), as amended.
WHEREAS, the NEPOOL Agreement as in effect on December 1, 1996 was amended and restated by the Thirty-Third Agreement Amending the New England Power Pool Agreement dated as of December 1, 1996 (the "Thirty-Third Agreement") in the form of the Restated New England Power Pool Agreement ("Restated NEPOOL Agreement") attached to the Thirty-Third Agreement as Exhibit A thereto, and the Thirty-Third Agreement also provided for the NEPOOL Open Access Transmission Tariff (the "NEPOOL Tariff") which is Attachment B to the Restated NEPOOL Agreement; and
WHEREAS, the Restated NEPOOL Agreement and the NEPOOL Tariff have subsequently been amended numerous times, the most recent amendment dated as of January 18, 2002; and
WHEREAS, the Participants desire to amend the NEPOOL Agreement and the NEPOOL Tariff, as heretofore amended, to reflect the revisions detailed herein.
NOW, THEREFORE, upon approval of this Eighty-Third Agreement by the NEPOOL Participants Committee in accordance with the procedures set forth in the NEPOOL Agreement, the Participants agree as follows:
SECTION 1 AMENDMENTS TO NEPOOL AGREEMENT
1.1 Amendment to Section 21.2(c) of the NEPOOL Agreement. The second sentence of Section 21.2(c) of the NEPOOL Agreement is amended to read as follows:
If a Participant fails to meet the requirements for continuation of service, NEPOOL may take such actions as are specified in the NEPOOL Billing Policy attached to the Tariff (the "Billing Policy") and the Financial Assurance Policy for NEPOOL Members attached to the Tariff (the "Member Financial Assurance Policy").
1.2 Amendment to Section 21.2(d) of the NEPOOL Agreement. Section 21.2(d) of the NEPOOL Agreement is amended to read as follows:
In the event a Participant fails, for any reason other than a billing dispute as described in subsection (c) of this Section 21.2, to pay when due in accordance with NEPOOL System Rules (including, without limitation, the Billing Policy) all amounts invoiced to it by NEPOOL, or by the System Operator on behalf of NEPOOL (a "Payment Default"), or the Participant otherwise fails to comply with the Billing Policy or the Member Financial Assurance Policy (including, without limitation, a failure to provide adequate financial assurance), or the Participant fails to perform any other obligation under the Agreement or the Tariff, and such failure continues for at least five days in the case of a Payment Default and for at least ten days in the case of any other default, NEPOOL, or the System Operator on behalf of NEPOOL, may (but shall not be required to) notify such Participant in writing, electronically and by first class mail sent in each case to such Participant's member or alternate on the Participants Committee or billing contact, that it is in default, and NEPOOL may initiate a proceeding before the Commission to terminate such Participant's status as a Participant. Simultaneously with the giving of the notice described in the preceding sentence in the case of a Payment Default and within ten days after the giving of such notice in the case of any other default (unless the default giving rise to such notice is cured during such period), NEPOOL, or the System Operator on behalf of NEPOOL, shall notify each other member and alternate on the Participants Committee and each Participant's billing contact of the identity of the Participant receiving such notice, whether such notice relates to a Payment Default, to a failure to comply otherwise with the Billing Policy or the Member Financial Assurance Policy, or to another failure to perform obligations under the Agreement or the Tariff, and the actions NEPOOL and/or the System Operator plans to take and/or has taken in response to such default. Pending Commission action on such termination, NEPOOL may suspend service, in whole or part, to the Participant on or after 50 days after the giving of such notice and the initiation of such proceeding, in accordance with Commission policy, or such shorter time period as is specified in the Billing Policy or the Member Financial Assurance Policy, unless the Participant cures the default within such period. Nothing set forth in this Section 21.2 is intended to limit the additional provisions of the Information Policy, the Member Financial Assurance Policy or the Billing Policy relating to defaults.
SECTION 2 AMENDMENTS TO MEMBER FINANCIAL ASSURANCE POLICY
2.1 Amendment to Section II.A.1 of the Member Financial Assurance Policy. The second sentence of the first paragraph of Section II.A.1 of the Financial Assurance Policy for NEPOOL Members included as Attachment L to the NEPOOL Tariff, as amended by the Eighty-First Agreement Amending New England Power Pool Agreement (the "Member Financial Assurance Policy"), is amended to insert "and" immediately before "(iv)" and to delete "; and (v) a list of the officers and principal management of the Non-Municipal Applicant" at the end of the that sentence.
2.2 Amendment to Section II.A.1 of the Member Financial Assurance Policy. In the second sentence of the second paragraph of Section II.A.1 of the Member Financial Assurance Policy, "(v)" is changed to "(iv)".
2.3 Amendment to Section II.A.2 of the Member Financial Assurance Policy. In the first sentence of Section II.A.2 of the Member Financial Assurance Policy, the phrase "and a list of its officers and principal management" is deleted. In the second sentence of that section, ": (i) the background of the Non-Municipal Participant's officers and principal management; and (ii)" is deleted.
2.4 Amendment to Section II.B.4. of the Member Financial Assurance Policy. The first sentence of Section II.B.4. of the Member Financial Assurance Policy is amended to read as follows:
When a Non-Municipal Participant's aggregate outstanding obligations
to NEPOOL and the System Operator equal 80 percent (80%) of the sum of
(i) that Non-Municipal Participant's then-effective Credit Limit
and (ii) the available amount of the additional financial assurance
provided by that Non-Municipal Participant divided by three and one-half
(3.5) (the sum of item (i) and (ii) being referred to herein as
the "Credit Test Amount"), the System Operator shall issue notice thereof
to such Non-Municipal Participant, such notice to be given in the manner
provided in Section 21 of the Restated NEPOOL Agreement.
2.5 Amendment to Section II.B.4. of the Member Financial Assurance Policy. Clause (ii)(a) in the second paragraph of Section II.B.4. of the Member Financial Assurance Policy is amended to read as follows:
(ii) such Non-Municipal Participant shall be suspended from (a) making any purchases or sales of Market Products in the NEPOOL Market;
2.6 Amendment to Section II.B.4. of the Member Financial Assurance Policy. In the first clause (x) and the first clause (y) of the second paragraph of Section II.B.4. of the Member Financial Assurance Policy, "purchases of Market Products" is changed to "purchases and sales of Market Products" in each place where that phrase appears.
2.7 Amendment to Section II.B.4. of the Member Financial Assurance Policy. In the last sentence of the second paragraph of Section II.B.4. of the Member Financial Assurance Policy, "purchase Market Products" is changed to "purchase or sell Market Products."
2.8 Amendment to Section II.B.4. of the Member Financial Assurance Policy.
The following is added at the end of the second paragraph of Section
II.B.4. of the Member Financial Assurance Policy:
In addition to the notices provided for herein, the System Operator will provide any additional information required under the Information Policy.
2.9 Amendment to Section V.D. of the Member Financial Assurance Policy. The last sentence of the first paragraph of Section V.D. of the Member Financial Assurance Policy is deleted.
2.10 Amendment to Section V.F. of the Member Financial Assurance Policy. The following is added at the end of the first paragraph of Section V.F. of the Member Financial Assurance Policy:
In addition to the notices provided for herein, NEPOOL and/or the System Operator will provide any additional information required under the Information Policy.
SECTION 3 AMENDMENTS TO NON-PARTICIPANT FINANCIAL ASSURANCE POLICY
3.1 Amendment to Section I.A.1 of the Non-Participant Financial Assurance Policy. The second sentence of the first paragraph of Section I.A.1 of the Financial Assurance Policy for NEPOOL Non-Participant Transmission Customers included as Attachment M to the NEPOOL Tariff, as amended by the Eighty-First Agreement Amending New England Power Pool Agreement (the "Non-Participant Financial Assurance Policy"), is amended to insert "and" immediately before "(iv)" and to delete"; and (v) a list of the officers and principal management of the Non-Participant Applicant" at the end of the that sentence.
3.2 Amendment to Section I.A.1 of the Non-Participant Financial Assurance Policy. In the second sentence of the second paragraph of Section I.A.1 of the Non-Participant Financial Assurance Policy, "(v)" is changed to "(iv)".
3.3 Amendment to Section I.A.2 of the Non-Participant Financial Assurance Policy. In the first sentence of Section I.A.2 of the Non-Participant Financial Assurance Policy, the phrase "and a list of its officers and principal management" is deleted. In the second sentence of that section,": (i) the background of the Non- Participant Transmission Customer's officers and principal management; and (ii)" is deleted.
SECTION 4 AMENDMENTS TO NEPOOL BILLING POLICY
4.1 Amendment to Section 3.3(e) of the NEPOOL Billing Policy. The followin is added immediately after the first sentence of Section 3.3(e) of the New England Power Pool Billing Policy included as Attachment N to the NEPOOL Tariff (the "Billing Policy"):
Amounts withdrawn from the Late Payment Account and applied toward any shortfall resulting from the Default Amount shall not relieve the defaulting Participant or defaulting Non-Participant Transmission Customer of its obligation to pay such Default Amount.
4.2 Amendment to Section 3.3(j) of the NEPOOL Billing Policy. Section 3.3(j) of the NEPOOL Billing Policy is amended as follows:
(j) Notice and Suspension. Without limiting any of the other remedies described above, in the event that the ISO, in its reasonable opinion, believes that all or any part of any amount due to be paid by any Participant or any Non-Participant Transmission Customer will not be or has not been paid when due (a "Payment Default"), the ISO (on its own behalf or on behalf of NEPOOL) may (but shall not be required to) notify such Participant or Non-Participant Transmission Customer in writing, electronically and by first class mail sent in each case to such Participant's member or alternate on the Participants Committee or billing contact (it being understood that the ISO will use reasonable efforts to contact all three) or such Non-Participant Transmission Customer's billing contact, of such Payment Default. If a Payment Default is not cured within five days after when such payment was originally due, the ISO shall notify each member and alternate on the NEPOOL Participants Committee, each Participant's billing contact and each of the New England governors and utility regulatory agencies of (i) the identity of the Participant or Non-Participant Transmission Customer receiving such notice, (ii) whether such notice relates to a Payment Default, (iii) whether the defaulting Participant has a registered load asset, and (iv) the actions the ISO plans to take and/or has taken in response to such Payment Default. In addition, the ISO will provide any additional information with respect to such Payment Default as may be required under the Information Policy. If a Payment Default is not cured within ten days after when such payment was originally due, the defaulting Participant or Non-Participant Transmission Customer shall be suspended (if applicable) from (a) making any purchases or sales of Market Products in the NEPOOL Market; (b) scheduling any future transmission service under the Tariff; and (c) voting on matters before the Participants Committee or any Technical Committee, in each case until (x) in the case of purchases and sales of Market Products and the scheduling of transmission services, such Payment Default has been cured in full, and (y) in the case of voting on matters before the Participants Committee or any Technical Committee, such Payment Default has been cured in full at least three Business Days prior to such vote; provided; however, that any suspension of a Participant's authority to vote on matters before the Participants Committee or any Technical Committee hereunder shall not be effective while an appeal of such suspension is pending. The suspension of a Participant's ability to purchase or sell Market Products in the NEPOOL Market shall not limit, in any way, NEPOOL's or the ISO's right to invoice or collect payment for any amounts owed (whether such amounts are due or becoming due) by such Participant under the Documents. If the ISO has issued a notice that a Participant or a Non-Participant Transmission Customer has defaulted on a payment obligation and that Participant or Non-Participant Transmission Customer subsequently cures that Payment Default, such Participant or Non-Participant Transmission Customer may request the ISO to issue a notice stating such fact; provided; however, that the ISO shall not be required to issue that notice unless, in its sole discretion, the ISO determines that such Payment default has been cured.
SECTION 5 MISCELLANEOUS
5.1 This Eighty-Third Agreement shall become effective on June 1, 2002, or on such other date as the Commission shall provide that the amendments reflected herein shall become effective.
5.2 Terms used in this Eighty-Third Agreement that are not defined herein shall have the meanings ascribed to them in the NEPOOL Agreement.
Exhibit 10.25.14
EIGHTY-FOURTH AGREEMENT AMENDING
NEW ENGLAND POWER POOL AGREEMENT
(INTEGRATION OF MERCHANT TRANSMISSION FACILITIES)
THIS EIGHTY-FOURTH AGREEMENT AMENDING NEW ENGLAND POWER POOL AGREEMENT, dated as of April 5, 2002 ("Eighty-Fourth Agreement"), amends the New England Power Pool Agreement (the "NEPOOL Agreement"), as amended.
WHEREAS, the NEPOOL Agreement as in effect on December 1, 1996 was amended and restated by the Thirty-Third Agreement Amending the New England Power Pool Agreement dated as of December 1, 1996 (the "Thirty-Third Agreement") in the form of the Restated New England Power Pool Agreement ("Restated NEPOOL Agreement") attached to the Thirty-Third Agreement as Exhibit A thereto, and the Thirty-Third Agreement also provided for the NEPOOL Open Access Transmission Tariff (the "NEPOOL Tariff") which is Attachment B to the Restated NEPOOL Agreement; and
WHEREAS, the Restated NEPOOL Agreement and the NEPOOL Tariff have subsequently been amended numerous times, the most recent amendment dated as of January 18, 2002; and
WHEREAS, the Participants desire to amend the Restated NEPOOL Agreement and the NEPOOL Tariff, as heretofore amended, to reflect the revisions detailed herein.
NOW, THEREFORE, upon approval of this Eighty-Fourth Agreement by the NEPOOL Participants Committee in accordance with the procedures set forth in the Restated NEPOOL Agreement, the Participants agree as follows:
SECTION 1
AMENDMENTS TO RESTATED NEPOOL AGREEMENT
1.1 Addition of Definition of MTF. The following definition is added to Section 1 of the Restated NEPOOL Agreement and inserted in the appropriate alphabetical order:
MTF is/are the transmission facility or facilities defined and classified as MTF pursuant to the Tariff.
1.2 Amendment to Definition of "Facilities Study" and "System Impact Study". The phrase "and/or MTF" is added immediately after each occurrence of the phrase "NEPOOL Transmission System" in the definitions of "Facilities Study" and "System Impact Study".
1.3 Amendment to Section 7.5(c). Section 7.5(c) of the NEPOOL Agreement is amended by adding the following proviso to the end of subsection (c): "; provided that the Participants Committee shall not have authority over MTF costs or charges."
1.4 Amendment to Section 15.1. The following new subsection is inserted immediately after Section 15.1(1)(c):
(d) Lines and associated facilities that are classified as MTF.
1.5 Amendment to Section 16.2. The following sentence is added to the end of Section 16.2:
Participants and their Related Persons who are MTF Providers shall collectively provide service over the MTF through the System Operator to other Participants and other Eligible Customers pursuant to the Tariff.
1.6 Amendment to Section 17.7. Section 17.7 of the Restated NEPOOL Agreement is amended by inserting the phrase "on the NEPOOL Transmission System" in the first sentence so that the first sentence reads as follows:
Any charges for transmission service on the NEPOOL Transmission System pursuant to this Section 17 by any Participant to another Participant shall be just, reasonable and not unduly discriminatory or preferential.
SECTION 2
AMENDMENTS TO THE NEPOOL TARIFF
2.1 New and Modified Definitions. The following definitions are added to Section 1 of the NEPOOL Tariff and inserted in the appropriate alphabetical order, or modified:
Ancillary Services: Those services that are necessary to support the transmission of electric capacity and energy from resources to loads while maintaining reliable operation of the NEPOOL Transmission System and/or MTF in accordance with Good Utility Practice.
Elective Transmission Upgrade: An addition to or modification of the NEPOOL Transmission System and/or MTF that is not: (i) a Generator Interconnection Related Upgrade; (ii) a Reliability Upgrade (including a NEMA Upgrade, as appropriate); (iii) an Economic Upgrade (including a NEMA Upgrade, as appropriate); (iv) a Quick Fix Upgrade; or (v) initially proposed in an Elective Transmission Upgrade Application filed with the System Operator in accordance with Section 50.2 on a date after the addition or modification already has been otherwise identified in the current NEPOOL Transmission Plan (other than as an Elective Transmission Upgrade) in publication as of the date of that application. An Elective Transmission Upgrade may increase transfer capability of the NEPOOL Transmission System and/or MTF, may increase the reliability or stability of the NEPOOL Transmission System and/or MTF above the requirements and criteria established by NERC, NPCC or the NEPOOL Reliability Committee, or may reduce Congestion Costs into Load Zones or at Nodes into or within the NEPOOL Control Area.
Facilities Study: An engineering study conducted pursuant to the Agreement or this Tariff by the System Operator and/or one or more affected Participants to determine the required modifications to the NEPOOL Transmission System and/or MTF, including the cost and scheduled completion date for such modifications, that will be required to provide a requested transmission service or interconnection.
Firm Transmission Service: Service for Native Load Customers, firm Regional Network Service (Network Integration Transmission Service), service for Excepted Transactions, Firm Internal Point-To-Point Transmission Service, Firm MTF Service or Firm Through or Out Service.
Import Transaction: An energy delivery originating outside
the NEPOOL Control Area that uses the PTF to deliver energy
to Network Load within the NEPOOL Control Area, except for:
(i) a delivery that uses a direct interconnection between
the NEPOOL Control Area and the Hydro-Quebec transmission
system that existed as of January 1, 2000; or (ii) a
delivery that uses a direct interconnection between the
NEPOOL Control Area and an adjacent Control Area that is a
Merchant Transmission Facility.
MTF: The Merchant Transmission Facility or Facilities defined and classified as MTF pursuant to Schedule 18.
MTF Provider: An entity as defined in Schedule 18.
MTF Service: Transmission service over MTF as provided for in Schedule 18.
Non-PTF: The transmission facilities owned by the Participants that do not constitute PTF or MTF.
Point-To-Point Transmission Service: The transmission of capacity and/or energy on either a firm or non-firm basis from the Point(s) of Receipt to the Point(s) of Delivery under this Tariff. NEPOOL Point-To-Point Transmission Service includes Internal Point-to-Point Service, Through or Out Service and MTF Service.
Regional Network Service: The transmission service over the NEPOOL Transmission System described in Part II and Part VI of this Tariff.
Reserved Capacity: The maximum amount of capacity and energy that is committed to the Transmission Customer for transmission over the NEPOOL Transmission System or MTF between the Point(s) of Receipt and the Point(s) of Delivery under Part V or Schedule 18 of this Tariff. Reserved Capacity shall be expressed in terms of whole kilowatts on a sixty-minute interval (commencing on the clock hour) basis.
System Impact Study: An assessment pursuant to Part V, VI or VII of this Tariff of (i) the adequacy of the NEPOOL Transmission System and/or MTF to accommodate a request for the interconnection of a new or materially changed generating unit or a new or materially changed interconnection to another Control Area or new Regional Network Service, Internal Point-to-Point Service or Through or Out Service, and (ii) whether any additional costs may be required to be incurred in order to provide the interconnection or transmission service.
Through or Out Service: Point-To-Point Transmission Service over the NEPOOL Transmission System provided by the Participants with respect to a transaction that goes through the NEPOOL Control Area, as, for example, a single transaction where energy or capacity is transmitted into the NEPOOL Control Area from the Maine Electric Power Company line or New Brunswick and subsequently out of the NEPOOL Control Area to New York, or a single transaction where energy or capacity is transmitted into the NEPOOL Control Area from New York through one point on the PTF and subsequently flows over the PTF prior to passing out of the NEPOOL Control Area to New York, or with respect to a transaction which originates at a point on the PTF and flows over the PTF prior to passing out of the NEPOOL Control Area, as, for example, from Boston to New York.
Ties: (i) The PTF lines and facilities which connect the NEPOOL Transmission System to the transmission line owned by Maine Electric Power Company, which is in turn connected to the transmission system in New Brunswick, (ii) the PTF and/or MTF lines and facilities which connect the NEPOOL Transmission System to the transmission system in New York and (iii) any new PTF and/or MTF lines and facilities which connect the NEPOOL Transmission System to the transmission system in another Control Area.
2.2 Amendment to Section 2. The first sentence of Section 2 of the NEPOOL Tariff is amended to read as follows:
This Tariff, together with the transmission provisions in Part Four of the Agreement, is intended to provide a regional arrangement which will cover uses of the NEPOOL Transmission System and/or MTF.
2.3 Amendment to Section 4. The following sentence is added
following the last sentence of the first paragraph of
Section 4:
Ancillary Services for MTF shall be allocated and paid for in accordance with Schedule 18 of the Tariff.
2.4 Amendment to Title of Part III. The title of Part III is amended to read as follows:
III. THROUGH OR OUT SERVICE; INTERNAL POINT-TO-POINT SERVICE; MTF SERVICE
2.5 Amendment to Preamble of Section III. The preamble to Part III is amended to include "MTF Service" and as amended reads as follows:
Point-To-Point Transmission Service as Through or Out Service, MTF Service or Internal Point-To-Point Service will be provided during and after the Transition Period pursuant to the applicable terms and conditions of Part III, Part V and Schedule 18 of the Tariff.
2.6 Addition of Section 22A. A new Section 22A is added after
Section 22 as follows:
MTF Service: Schedule 18 of this Tariff shall govern MTF Service.
2.7 Amendment to Preamble of Part V. The preamble of Part V is amended to read as follows:
Firm or Non-Firm Point-To-Point Transmission Service shall be reserved by all Transmission Customers, whether Participants or Non-Participants, for all new transfers to be effected as Internal Point-to-Point Service, MTF Service or as Through or Out Service, pursuant to the applicable terms and conditions of Part III, Part V and Schedule 18 of the Tariff. Point-To-Point Transmission Service is the service required for the receipt of capacity and/or Energy at designated Point(s) of Receipt and the transmission of such capacity and/or Energy to designated Point(s) of Delivery. MTF Service shall be reserved on the OASIS separately or as a component of a single reservation in connection with Through or Out Service or Internal Point-to- Point Service. Priority of MTF Service shall be in accordance with the provisions of Schedule 18 of the Tariff and as provided below.
2.8 Amendment to Section 27.2. Section 27.2 of the NEPOOL Tariff is amended to read as follows:
Reservation Priority: Long-Term Firm Point-To-Point
Transmission Service over the PTF shall be available to
Participants and Non-Participants on a first-come, first-
served basis, i.e., in the chronological sequence in which
each Transmission Customer's application for reserved
service is received by the System Operator pursuant to
Section 31. Reservations for Short-Term Firm Point-To-Point
Transmission Service over the PTF will be conditional based
upon the length of the requested transaction. If the NEPOOL
Transmission System and MTF become oversubscribed,
reservation priorities shall be established separately for
the NEPOOL Transmission System and MTF, respectively.
Requests for longer term service over the PTF may preempt
requests for shorter term service up to the following
deadlines: one day before the commencement of daily
service, one week before the commencement of weekly service,
and one month before the commencement of monthly service.
Before the conditional reservation deadline, if available
transmission capability is insufficient to satisfy all
Applications, an Eligible Customer with a reservation for
shorter term service over the PTF has the right of first
refusal to match any longer term reservation before losing
its reservation priority. A longer term competing request
for Short-Term Firm Point-To-Point Transmission Service over
the PTF will be granted if the Eligible Customer with the
right of first refusal does not agree to match the competing
request within 24 hours (or earlier if necessary to comply
with the scheduling deadlines provided in Section 27.8) from
being notified by the System Operator of a longer-term
competing request for Short-Term Firm Point-To-Point
Transmission Service over the PTF. After the conditional
reservation deadline, service will commence pursuant to the
terms of Part III of this Tariff. Firm Point-To-Point
Transmission Service over the PTF will have a reservation
priority over Non-Firm Point-To-Point Transmission Service
over the PTF and all Long-Term Firm Point-To-Point
Transmission Service over the PTF will have reservation
priority equal to Native Load Customers, Network Customers
and customers for Excepted Transactions. Reservation
priorities for existing firm service customers, including
customers receiving service with respect to Excepted
Transactions, are provided in Section 3.2. As between or
among oversubscribed transactions that require the use of
both the NEPOOL Transmission System and MTF, the reservation
priority for such competing Point-To-Point Transmission
Service requests over the PTF shall be determined by the
reservation priority held by the Transmission Customers over
the MTF.
2.9 Amendment to Section 27.6. Section 27.6 of the NEPOOL Tariff is amended to read as follows:
Curtailment of Firm Transmission Service: In the event that a Curtailment on the NEPOOL Transmission System and/or MTF, or a portion thereof, is required to maintain reliable operation of the system, the Curtailment will be made on a non-discriminatory basis to the transaction(s) that effectively relieve the constraint. If multiple transactions require Curtailment, to the extent practicable and consistent with this Section and Good Utility Practice, the System Operator will curtail service to Network Customers and Transmission Customers taking Firm Point-To- Point Transmission Service on a non-discriminatory basis. All Curtailments will be made on a non-discriminatory basis; however, Non-Firm Point-To-Point Transmission Service shall be subordinate to Firm Transmission Service, except for Curtailment of competing transactions that require the use of both the NEPOOL Transmission System and MTF. As between or among such competing transactions, Curtailment will be accomplished based upon the reservation priority held by the competing Transmission Customers over the MTF without regard to the priority for those competing transactions of the service over the NEPOOL Transmission System to or from the MTF such that Point-To-Point Transmission Service for a Transmission Customer that holds a Firm MTF Service reservation has priority over Point-To-Point Transmission Service for a Transmission Customer that holds a Non-Firm MTF Service Reservation. When the System Operator determines that an electrical emergency exists on the NEPOOL Transmission System and/or MTF and implements emergency procedures to effect a Curtailment of Firm Transmission Service, the Transmission Customer shall make the required reductions upon the System Operator's request. However, NEPOOL reserves the right to effect a Curtailment, in whole or in part, of any Firm Transmission Service provided under this Tariff when, in the System Operator's sole discretion, an emergency or other unforeseen condition impairs or degrades the reliability of the NEPOOL Transmission System and/or MTF. The System Operator will notify all affected Transmission Customers in a timely manner of any scheduled Curtailments. In the event the System Operator exercises its right to effect a Curtailment, in whole or part, of Firm Point-To-Point Transmission Service, no credit or other adjustment shall be provided as a result of the Curtailment with respect to the charge payable by the Customer.
2.10 Amendment to Section 27.7. Section 27.7(b) of the NEPOOL Tariff is amended to include the words "and/or MTF" immediately following phrase "the NEPOOL Transmission System."
2.11 Amendment to Section 28.2. Section 28.2 of the NEPOOL Tariff is amended to read as follows:
Reservation Priority: Non-Firm Point-To-Point Transmission Service shall be available from transmission capability in excess of that needed for reliable service to Native Load Customers, Network Customers, customers for Excepted Transactions and other Transmission Customers taking Long- Term and Short-Term Firm Point-To-Point Transmission Service. A higher priority will be assigned to reservations with a longer duration of service. In the event the NEPOOL Transmission System and MTF are constrained, reservation priorities shall be established separately for the NEPOOL Transmission System and MTF, respectively. Competing requests of equal duration over PTF will be prioritized based on the highest price offered by the Eligible Customer for the Transmission Service, or in the event the price for all Eligible Customers is the same, will be prioritized on a first-come, first-served basis i.e., in the chronological sequence in which each Customer has reserved service. Eligible Customers that have already reserved shorter term service over PTF have the right of first refusal to match any longer term reservation before being preempted. A longer term competing request over PTF for Non-Firm Point-To- Point Transmission Service will be granted if the Eligible Customer with the right of first refusal does not agree to match the competing request: (a) immediately for hourly Non- Firm Point-To-Point Transmission Service after notification by the System Operator; and (b) within 24 hours (or earlier if necessary to comply with the scheduling deadlines provided in Section 28.6) for Non-Firm Point-To-Point Transmission Service other than hourly transactions after notification by the System Operator. Secondary transmission service for Network Customers pursuant to Section 40.4 will have a higher priority than any Non-Firm Point-To-Point Transmission Service over PTF. Non-Firm Point-To-Point Transmission Service over PTF to secondary Point(s) of Receipt and Point(s) of Delivery will have the lowest reservation priority under this Tariff. As between or among transactions that require the use of both the NEPOOL Transmission System and MTF, the reservation priority for such competing Point-To-Point Transmission Service requests shall be determined by the reservation priority held by the Transmission Customer over MTF.
2.12 Amendment to Section 28.7. Section 28.7 of the NEPOOL Tariff is amended to read as follows:
Curtailment or Interruption of Service: (a) The System
Operator reserves the right to effect a Curtailment, in
whole or in part, of Non-Firm Point-To-Point Transmission
Service provided under this Tariff for reliability reasons
when an emergency or other unforeseen condition threatens to
impair or degrade the reliability of the NEPOOL Transmission
System and/or the MTF. The System Operator reserves the
right to effect an Interruption, in whole or in part, of Non-
Firm Point-To-Point Transmission Service provided under this
Tariff for economic reasons in order to accommodate (1) a
request for Firm Transmission Service, (2) a request for Non-
Firm Point-To-Point Transmission Service of greater
duration, or (3) transmission service for Network Customers.
The System Operator also will discontinue or reduce service
to the Transmission Customer to the extent that deliveries
for transmission are discontinued or reduced at the Point(s)
of Receipt. Where required, Curtailments or Interruptions
will be made on a non-discriminatory basis to the
transaction(s) that effectively relieve the constraint;
however, Non-Firm Point-To-Point Transmission Service shall
be subordinate to Firm Transmission Service, except as
provided in Section 28.7(b). If multiple transactions
require Curtailment or Interruption, to the extent
practicable and consistent with this Section and Good
Utility Practice, Curtailments or Interruptions will be made
to transactions of the shortest term (e.g., hourly non-firm
transactions will be Curtailed or Interrupted before daily
non-firm transactions and daily non-firm transactions will
be Curtailed or Interrupted before weekly non-firm
transactions). Transmission service for Network Customers
will have a higher priority than any Non-Firm Point-To-Point
Transmission Service under this Tariff except as provided in
Section 28.7(b). Non-Firm Point-To-Point Transmission
Service furnished over secondary Point(s) of Receipt and
Point(s) of Delivery will have a lower priority than any
other Non-Firm Point-To-Point Transmission Service under
this Tariff except as provided in Section 28.7(b).
(b) To the extent competing transactions require the use of both the NEPOOL Transmission System and MTF, Curtailments or Interruptions for such competing transactions will be accomplished based upon the reservation priority held for such transactions over the MTF, without regard to the priorities for those competing transactions of the service over the NEPOOL Transmission System to or from the MTF, such that Point-To-Point Transmission Service for a Transmission Customer that holds a Firm MTF Service reservation has priority over Point-To-Point Transmission Service for a Transmission Customer that holds a Non-Firm MTF Service reservation.
(c) The System Operator will provide advance notice of Curtailment or Interruption where such notice can be provided consistent with Good Utility Practice. In the event the System Operator exercises its right to effect a Curtailment, in whole or part, of Non-Firm Point-To-Point Transmission Service, no credit or other adjustment shall be provided as a result of the Curtailment with respect to the charge payable by the Customer. In the event the System Operator exercises its right to effect an Interruption, in whole or part, of Non-Firm Point-To-Point Transmission Service, the charge payable by the Customer shall be computed as if the term of service actually rendered were the term of service reserved; provided that an adjustment of the charge shall be made only when the Interruption is initiated by the System Operator, not when the Customer fails to deliver energy to NEPOOL.
2.13 Amendment to Section 29.6. The following sentence is added to the end of Section 29.6 of the NEPOOL Tariff:
Real power losses across MTF shall be allocated in accordance with Schedule 18 of this Tariff.
2.14 Amendment to Insert the Phrase "and/or MTF". The phrase "and/or MTF" is inserted immediately after each occurrence of the phrase "NEPOOL Transmission System" in the following Sections of the NEPOOL Tariff: 29.7, 31.2, 33.2, 33.6, 33.7, and 35.2.
2.15 Amendment to Section 33.1 of the NEPOOL Tariff. The first sentence of Section 33.1 of the NEPOOL Tariff is amended to insert "and/or MTF" immediately following the phrase "Participants whose PTF".
2.16 Amendment to Section 45.5. The first sentence of Section 45.5 of the NEPOOL Tariff is amended to insert the phrase "MTF Service" immediately following the phrase "Internal Point-To-Point Service".
2.17 Amendment to Section 45.6. Section 45.6 of the NEPOOL Tariff is amended to include the phrase "and/or MTF" immediately following "NEPOOL Transmission System" and to include "MTF Service" immediately following "Internal Point- to-Point Service."
2.18 Amendment to Section 51.8. Subsection (ii) of part (b) is eliminated, with numbering adjusted accordingly. In addition, the following new subsection (c) is inserted immediately after Section 51.8(b):
(c) MTF shall be subject to the operational control, scheduling and maintenance coordination of the System Operator.
2.19 Amendment to Schedule 1. Schedule 1 of the NEPOOL Tariff is amended to read as follows:
SCHEDULE 1
Scheduling, System Control and Dispatch Service
Scheduling, System Control and Dispatch Service is the service required to schedule at the pool level the movement of power through, out of, within, or into the NEPOOL Control Area. Local level service is provided under the Local Network Service tariffs of the Participants which are the individual Transmission Providers. For transmission service under this Tariff, this Ancillary Service can be provided only by the System Operator and the Transmission Customer must purchase this service from the System Operator. Charges for Scheduling, System Control and Dispatch Service are to be based on the expenses incurred by the System Operator, and by the individual Transmission Providers in the operation of satellite dispatch centers or otherwise, to provide these services. Effective as of January 1, 1999, or such other date as the Commission may determine, the expenses incurred by the System Operator in providing these services are to be recovered under its Tariff for Transmission Dispatch and Power Administration Services, which has been filed in Docket No. ER98-3554-000. A surcharge for the expenses incurred by Participants in the provision of these services for transmission service over the PTF will be added to the Internal Point-to-Point Service rate, to the Through or Out Service rate, and to the Regional Network Service rate. Any Scheduling, System Control and Dispatch Service expenses for the provisions of these services for MTF Service shall be determined separately and assessed to Transmission Customers receiving MTF Service, in accordance with the arrangements between the Transmission Customers receiving MTF Service and the MTF Provider.
The expenses incurred in providing Scheduling, System Control and Dispatch Service for transmission service over the PTF for each Participant will be determined by an annual calculation based on the previous calendar year's data as shown, in the case of Transmission Providers which are subject to the Commission's jurisdiction, in the Participants' FERC Form 1 report for that year, and shall be based on actual data in lieu of allocated data if specifically identified in the Form 1 report. This amended Schedule 1 shall be effective as of January 1, 1999, or such other date as the Commission may determine. The surcharge shall be redetermined annually as of June 1 in each year and shall be in effect for the succeeding twelve months. The rate surcharge per kilowatt for each month is one-twelfth of the amount derived by dividing the total annual Participant expenses for providing the service by the sum of the average of the coincident Monthly Peaks (as defined in Section 46.1) of all Local Networks for the prior calendar year.
Each Participant or Non-Participant which is obligated to pay the rate for Regional Network Service for a month shall pay the surcharge on the basis of the number of kilowatts of its Monthly Network Load (as defined in Section 46.1) for the month. Each Participant or Non-Participant which is obligated to pay the rate for Internal Point-to- Point Service or Through or Out Service for the applicable period shall pay the surcharge on the basis of the highest amount of its Reserved Capacity for each transaction scheduled as Internal Point-to-Point Service and/or Through or Out Service for such period.
The revenues received under this Schedule 1 to cover the expenses incurred by Participants for providing Scheduling, System Control and Dispatch Service for transmission service over the PTF shall be allocated each month among the Participants whose satellite or other costs are reflected in the computation of the surcharge for the service in proportion to the costs for each which are reflected in the computation of the surcharge.
The details for implementation of Schedule 1 for transmission service over the PTF shall be established in accordance with a rule approved by the Regional Transmission Operations Committee which shall be filed with the Commission and considered a supplement to this Tariff.
2.20 Amendment to Schedule 12. The first sentence of the first paragraph of Schedule 12 of the NEPOOL Tariff is amended to replace the phrase "Merchant Transmission Facilities" with the term "MTF" so that as amended it reads as follows:
All costs of MTF shall be recovered in accordance with the recovery mechanism for those facilities that is filed with and accepted by the Commission.
2.21 Addition of Schedule 18. A new Schedule 18 is added to read as set forth in Appendix A.
2.22 Amendment to Attachment A. Attachment A of the NEPOOL Tariff is amended to read as set out in Appendix B hereto.
SECTION 3
MISCELLANEOUS
3.1 This Eighty-Fourth Agreement shall become effective on June 1, 2002, or on such other date as the Commission shall provide that the amendments reflected herein shall become effective.
3.2 Terms used in this Eighty-Fourth Agreement that are not defined herein shall have the meanings ascribed to them in the NEPOOL Agreement.
Appendix A
SCHEDULE 18
MTF; MTF Service
This Schedule 18 contains the main substantive provisions regarding the treatment of MTF and MTF Service under the Tariff.
1. Definitions
Capitalized terms used and defined in this Schedule 18 shall have the meaning given them under this Schedule. Capitalized terms used and not defined in this Schedule 18 but defined in other provisions of the Tariff shall have the meaning given them under those provisions. Capitalized terms used in this Schedule 18 that are not defined in it or elsewhere in this Tariff shall have the meanings customarily attributed to such terms by the electric utility industry in New England.
1.1 MTF: The Cross Sound Cable high voltage, direct current Merchant Transmission Facilities of plus or minus 150 kV and associated dc/ac converter facilities that are directly interconnected with the 345 kV PTF in Connecticut at the East Shore substation, and the 138kV transmission facilities at the Shoreham substation on Long Island, New York that were subject to the Commission order in TransEnergie U.S., Ltd., 91 FERC Section 61,230 (2000) (Docket No. ER00-1-000).
1.2 MTF Provider: An owner of MTF, or a party holding rights to the transmission capability over MTF pursuant to a Commission-approved rights allocation process, that offers unused transmission capability over the MTF to Eligible Customers through the System Operator and/or NEPOOL OASIS.
1.3 MTF Service: Point-To-Point Transmission Service over MTF.
1.4 MTF Service Charge: The charge applicable to MTF Service, which shall be determined pursuant to arrangements between the MTF Provider and Eligible Customers that take MTF Service, and not under this Tariff. The charge applicable to MTF Service shall be in accordance with the Commission's authorization for the MTF Provider to charge negotiated rates (i.e., rates established pursuant to market mechanisms as recognized for merchant transmission projects and not included in NEPOOL Tariff rates) for the use of transmission capability over its MTF.
2. Allocation of Available Transmission Capability Over MTF
2.1 Commission Approved Allocation Process: All available transmission capability over MTF shall be allocated to the owner of the MTF who may assign it under a Commission-approved rights allocation process. The MTF Provider shall furnish to the System Operator the results of the Commission-approved rights allocation process, which shall be posted on OASIS. To the extent that transmission capability over MTF is not fully reserved through the Commission-approved rights allocation process, such excess transmission capability shall be available in accordance with this Schedule 18. In the event that the entire capability of the MTF is reserved under the Commission-approved rights allocation process, secondary rights to use the MTF, to the extent unused by the primary rights holders, may be offered on the NEPOOL OASIS by MTF Providers in accordance with a Commission-approved process for offering such rights.
3. MTF Service
3.1 Availability of MTF Service: To the extent that transmission
capability over MTF has not been fully allocated in accordance with
Section 2 of this Schedule 18, a Participant or Non-Participant that
is an Eligible Customer (except as provided below) may reserve Firm or
Non-Firm MTF Service. Such service shall be provided by the MTF
Provider(s) and shall be reserved pursuant to the applicable terms and
conditions of this Schedule 18. MTF Service shall be reserved through
the System Operator separately or as a component of a single reservation
in connection with Through or Out Service or Internal Point-to-Point
Service. MTF Service is available to any Eligible Customer unless an
MTF Provider has informed the System Operator that MTF Service shall
not be made available to such Eligible Customer due to that Customer's
failure to make necessary payments for previously assessed MTF Service
Charges or failure to meet the creditworthiness or operational
requirements posted by the MTF Provider on the NEPOOL OASIS.
3.2 Reservation of MTF Service: A Participant or Non-Participant that is an Eligible Customer requesting Firm or Non-Firm MTF Service shall comply with the applicable provisions of Part V of the Tariff.
3.3 Use of MTF Service By a Transmission Customer: If a Transmission Customer elects to take MTF Service it may reserve transmission capability for such service to cover both the delivery to it over the MTF of Energy and capacity (to the extent permitted under applicable Market Rules) covered by the Entitlements or System Contracts designated by it in Completed Applications and the delivery to or from it over the MTF in Interchange Transactions of Energy and/or capacity (to the extent permitted under applicable Market Rules). In order to fulfill its obligations to serve load or to consummate a transaction, a Transmission Customer which takes MTF Service must also take service under the Tariff for use of the PTF and under any applicable Local Network Service tariff for use of the Non-PTF. Any load-serving entity may use MTF Service to effect sales in bilateral arrangements, whether or not it elects to take Point-To-Point Service on PTF to serve its load.
4. Payment for MTF Service
A Transmission Customer shall pay the MTF Service Charge to the MTF Provider if the Customer: (i) receives Firm or Non-Firm MTF Service based upon an allocation of transmission capability over the MTF awarded to the Transmission Customer through a Commission-approved rights allocation process; (ii) reserves on the OASIS transmission capability not initially allocated in the Commission-approved rights allocation process; or (iii) reserves on the OASIS transmission capability made available as a result of a capability forfeiture by a rights holder for nonuse consistent with the terms of a Commission-approved rights allocation. Each Participant or Non-Participant which takes Firm or Non-Firm MTF Service shall pay the MTF Service Charge to the MTF Provider, or its designated agent, where the Transmission Customer takes such Firm or Non-Firm MTF Service based on secondary rights released by the existing MTF Provider through the NEPOOL OASIS.
5. MTF Service Reservation, Interruption and Curtailment Priorities
The MTF Provider shall furnish to the System Operator for posting on NEPOOL OASIS, and the System Operator shall post on the NEPOOL OASIS, rules setting reservation, Interruption and Curtailment priorities for Firm and Non-Firm MTF Service. Such rules shall be non-discriminatory and consistent with the Commission's approval of the rights to charge negotiated rates (i.e., rates established pursuant to market mechanisms as recognized for merchant transmission projects and not included in NEPOOL Tariff rates). If an MTF Provider fails to furnish to the System Operator such rules, reservation, Interruption and Curtailment priorities for Firm and Non-Firm MTF Service shall be the same as those established under the Tariff for Firm and Non-Firm Point-To-Point Transmission Service over the PTF. The reservation priority for Long-Term Firm Transmission Service and Short-Term Firm Transmission Service based upon an award of transmission capability of MTF pursuant to a Commission-approved rights allocation process shall be the date of the issuance of such award.
When the System Operator determines that an electrical emergency exists on the NEPOOL Transmission System and/or MTF and implements emergency procedures to effect a Curtailment of MTF Service, the Transmission Customer shall make the required reductions upon the System Operator's request. The System Operator reserves the right to effect a Curtailment, in whole or in part, of any MTF Service provided under this Tariff when, in the System Operator's sole discretion, an emergency or other unforeseen condition impairs or degrades the reliability of the NEPOOL Transmission System and/or MTF. The System Operator will notify all affected Transmission Customers in a timely manner of any scheduled Curtailments. In the event the System Operator exercises its right to effect a Curtailment, in whole or part, of Firm MTF Service, no credit or other adjustment shall be provided as a result of the Curtailment with respect to the charge payable by the Customer, unless provided for by the MTF Provider under arrangements between the MTF Provider and the Transmission Customer. To the extent not otherwise provided for in this Section 5, Curtailments or Interruptions of MTF Service shall be in accordance with Sections 27.6 and 28.7 of the Tariff.
6. Real Power Losses
Real power losses across MTF shall be allocated solely to Transmission Customers that use MTF. Such allocation shall be pursuant to arrangements between the MTF Providers and the Transmission Customers.
7. No Obligation to Build
MTF Provider status under the Tariff shall not impose an obligation to build transmission facilities on the MTF Provider. The offering of MTF Service under the Tariff shall not impose an obligation to build transmission facilities on the Participants, Transmission Owners or System Operator.
8. No Effect on Rates; No Allocation of Revenues
MTF and MTF Service shall not affect rates for service on the NEPOOL Transmission System under the Tariff and MTF Providers shall not be allocated any revenues collected under the Tariff for such service.
9. Ancillary Services
The System Operator shall determine what Ancillary Services are required, and the extent to which they are required, for transmission service over MTF. The cost of any Ancillary Services provided in connection with such service over MTF shall be assessed to the MTF Provider, which may pass such costs on to Transmission Customers taking MTF Service in accordance with the particular arrangements between the MTF Provider and the MTF Transmission Customers
APPENDIX B
ATTACHMENT A
Form of Service Agreement for
MTF Service and/or
Through or Out Service or Internal Point-To-Point Service
1.0 This Service Agreement, dated as of ____________, is entered into, by and between the NEPOOL Participants and MTF Providers (as applicable for MTF Service), acting through the System Operator, and ________________ ("Transmission Customer").
2.0 The Transmission Customer has been determined by the System Operator to have a Completed Application for Firm [Non-Firm] Transmission Service under this Tariff.
3.0 If required, the Transmission Customer has provided to the System Operator an Application deposit in accordance with the provisions of this Tariff.
4.0 Service under this Service Agreement shall commence on the later of (1) the requested service commencement date, or (2) the date on which construction or any Direct Assignment Facilities and/or facility additions or upgrades are completed, or (3) such other date as it is permitted to become effective by the Commission. Service under this Service Agreement shall terminate on such date as is mutually agreed upon by the parties. [The Service Agreement may be a blanket agreement for non-firm service.]
5.0 The Participants and MTF Provider (as applicable for MTF Service) agree to provide through the System Operator, and the Transmission Customer agrees to take and pay for, Transmission Service in accordance with the provisions of the Tariff and this Service Agreement.
6.0 Any notice or request made to or by either party regarding this Service Agreement shall be made to the representative of the other party as indicated below.
NEPOOL Participants and MTF owners:
c/o ISO New England Inc.
One Sullivan Road
Holyoke, MA 01040-2841
Transmission Customer:
7.0 The Tariff is incorporated in this Service Agreement and made a part hereof.
IN WITNESS WHEREOF, the Parties have caused this Service Agreement to be executed by their respective authorized officials.
NEPOOL Participants and/or MTF Provider:
By [System Operator]
By:
Name Title Date
Transmission Customer:
By:
Name Title Date
|
Specifications For MTF Service and/or Through or Out Service or Internal Point-To-Point Service
1.0 Term of Transaction: ________________________________ Start Date: _________________________________________ Termination Date: ___________________________________
3.0 Point(s) of Receipt:__________________________________ Delivering party:_____________________________________
4.0 Point(s) of Delivery:_________________________________ Receiving party:______________________________________
8.0 Service under this Service Agreement may be subject to some combination of the charges detailed below. (The appropriate charges for individual transactions will be determined in accordance with the terms and conditions of this Tariff.)
8.4 Special Condition: MTF Service shall also be provided in accordance with the terms and conditions of the contract between the MTF Provider and the Eligible Customer as attached hereto.
Exhibit 10.25.15
EIGHTY-FIFTH AGREEMENT AMENDING
NEW ENGLAND POWER POOL AGREEMENT
(NON PARTICIPANT FTR FINANCIAL ASSURANCE POLICY)
THIS EIGHTY-FIFTH AGREEMENT AMENDING NEW ENGLAND POWER POOL AGREEMENT, dated as of May 9, 2002 (the "Eighty-Fifth Agreement"), amends the New England Power Pool Agreement (the "NEPOOL Agreement"), as amended.
WHEREAS, the NEPOOL Agreement as in effect on December 1, 1996 was amended and restated by the Thirty-Third Agreement Amending New England Power Pool Agreement dated as of December 1, 1996 (the "Thirty-Third Agreement") in the form of the Restated New England Power Pool Agreement ("Restated NEPOOL Agreement") attached to the Thirty-Third Agreement as Exhibit A thereto, and the Thirty-Third Agreement also provided for the NEPOOL Open Access Transmission Tariff (the "NEPOOL Tariff") which is Attachment B to the Restated NEPOOL Agreement; and
WHEREAS, the Restated NEPOOL Agreement and the NEPOOL Tariff have subsequently been amended numerous times, the most recent amendment dated as of April [__], 2002; and
WHEREAS, the Participants desire to amend the NEPOOL Agreement, including the NEPOOL Tariff, as heretofore amended, to reflect the revisions detailed herein.
NOW, THEREFORE, upon approval of this Eighty-Fifth Agreement by the NEPOOL Participants Committee in accordance with the procedures set forth in the NEPOOL Agreement, the Participants agree as follows:
SECTION 1 AMENDMENT TO NEPOOL TARIFF
1.1 Addition of Attachment O to NEPOOL Tariff. The Financial Assurance Policy for Non-Participant FTR Customers is added as Attachment O to the NEPOOL Tariff, reading as Attachment 1 hereto.
SECTION 2 MISCELLANEOUS
2.1 The Eighty-Fifth Agreement shall become effective on August 1, 2002 or on such other date as the Commission shall provide that the amendments reflected herein shall become effective.
2.2 Terms used in this Eighty-Fifth Agreement that are not defined herein shall have the meanings ascribed to them in the NEPOOL Agreement.
Attachment 1
ATTACHMENT O
The purpose of this Policy is (i) to establish a financial assurance policy for Non-Participants <FN1> that transact in the FTR Auction and/or Secondary FTR Market ("Non-Participant FTR Customers") and applicants to become Non-Participant FTR Customers ("Non-Participant FTR Applicants") that includes a commercially reasonable credit review procedure to assess the financial ability of a Non-Participant FTR Applicant or of a Non- Participant FTR Customer to pay for such transactions under the Tariff and the applicable Market Rules and other governing documents (the "FTR Documents"); (ii) to set forth the requirements for alternative forms of security from Non-Participant FTR Applicants and Non-Participant FTR Customers that will be deemed acceptable to NEPOOL and consistent with commercial practices established by the Uniform Commercial Code that protect NEPOOL, the System Operator and the FTR and ARR Holders against the risk of non-payment by defaulting Non-Participant FTR Customers; (iii) to set forth the conditions under which NEPOOL will conduct business so as to avoid the possibility of failure of payment by Non-Participant FTR Customers for services rendered under the FTR Documents; and (iv) to collect amounts past due and make up shortfalls in payments and terminate service to defaulting Non-Participant FTR Customers. A Non-Participant FTR Customer's failure to meet the requirements of this Policy may result in suspension or termination of service by NEPOOL.
FINANCIAL ASSURANCE REQUIREMENTS
Each Non-Participant FTR Applicant and Non-Participant FTR Customer shall, upon the request of the System Operator <FN2>, submit the following information to the System Operator: (i) all current rating agency reports from Standard & Poors ("S&P"), Moody's and/or Fitch; (ii) audited financial statements for at least the immediately preceding three (3) years, or the period of its existence, if shorter, including, but not limited to, balance sheets, income statements, statements of cash flows and notes to financial statements, annual and quarterly reports, and 10-K, 10-Q and 8-K Reports; <FN3> (iii) at least one bank reference and three (3) utility company credit references, or in those cases where a Non-Participant FTR Applicant or Non-Participant FTR Customer does not have three (3) utility company credit references, three (3) trade payable vendor references may be substituted; and (iv) relevant information as to any known or anticipated material lawsuits, as well as any prior bankruptcy declarations by the Non-Participant FTR Applicant or Non-Participant FTR Customer, or by its predecessor(s), if any. In the case of certain Non- Participant FTR Applicants and Non-Participant FTR Customers, some of the information and documentation described in the immediately preceding sentence may not be applicable or available, and alternate requirements may be specified by NEPOOL or its designee in its sole discretion.
Each Non-Participant FTR Applicant must submit to the System Operator, with its application for FTR system access, financial assurance, in the form of either a cash deposit or a letter of credit meeting the requirements described below, in an amount that is at least equal to the greater of $500,000 or three-and-one-half (3.5) times the average expected net monthly charges of such Non-Participant FTR Applicant (the "Base Financial Assurance"). The Base Financial Assurance ensures a minimal level of coverage of the hourly market settlements, which amounts cannot be pre-determined, should the Non- Participant FTR Applicant win its bids. The Base Financial Assurance must be maintained at all times that the entity providing it is a Non-Participant FTR Customer, as described below.
If a Non-Participant FTR Customer submits a bid into an FTR Auction, that Non-Participant FTR Customer must provide, in addition to its Base Financial Assurance, financial assurance, in the form of either a cash deposit or a letter of credit meeting the requirements described below, in an amount that is at least equal to the total dollar amount of the bids <FN4> submitted by such FTR Non-Participant FTR Customer in such FTR Auction at the time such FTR Auction closes (the "Bid Financial Assurance"). Moreover, a Non-Participant FTR Customer must maintain, at all times, in addition to its Base Financial Assurance required hereunder, financial assurance, in the form of either a cash deposit or letter of credit meeting the requirements described below, in an amount that is at least equal to the total dollar amount of any awarded bids in any FTR Auctions (the "Award Financial Assurance" and together with the Base Financial Assurance and the Bid Financial Assurance, the "Total Financial Assurance") <FN5>. The System Operator shall compute each Non- Participant FTR Customer's Total Financial Assurance requirement on a daily basis. If a Non-Participant FTR Customer does not have the required level of Total Financial Assurance in place at the time an FTR Auction into which it has bid closes, then, in addition to the other consequences described herein, all bids submitted by that Non-Participant FTR Customer for that FTR Auction will be rejected. The Non-Participant FTR Customer will be allowed to participate in the next FTR Auction held provided it meets all requirements for such participation, including without limitation those set forth herein.
Each Non-Participant FTR Customer must maintain its Total Financial Assurance for the duration of the FTRs awarded to it. Any financial assurance amount collected from a Non-Participant FTR Customer in connection with an unsuccessful bid will be held by the System Operator and applied first against any unsatisfied financial assurance requirement hereunder, and unless that Non-Participant FTR Customer requests in writing to have such financial assurance returned to it, that financial assurance will be applied against future bids and awards by that Non-Participant FTR Customer. Prior to returning any financial assurance to a Non-Participant FTR Customer, the System Operator shall use such financial assurance to satisfy any overdue obligations of that Non-Participant FTR Customer.
The System Operator shall only return to that Non-Participant FTR Customer the balance of such financial assurance after all such overdue obligations have been satisfied.
When a Non-Participant FTR Customer's aggregate outstanding obligations to NEPOOL and the System Operator equal 70 percent (70%) of the available amount of that Non-Participant FTR Customer's financial assurance provided hereunder, exclusive of any Bid Financial Assurance that relates to bids that have not yet been accepted or rejected (the "Test Amount"), the System Operator shall issue anotice thereof to such Non-Participant FTR Customer, such notice to be given in a manner consistent with Section 21 of the Restated NEPOOL Agreement. When a Non-Participant FTR Customer's aggregate outstanding obligations to NEPOOL and the System Operator equal 80 percent (80%) of its Test Amount, (i) the System Operator will issue a notice thereof to that Non-Participant FTR Customer, such notice to be given in a manner consistent with Section 21 of the Restated NEPOOL Agreement, and, (ii) if such condition continues to exist for five business days after the date of such notice, the System Operator shall issue notice thereof to all members and alternates of the NEPOOL Participants Committee. When a Non-Participant FTR Customer's aggregate outstanding obligations to NEPOOL and the System Operator equal 90 percent (90%) of its Test Amount, (i) the System Operator will issue notice thereof to such Non Participant FTR Customer, all members and alternates on the NEPOOL Participants Committee and the New England governors and utility regulatory agencies, such notice to be given in a manner consistent with Section 21 of the Restated NEPOOL Agreement, (ii) such Non-Participant FTR Customer shall be suspended from any right to enter into any future transactions in the FTR system, and (iii) all FTRs held by such Non-Participant FTR Customer (the "Default FTRs") shall be offered in the next FTR Auction, with a bid price of $0. All Default FTRs that have a positive value in that next FTR Auction shall be forfeited by such Non-Participant FTR Customer and will be sold at the applicable clearing price in that FTR Auction. The proceeds from the sale of those Default FTRs will first be used to satisfy all obligations of such Non-Participant FTR Customer to NEPOOL and the System Operator, and any amount remaining after all such obligations have been satisfied shall be paid over to the Non-Participant FTR Customer that formerly owned such Default FTRs. All Default FTRs that have a negative value in the next FTR Auction will be retained by such Non-Participant FTR Customer, and such Non-Participant FTR Customer will remain subject to all of the requirements, including the requirements hereunder, with respect to such Default FTRs retained by it.
A Non-Participant FTR Customer that has been suspended in accordance with the preceding paragraph will not be allowed to participate in the FTR Auctions and Secondary FTR Market without re-registering as a Non-Participant FTR Applicant, and such Non-Participant FTR Applicant shall be required to cure all defaults hereunder prior to the acceptance of its application.
Except as set forth herein, no financial assurance provided under this policy shall be terminated or returned prior to the end date of all awarded FTRs and the final satisfaction of all obligations of the Non-Participant FTR Applicant or Non-Participant FTR Customer providing that financial assurance, even if the Non-Participant FTR Applicant or Non-Participant FTR Customer providing such financial assurance is terminated or withdraws from the FTR system and otherwise satisfies all of its obligations to NEPOOL.
ACCEPTABLE FORMS OF ADDITIONAL FINANCIAL ASSURANCE
A cash deposit for the full value of the financial assurance amount required hereunder, as determined by NEPOOL or the System Operator, provides an acceptable form of financial assurance to NEPOOL.
In the event that actual amounts due to NEPOOL exceed those anticipated, the anticipated charges will be increased accordingly and the Non-Participant FTR Applicant or Non-Participant FTR Customer must augment its cash deposit to reach the required level.
The cash deposit will be invested by the System Operator in direct obligations of the United States or its agencies and interest earned will be paid to the Non-Participant FTR Customer. The System Operator may sell or otherwise liquidate such investments at its discretion to meet the Non- Participant FTR Customer's obligations to NEPOOL and the System Operator.
An irrevocable standby letter of credit for the full value of the financial assurance required hereunder, as determined by NEPOOL or the System Operator, provides an acceptable form of financial assurance to NEPOOL. The letter of credit shall be valued as zero dollars ($0.00) 30 days prior to the termination of such letter of credit.
If the letter of credit amount is below the required level, the Non- Participant FTR Applicant or Non-Participant FTR Customer shall immediately replenish or increase the letter of credit amount; otherwise NEPOOL shall terminate the Non-Participant FTR Applicants or Non-Participant FTR Customer's right to access and participation in the FTR Market.
The form, substance and provider of the letter of credit must all be acceptable to NEPOOL. The letter of credit should clearly state the full names of the "Issuer," "Account Party" and "Beneficiary," the dollar amount available for drawings, and should include a statement required on the drawing certificate and other terms and conditions that should apply. It should also specify that funds will be disbursed, in accordance with the instructions, within one Business Day after due presentation of the drawing certificate. The bank issuing the letter of credit must (i) have a minimum corporate debt rating of an "A-" by S&P, or "A3" by Moody's, or "A-" by Fitch, or an equivalent short-term debt rating by one of these agencies, and (ii) be organized under the laws of the United States or any state thereof or be the United States branch of a foreign bank. The System Operator will confirm no less frequently than quarterly that each bank providing a letter of credit hereunder satisfies the preceding sentence.
Attachment 1 provides a generally acceptable sample "clean" letter of credit, and all letters of credit provided by Non-Participant FTR Applicants and Non-Participant FTR Customers shall be in this form (with only minor, non- material changes), unless a variation therefrom is approved by the Budget and Finance Subcommittee of the Participants Committee. All costs associated with obtaining financial security and meeting the provisions of this Policy are the responsibility of the Non-Participant FTR Applicant or Non- Participant FTR Customer.
MISCELLANEOUS
Under certain conditions, NEPOOL or the System Operator may be obligated to make payments to a Non-Participant FTR Customer. In this event, the amount of the cash deposit or letter of credit required for financial assurance for the contemplated transactions will be reduced ("setoff") by an amount equal to NEPOOL's or the System Operator's unpaid balance or expected billing under the other transactions. The terms and the amount of the setoff must be approved by NEPOOL.
If a Non-Participant FTR Customer is delinquent two or more times within any 12 months in paying on time its charges due to NEPOOL and the System Operator, a late payment charge in an amount equal to the greater of (i) two percent (2%) of the total amount of such late payment or (ii) $250.00 will be billed to that Non-Participant FTR Customer. In addition interest will be charged on any delinquent payments at the rate provided in Section 8.3 of the Tariff.
<FN1> Capitalized terms used but not defined in this Policy are intended to have the meanings given to such terms in the Restated NEPOOL Agreement or the Restated NEPOOL Open Access Transmission Tariff (the "Tariff").
<FN2> The System Operator will act as NEPOOL's agent in managing and enforcing this Policy. Accordingly, all financial information required pursuant to this Policy is to be provided to the System Operator, which will keep all such information confidential in accordance with the provisions of the NEPOOL Information Policy.
<FN3> If any of the above-mentioned financial statements are available on the Internet, the Non-Participant FTR Applicant or Non-Participants FTR Customer may provide instead a letter to NEPOOL stating where such statements may be located and retrieved by NEPOOL or its designee.
<FN4> The total dollar amount of the bids submitted is equal to the bid dollar amount per megawatt multiplied by the total amount of megawatts bid.
<FN5> Once a bid in an FTR Auction is awarded, the Bid Financial Assurance that relates to such bid will be converted to the Award Financial Assurance relating to such awarded bid. The required amount of the Award Financial Assurance will be based on the amount of the awarded bid, not on the amount initially bid.
ATTACHMENT 1
[EXPIRATION DATE] AT OUR COUNTERS
WE DO HEREBY ISSUE AN IRREVOCABLE NON-TRANSFERABLE STANDBY LETTER OF CREDIT BY ORDER OF AND FOR THE ACCOUNT OF ON BEHALF OF [NON-PARTICIPANT FTR CUSTOMER] ("ACCOUNT PARTY") IN FAVOR OF THE PARTICIPANTS IN THE NEW ENGLAND POWER POOL ("NEPOOL") IN AN AMOUNT NOT EXCEEDING US$ ______.00 (UNITED STATES DOLLARS ____________ AND 00/100) AGAINST PRESENTATION TO US OF A DRAWING CERTIFICATE SIGNED BY A PURPORTED OFFICER OR AUTHORIZED AGENT OF NEPOOL AND DATED THE DATE OF PRESENTATION CONTAINING THE FOLLOWING STATEMENT:
"THE UNDERSIGNED HEREBY CERTIFIES TO [BANK] ("BANK"), WITH REFERENCE TO IRREVOCABLE NON-TRANSFERABLE STANDBY LETTER OF CREDIT NO. ISSUED BY [BANK] IN FAVOR OF THE PARTICIPANTS IN THE NEW ENGLAND POWER POOL ("NEPOOL"), THAT [NON-PARTICIPANT FTR CUSTOMER] HAS FAILED TO PAY NEPOOL AND/OR ISO NEW ENGLAND IN ACCORDANCE WITH THE TERMS AND PROVISIONS OF THE RESTATED NEPOOL AGREEMENT BETWEEN [NON-PARTICIPANT FTR CUSTOMER] AND THE OTHER NEPOOL MEMBERS, AND THUS NEPOOL IS DRAWING UPON THE LETTER OF CREDIT IN AN AMOUNT EQUAL TO $_______________."
IF PRESENTATION OF ANY DRAWING CERTIFICATE IS MADE ON A BUSINESS DAY AND SUCH PRESENTATION IS MADE AT OUR COUNTERS ON OR BEFORE 10:00 A.M. _________ TIME, WE SHALL SATISFY SUCH DRAWING REQUEST ON THE SAME BUSINESS DAY. IF THE DRAWING CERTIFICATE IS RECEIVED AT OUR COUNTERS AFTER 10:00 A.M. ___________ TIME, WE WILL SATISFY SUCH DRAWING REQUEST ON THE NEXT BUSINESS DAY, FOR THE PURPOSES OF THIS SECTION, A BUSINESS DAY MEANS A DAY, OTHER THAN A SATURDAY OR SUNDAY, ON WHICH COMMERCIAL BANKS ARE NOT AUTHORIZED OR REQUIRED TO BE CLOSED IN NEW YORK, NEW YORK. DISBURSEMENTS SHALL BE IN ACCORDANCE WITH THE INSTRUCTIONS OF NEPOOL.
THE FOLLOWING TERMS AND CONDITIONS APPLY:
THIS LETTER OF CREDIT SHALL EXPIRE AT THE CLOSE OF BUSINESS [DATE]. THE AMOUNT WHICH MAY BE DRAWN BY YOU UNDER THIS LETTER OF CREDIT SHALL BE AUTOMATICALLY REDUCED BY THE AMOUNT OF ANY UNREIMBURSED DRAWINGS HEREUNDER AT OUR COUNTERS. ANY NUMBER OF PARTIAL DRAWINGS ARE PERMITTED FROM TIME TO TIME HEREUNDER.
ALL COMMISSIONS AND CHARGES WILL BE BORNE BY THE ACCOUNT PARTY.
THIS LETTER OF CREDIT IS NOT TRANSFERABLE OR ASSIGNABLE. THIS LETTER OF CREDIT DOES NOT INCORPORATE AND SHALL NOT BE DEEMED MODIFIED, AMENDED OR AMPLIFIED BY REFERENCE TO ANY DOCUMENT, INSTRUMENT OR AGREEMENT (A) THAT IS REFERRED TO HEREIN (EXCEPT FOR THE UCP, AS DEFINED BELOW) OR (B) IN WHICH THIS LETTER OF CREDIT IS REFERRED TO OR TO WHICH THIS LETTER OF CREDIT RELATES.
THIS LETTER OF CREDIT SHALL BE GOVERNED BY THE UNIFORM CUSTOMS AND PRACTICE FOR DOCUMENTARY CREDITS, 1993 REVISION, INTERNATIONAL CHAMBER OF COMMERCE PUBLICATION NO. 500 (THE "UCP"), EXCEPT TO THE EXTENT THAT TERMS HEREOF ARE INCONSISTENT WITH THE PROVISIONS OF THE UCP, INCLUDING BUT NOT LIMITED TO ARTICLES 13(b) AND 17 OF THE UCP, IN WHICH CASE THE TERMS OF THE LETTER OF CREDIT SHALL GOVERN.
THIS LETTER OF CREDIT MAY NOT BE AMENDED, CHANGED OR MODIFIED
WITHOUT THE EXPRESS WRITTEN CONSENT OF NEPOOL AND US.
WE HEREBY ENGAGE WITH YOU THAT DOCUMENTS DRAWN UNDER AND IN COMPLIANCE WITH THE TERMS OF THIS LETTER OF CREDIT SHALL BE DULY HONORED UPON PRESENTATION AS SPECIFIED.
PRESENTATION OF ANY DRAWING CERTIFICATE UNDER THIS STANDBY LETTER OF CREDIT MAY BE SENT TO US BY COURIER, CERTIFIED MAIL, REGISTERED MAIL, TELEGRAM, TELEX TO THE ADDRESS SET FORTH BELOW, OR SUCH OTHER ADDRESS AS MAY HEREAFTER BE FURNISHED BY US. OTHER NOTICES CONCERNING THIS STANDBY LETTER OF CREDIT MAY BE SENT BY FACSIMILE OR SIMILAR COMMUNICATIONS FACILITY TO THE RESPECTIVE ADDRESSES SET FORTH BELOW. ALL SUCH NOTICES AND COMMUNICATIONS SHALL BE EFFECTIVE WHEN ACTUALLY RECEIVED BY THE INTENDED RECIPIENT PARTY.
IF TO THE BENEFICIARY OF THIS LETTER OF CREDIT:
IF TO THE ACCOUNT PARTY:
IF TO US:
-------------------------------- -----------------------------------
[signature] [signature]
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Exhibit 10.25.16
EIGHTY-SIXTH AGREEMENT AMENDING
NEW ENGLAND POWER POOL AGREEMENT
(INTERRUPTIBLE/DISPATCHABLE LOADS FOR OBJECTIVE CAPABILITY)
THIS EIGHTY-SIXTH AGREEMENT AMENDING NEW ENGLAND POWER POOL AGREEMENT, dated as of May 3, 2002 (the "Eighty-Sixth Agreement"), amends the New England Power Pool Agreement (the "NEPOOL Agreement"), as amended.
WHEREAS, the NEPOOL Agreement as in effect on December 1, 1996 was amended and restated by the Thirty-Third Agreement Amending New England Power Pool Agreement dated as of December 1, 1996 (the "Thirty-Third Agreement") in the form of the Restated New England Power Pool Agreement ("Restated NEPOOL Agreement") attached to the Thirty-Third Agreement as Exhibit A thereto, and the Thirty-Third Agreement also provided for the NEPOOL Open Access Transmission Tariff (the "NEPOOL Tariff") which is Attachment B to the Restated NEPOOL Agreement; and
WHEREAS, the Restated NEPOOL Agreement and the NEPOOL Tariff have subsequently been amended numerous times, the most recent amendment dated as of April 5, 2002; and
WHEREAS, the Participants desire to amend the NEPOOL Agreement, including the NEPOOL Tariff, as heretofore amended, to reflect the revisions detailed herein.
NOW, THEREFORE, upon approval of this Eighty-Sixth Agreement by the NEPOOL Participants Committee in accordance with the procedures set forth in the NEPOOL Agreement, the Participants agree as follows:
SECTION 1 AMENDMENTS TO NEPOOL AGREEMENT
1.1 The formula in Section 12.2(a)(1) for determining each Participant's tentative Installed Capability Responsibility in Kilowatts for a month is amended to read as follows:
X = (P(A-N)+Np)(1+T)
1.2 The definition of "P" in Section 12.2(a)(1) is amended to read as follows:
P is the value of the Participant's fraction for the month as determined in accordance with the following formula:
P = Fp / F, wherein:
Fp is the Participant's Adjusted Monthly Peak for the month less any Kilowatts received by such Participant pursuant to a contract of a type that traditionally has been treated by NEPOOL as a firm contract for the purposes of this Section prior to January 1, 1999, but which does not constitute a Firm Contract as defined in this Agreement.
F is the aggregate for the month of the
Adjusted Monthly Peaks for all Participants
less any Kilowatts received by any
Participant pursuant to a contract of a type
that traditionally has been treated by NEPOOL
as a firm contract for the purposes of this
Section prior to January 1, 1999, but which
does not constitute a Firm Contract as
defined in this Agreement.
1.3 The definition of "C" in Section 12.2(a)(1) is deleted.
SECTION 2 AMENDMENT TO MARKET RULES AND PROCEDURES
2.1 Market Rule and Procedure No. 11 is amended as set forth in Attachment 1 hereto.
SECTION 3 MISCELLANEOUS
3.1 The Eighty-Sixth Agreement shall become effective on the first day of the first month in Power Year 2002-2003 following Commission acceptance of the amendments reflected herein or on such other date as the Commission shall provide that the amendments reflected herein shall become effective.
3.2 Terms used in this Eighty-Sixth Agreement that are not defined herein shall have the meanings ascribed to them in the NEPOOL Agreement.
Exhibit 10.25.17
EIGHTY-SEVENTH AGREEMENT AMENDING
NEW ENGLAND POWER POOL AGREEMENT
(FINANCIAL ASSURANCE POLICIES
AND BILLING POLICY)
THIS EIGHTY-SEVENTH AGREEMENT AMENDING NEW ENGLAND POWER POOL AGREEMENT, dated as of June 21, 2002 ("Eighty-Seventh Agreement"), amends the New England Power Pool Agreement (the "NEPOOL Agreement"), as amended.
WHEREAS, the NEPOOL Agreement as in effect on December 1, 1996 was amended and restated by the Thirty-Third Agreement Amending the New England Power Pool Agreement dated as of December 1, 1996 (the "Thirty-Third Agreement") in the form of the Restated New England Power Pool Agreement ("Restated NEPOOL Agreement") attached to the Thirty-Third Agreement as Exhibit A thereto, and the Thirty-Third Agreement also provided for the NEPOOL Open Access Transmission Tariff (the "NEPOOL Tariff") which is Attachment B to the Restated NEPOOL Agreement; and
WHEREAS, the Restated NEPOOL Agreement and the NEPOOL Tariff have subsequently been amended numerous times, the most recent amendment dated as of May 9, 2002; and
WHEREAS, the Participants desire to amend the Restated NEPOOL Agreement, including the NEPOOL Tariff, as heretofore amended, to reflect the revisions detailed herein.
NOW, THEREFORE, upon approval of this Eighty-Seventh Agreement by the NEPOOL Participants Committee in accordance with the procedures set forth in the NEPOOL Agreement, the Participants agree as follows:
SECTION 1 AMENDMENTS TO MEMBER FINANCIAL ASSURANCE POLICY
1.1 Amendment to Section II.A.1 of the Member Financial Assurance Policy.
Section II.A.1 of the Financial Assurance Policy for NEPOOL Members,
included as Attachment L to the NEPOOL Tariff, as amended by the
Eighty-Third Agreement (the "Member Financial Assurance Policy"), is
amended by deleting from the second sentence of the second paragraph the
following text: "as well as a lien search for such Non-Municipal
Applicant."
1.2 Amendment to Section II.A.2 of the Member Financial Assurance Policy.
Section II.A.2 of the Member Policy is amended by deleting the third
sentence.
1.3 Amendment to Section II.B.1.c of the Member Financial Assurance Policy.
Section II.B.1.c of the Member Financial Assurance Policy is amended
to read as follows:
Except as set forth in Part VI below, Governance Only Members and Non-Municipal Participants with average monthly NEPOOL Charges (as hereinafter defined) of $15,000 or less shall not be required to provide a cash deposit, letter of credit, payment bond or guaranty under this Policy.
1.4 Amendment to Section II.B.2.a of the Member Financial Assurance Policy. Clause (iii) of the first paragraph of Section II.B.2.a of the Member Financial Assurance Policy is amended to read as follows:
(iii) 20 percent (20%) of the total amount due and owing at such time to the System Operator, the Participants, the Non-Participant Transmission Customers and the Non-Participants that transact in the FTR Auction and/or Secondary FTR Market ("Non-Participant FTR Customers") by all Participants, Non-Participant Transmission Customers and Non-Participant FTR Customers.
1.5 Amendment to Section II.B.2.b of the Member Financial Assurance Policy. Clause (iii) of the first sentence of Section II.B.2.b of the Member Financial Assurance Policy is amended to read as follows:
(iii) 20 percent (20%) of the total amount due and owing at such time to the System Operator, the Participants, the Non-Participant Transmission Customers and the Non-Participant FTR Customers by all Participants, Non-Participant Transmission Customers and Non-Participant FTR Customers.
1.6 Amendment to Section II.B.4 of the Member Financial Assurance Policy.
Section II.B.4 of the Member Financial Assurance Policy is amended to
read as follows:
4. Consequences Upon Reaching 80%, 90% and 100% of Credit Test Amount
When a Non-Municipal Participant's aggregate outstanding obligations
to NEPOOL, the System Operator and the Non-Participant FTR Customers equal
80 percent (80%) of the sum of (i) that Non-Municipal Participant's then-
effective Credit Limit and (ii) the available amount of the additional
financial assurance provided by that Non-Municipal Participant (exclusive
of any Bid Financial Assurance (defined below) provided by that Non-
Municipal Participant for bids in the FTR Auction that have not yet
been accepted or rejected), which available amount of additional financial
assurance shall be divided by three and one-half (3.5) for purposes of
this determination <FN1> (the sum of item (i) and item (ii) being referred
to herein as the "Credit Test Amount"), the System Operator shall issue
notice thereof to such Non-Municipal Participant, such notice to be given
in the manner provided in Section 21 of the Restated NEPOOL Agreement.
When a Non-Municipal Participant's aggregate outstanding obligations to
NEPOOL, the System Operator and the Non-Participant FTR Customers equal
90 percent (90%) of that Non-Municipal Participant's Credit Test Amount,
(i) the System Operator shall issue notice thereof to such Non-Municipal
Participant, such notice to be given in the manner provided in Section 21
of the Restated NEPOOL Agreement; and (ii) if such condition continues to
exist 10 Business Days after the date of such notice, the System Operator
shall issue notice thereof to all members and alternates of the NEPOOL
Participants Committee.
When a Non-Municipal Participant's aggregate outstanding obligations
to NEPOOL, the System Operator and the Non-Participant FTR Customers equal
100 percent (100%) of that Non-Municipal Participant's Credit Test Amount,
(i) the System Operator shall issue notice thereof to such Non-Municipal
Participant, all members and alternates of the NEPOOL Participants
Committee and the New England governors and utility regulatory agencies,
such notice to be given in the manner provided in Section 21 of the
Restated NEPOOL Agreement, and (ii) such Non-Municipal Participant shall
be suspended from: (a) the NEPOOL Market, as provided in Section II.E
below; (b) receiving transmission service under any existing or pending
arrangements under the Tariff or scheduling any future transmission
service under the Tariff; (c) voting on matters before the Participants
Committee or any Technical Committee; and (d) entering into any future
transactions in the FTR system, in each case until either (x) in the case
of activity in the NEPOOL Market, the scheduling and receipt of
transmission service and entering future transactions in the FTR system,
such Non-Municipal Participant's outstanding obligations to NEPOOL, the
System Operator and the Non-Participant FTR Customers fall below
100 percent (100%) of its Credit Test Amount and, in the case of voting on
matters before the Participants Committee or any Technical Committee, such
Non-Municipal Participant's outstanding obligations to NEPOOL, the System
Operator and the Non-Participant FTR Customers fall and remain below 100
percent (100%) of its Credit Test Amount at least three (3) Business Days
prior to any such vote, or (y) in the case of activity in the NEPOOL
Market, the scheduling and receipt of transmission service and entering
future transactions in the FTR system, such Non-Municipal Participant has
provided additional financial assurance (in addition to any other
financial assurance required of such Non-Municipal Participant hereunder)
equal to three and one-half (3.5) times the amount by which such Non-
Municipal Participant's outstanding obligations to NEPOOL, the System
Operator and the Non-Participant FTR Customers exceed 100 percent (100%)
of its Credit Test Amount (the "Excess Financial Assurance") and, in the
case of voting on matters before the Participants Committee or any
Technical Committee, such Non-Municipal Participant has provided Excess
Financial Assurance at least three (3) Business Days prior to any such
vote; provided, however, (i) any suspension of a Non-Municipal
Participant's authority to vote on matters before the Participants
Committee or any Technical Committee hereunder shall not be effective
while an appeal of such suspension is pending; (ii) if any Non-Municipal
Participant reaches 100 percent (100%) of its Credit Test Amount solely
because its rating, the rating of its outstanding debt or the rating of
its Guarantor (as hereinafter defined) or its Guarantor's outstanding debt
is downgraded by one grade, then (x) for 10 Business Days after such
downgrade, such Non-Municipal Participant's Credit Test Amount shall
remain the same as it was immediately preceding such downgrade and (y)
no notice shall be sent and no suspension shall occur with respect to such
downgrade if such Non-Municipal Participant cures such default within such
10 Business Day period; (iii) if any Non-Municipal Participant reaches
100 percent (100%) of its Credit Test Amount solely because the rating of
the bank issuing a letter of credit on its behalf hereunder is downgraded
below the requisite corporate debt rating, then (x) for 10 Business Days
after such downgrade, such Non-Municipal Participant's Credit Test Amount
shall remain the same as it was immediately preceding such downgrade,
and (y) no notice shall be sent and no suspension shall occur with
respect to such downgrade if such Non-Municipal Participant cures such
default within such 10 Business Day period; and (iv) if any Non-Municipal
Participant reaches 100 percent (100%) of its Credit Test Amount and such
Non-Municipal Participant has not previously received notice from the
System Operator that its aggregate outstanding obligations to NEPOOL, the
System Operator and the Non-Participant FTR Customers equal 80 percent
(80%) or 90 percent (90%) of its Credit Test Amount with respect to that
same event, then the System Operator will inform such Non-Municipal
Participant of its impending suspension by telephone by 10 a.m. on the
day (the "Notice Day") following the day on which its aggregate
outstanding obligations to NEPOOL, the System Operator and the Non-
Participant FTR Customers reached 100 percent (100%) of its Credit Test
Amount, and such Non-Municipal Participant shall not be suspended with
respect to that event only if either (a) its outstanding obligations to
NEPOOL, the System Operator and the Non-Participant FTR Customers fall
below 100 percent (100%) of its Credit Test Amount by 12:00 noon on the
first Business Day immediately following the Notice Day or (b) it provides
the System Operator with the requisite Excess Financial Assurance
required by this Policy by 12:00 noon on the first Business Day
immediately following the Notice Day.
The suspension of a Non-Municipal Participant, and any resulting annulment, termination or removal of OASIS reservations, removal from the settlement system and the FTR system and forfeiture of FTRs, shall not limit, in any way, NEPOOL's or the System Operator's right to invoice or collect payment for any amounts owed (whether such amounts are due or becoming due) by such suspended Non-Municipal Participant under the Agreement, the Tariff or the System Operator's tariff.
In addition to the notices provided herein, the System Operator will provide any additional information required under the Information Policy.
Each notice issued by the System Operator when a Non-Municipal Participant's aggregate outstanding obligations to NEPOOL, the System Operator and the Non-Participant FTR Customers equal 90 percent (90%) and 100 percent (100%) of that Non-Municipal Participant's Credit Test Amount shall indicate whether such Non-Municipal Participant has a registered load asset. If the System Operator has issued a notice that a Non- Municipal Participant's aggregate outstanding obligations to NEPOOL and the System Operator equal 90 percent (90%) or 100 percent (100%) of that Non-Municipal Participant's Credit Test Amount and subsequently such Non-Municipal Participant's aggregate outstanding obligations fall below the applicable percentage of its Credit Test Amount, such Non- Municipal Participant may request the System Operator to issue a notice stating such fact; provided, however, that the System Operator shall not be obligated to issue such notice unless, in its sole discretion, the System Operator concludes that such Non-Municipal Participant's aggregate outstanding obligations have in fact fallen below the applicable percentage of its Credit Test Amount.
1.7 Amendment to Section II.D of the Member Financial Assurance Policy. The first paragraph of Section II.D of the Member Financial Assurance Policy is amended to read as follows:
All Non-Municipal Applicants and Non-Municipal Participants that must provide (or choose to provide) additional financial assurance pursuant to this Section II, must provide NEPOOL with financial assurance in the form and in the amount described in Sections II, IV and VI hereof. Each financial assurance for monthly charges, unless replaced in accordance with the terms hereof or no longer required pursuant to the terms hereof, shall remain in effect until the later of (a) 120 days after termination of the Non-Municipal Participant's membership or (b) the end date of all FTRs awarded to the Non-Municipal Participant and the final satisfaction of all obligations of the Non- Municipal Participant providing that financial assurance; provided, however that financial assurances required by this Policy related to potential billing adjustments chargeable to a terminated Non-Municipal Participant shall remain in effect until such billing adjustment request is finally resolved in accordance with the provisions of the NEPOOL Billing Policy.
1.8 Amendment to Section II.D of the Member Financial Assurance Policy. The following is added after the third paragraph of Section II.D of the Member Financial Assurance Policy:
Furthermore and without limiting the generality of the foregoing, any Non-Municipal Participant that is so required under Section VI of this Policy shall provide additional financial assurance in connection with FTR transactions, as set forth in such Section VI.
1.9 Amendment to Section II.E of the Member Financial Assurance Policy. The following is added at the end of Section II.E of the Member Financial Assurance Policy:
If a Non-Municipal Participant is suspended from entering into future transactions in the FTR system and such suspension occurs at any time during an ongoing FTR Auction, then unless such Non-Municipal Participant cures the default(s) providing the basis for such suspension prior to 4:00 p.m. on the Business Day immediately preceding the close of the next FTR Auction, all FTRs held by such Non-Municipal Participant (the "Default FTRs") shall be offered in the next FTR Auction, with an offer price of $0. If a Non-Municipal Participant is suspended from entering into future transactions in the FTR System and such suspension occurs at any time other than during an ongoing FTR Auction, then unless such Non- Municipal Participant cures the default(s) providing the basis for such suspension prior to 4:00 p.m. on the Business Day immediately preceding the close of the next FTR Auction, all Default FTRs held by such Non-Municipal Participant shall be offered in that next FTR Auction, with an offer price of $0. All Default FTRs that are offered in an FTR Auction and have a positive value in that FTR Auction shall be forfeited by such Non-Municipal Participant and will be sold at the applicable clearing price in that FTR Auction. The proceeds from the sale of those Default FTRs will first be used to satisfy all obligations of such Non-Municipal Participant to NEPOOL, the System Operator and the Non-Participant FTR Customers, and any amount remaining after all such obligations have been satisfied shall be paid over to such Non-Municipal Participant that formerly owned such Default FTRs. All Default FTRs that are offered in an FTR Auction and have a negative value in that FTR Auction will be retained by such Non-Municipal Participant, and such Non-Municipal Participant will remain subject to all of the requirements, including the requirements hereunder, with respect to such Default FTRs retained by it.
1.10 Amendment to Section III.D of the Member Financial Assurance Policy. The second sentence of Section III.D of the Member Financial Assurance Policy is amended to read as follows:
Each financial assurance for NEPOOL Charges, unless replaced in accordance with the terms hereof or no longer required pursuant to the terms hereof, shall remain in effect until the later of (a) 120 days after termination of the Municipal Participant's membership or (b) the end date of all FTRs awarded to the Municipal Participant and the final satisfaction of all obligations of the Municipal Participant providing that financial assurance; provided, however that financial assurances required by this Policy related to potential billing adjustments chargeable to a terminated Municipal Participant shall remain in effect until such billing adjustment request is finally resolved in accordance with the provisions of the NEPOOL Billing Policy.
1.11 Amendment to Section III.D of the Member Financial Assurance Policy. The following is inserted after the fourth sentence (which is in parentheses) of the third paragraph of Section III.D of the Member Financial Assurance Policy:
Furthermore and without limiting the generality of the foregoing, any Municipal Participant that is so required under Section VI of this Policy shall provide additional financial assurance in connection with FTR transactions, as set forth in such Section VI.
1.12 Amendment to Section III.D of the Member Financial Assurance Policy. Clause (ii) of the third paragraph of Section III.D of the Member Financial Assurance Policy is amended to read as follows:
(ii) 20 percent (20%) of the total amount due and owing at such time to the System Operator, the Participants, the Non-Participant Transmission Customers and the Non-Participant FTR Customers by all Participants, Non-Participant Transmission Customers and Non-Participant FTR Customers.
1.13 Amendment to Section IV.D of the Member Financial Assurance Policy. Clause (ii) of the first paragraph of Section IV.D of the Member Financial Assurance Policy is amended to read as follows:
(ii) 20 percent (20%) of the total amount due and owing at such time to the System Operator, the Participants, the Non-Participant Transmission Customers and the Non-Participant FTR Customers by all Participants, Non-Participant Transmission Customers and Non-Participant FTR Customers.
1.14 Amendment to Section V.E of the Member Financial Assurance Policy.
Section V.E of the Member Financial Assurance Policy is amended to
read as follows:
Upon termination of membership in NEPOOL, a Participant must provide financial assurance in the amount of all potential billing adjustments chargeable to such Participant for all unresolved billing disputes in existence on the date of termination of such Participant's membership and the amount required with respect to any FTRs awarded to such Participant and any other remaining obligations of such Participant. Such financial assurance must be in the form of a cash deposit, letter of credit, payment bond or Corporate Guaranty meeting the requirements of this Policy. The amount of such financial assurance shall be reduced to the extent any billing dispute is resolved and the former Participant pays the billing adjustments or no billing adjustment is chargeable to the former Participant, to the extent that any FTR awarded to such Participant expires and to the extent that any remaining obligations of such Participant are otherwise satisfied.
1.15 Addition of Section VI to the Member Financial Assurance Policy.
Section VI is added to the Member Financial Assurance Policy, immediately
after Section V and before the attachments to the Member Financial
Assurance Policy, reading as follows:
VI. ADDITIONAL FINANCIAL ASSURANCE PROVISIONS FOR FTR TRANSACTIONS
This Section VI of this Policy contains the financial assurance
requirements and procedures for Non-Municipal Participants and Municipal
Participants that transact in the FTR Auction and/or Secondary FTR Market
(collectively, the "FTR Markets"). In addition to the other financial
assurance requirements found in this Policy, Participants transacting
in the FTR Markets which, after taking such FTR transactions into account,
must provide NEPOOL with additional financial assurance hereunder, shall
provide such additional financial assurance as described in this Section
VI. Governance Only Members transacting in the FTR Markets are required
to comply with the requirements of this Section VI and to provide
additional financial assurance in the amounts required for Non-Municipal
Participants or Municipal Participants, as applicable, to the extent that
such transactions cause their average monthly NEPOOL Charges to
exceed $15,000.
A. FTR Applicants
Each Participant that is otherwise required to provide additional financial assurance under this Policy must have provided to the System Operator at the time of its application for FTR system access, financial assurance, in the form and amount required by this Policy; provided, however, in order to obtain access to the FTR system, such a Participant shall have provided at least $500,000 of cumulative financial assurance with its application for FTR system access. For purposes of determining whether an applicant for access to the FTR system has provided at least $500,000 of cumulative financial assurance, the System Operator shall include in such calculation the amount of any financial assurance provided by such applicant pursuant to any other provision of this Policy.
B. Bidding into the FTR Auction
If a Participant that is required to provide additional financial assurance under this Policy submits a bid into an FTR Auction, that Participant must provide, in addition to all other financial assurance required hereunder, additional financial assurance, in the form required by this Policy and in an amount that is at least equal to the total dollar amount of the bids submitted by such Participant in such FTR Auction at the time such FTR Auction closes (the "Bid Financial Assurance"). Moreover, a Participant that is required to provide financial assurance under this Policy must maintain, at all times, in addition to the financial assurance otherwise required hereunder, financial assurance, in the form required hereunder, in an amount that is at least equal to the total dollar amount of any awarded bids in any FTR Auctions (the "Award Financial Assurance"). Once a bid in an FTR Auction is awarded, the Bid Financial Assurance that relates to such bid will be converted to the Award Financial Assurance relating to such awarded bid. The required amount of the Award Financial Assurance will be based on the amount of the awarded bid, not the amount initially bid.
If a Participant does not have the total amount of required additional financial assurance in place at the time an FTR Auction into which it has bid closes, then, in addition to the other consequences described in this Policy, all bids submitted by that Participant for that FTR Auction will be rejected. The Participant will be allowed to participate in the next FTR Auction held provided it meets all requirements for such participation, including without limitation those set forth herein. Each Participant must maintain the requisite additional financial assurance for the duration of the FTRs awarded to it. The amount of any additional financial assurance provided by a Participant in connection with an unsuccessful bid which, as a result of such bid being unsuccessful, is in excess of the total amount of additional financial assurance required from such Participant under this Policy will be held by the System Operator and will be applied against future bids and awards by that Participant unless that Participant requests in writing to have such excess financial assurance returned to it. Prior to returning any financial assurance to a Participant, the System Operator shall use such financial assurance to satisfy any overdue obligations of that Participant. The System Operator shall only return to that Participant the balance of such financial assurance after all such overdue obligations have been satisfied.
SECTION 2 AMENDMENTS TO NON-MEMBER FINANCIAL ASSURANCE POLICY
2.1 Amendment to Section I.A.1 of the Non-Member Financial Assurance Policy.
Section I.A.1 of the Financial Assurance Policy for NEPOOL Non-Participant
Transmission Customers, included as Attachment M to the NEPOOL Tariff, as
amended by the Eighty-Third Agreement (the "Non-Member Financial Assurance
Policy"), is amended by deleting from the second sentence of the second
paragraph the following text: "as well as a lien search for such
Non-Participant Applicant."
2.2 Amendment to Section I.A.2 of the Non-Member Financial Assurance Policy.
Section I.A.2 of the Non-Member Policy is amended by deleting the third
sentence.
SECTION 3 AMENDMENTS TO BILLING POLICY
3.1 Change to References in Billing Policy. In the New England Power Pool
Billing Policy, included as Attachment N to the NEPOOL Tariff, as amended
by the Eighty-Third Agreement (the "Billing Policy"), the reference in
Section 1.1 to "NEPOOL Participants and Non-Participant Transmission
Customers" is changed to "NEPOOL Participants, Non-Participant
Transmission Customers and Non-Participants that transact in the FTR
Auction and/or Secondary FTR Market ("Non-Participant FTR Customers")."
Except as noted herein, each subsequent reference to "Participants and
Non-Participant Transmission Customers" is changed to "Participants, Non-
Participant Transmission Customers and Non-Participant FTR Customers;"
each reference to "each Participant and Non-Participant Transmission
Customer" is changed to "each Participant, Non-Participant Transmission
Customer and Non-Participant FTR Customer;" each reference to "Participant
or Non-Participant Transmission Customer" is changed to "Participant,
Non-Participant Transmission Customer or Non-Participant FTR Customer;"
each reference to "Participants or Non-Participant Transmission Customers"
is changed to "Participants, Non-Participant Transmission Customers or
Non-Participant FTR Customers;" and each reference to "Participant's or
Non-Participant Transmission Customer's" is changed to "Participant's,
Non-Participant Transmission Customer's or Non-Participant FTR
Customer's." None of such reference changes shall be made to Section 4
of the Billing Policy.
3.2 Amendment to Section 1.3 of the Billing Policy. Clause (i) of Section 1.3 of the Billing Policy is amended to read as follows:
(i) Participants and Non-Participant Transmission Customers who have requested and received a weekly billing schedule in accordance with the Financial Assurance Policy for NEPOOL Members and the Financial Assurance Policy for NEPOOL Non-Participant Transmission Customers (collectively, together with the Financial Assurance Policy for Non- Participant FTR Customers, the "Financial Assurance Policies") and
3.3 Amendment to Section 3.1(d) of the Billing Policy. The third and fourth sentences of the second paragraph of Section 3.1(d) of the Billing Policy is amended to read as follows:
To the extent that the amount in dispute would be payable to one or more identifiable Participants or Non-Participant FTR Customers (but not to the ISO), then the amount due to each such Participant or Non-Participant FTR Customer in the billing period to which such dispute relates shall be reduced by the portion of the total amount in dispute that would be payable to such Participant or Non-Participant FTR Customer, subject to payment with interest accrued thereon if and when the dispute is resolved in favor of such Participant(s) or Non-Participant FTR Customer(s). To the extent that amount in dispute would be payable to the ISO, or the specific Participant(s) or Non-Participant FTR Customer(s) to which such amount would be payable cannot be identified, then the shortfall of funds available to pay Remittance Advices resulting from the amount in dispute being held in an escrow account shall be allocated among the Participants and Non-Participant FTR Customers according to the two-step allocation process described in Section 3.3.(f) below, subject to payment to all Participants and Non-Participant FTR Customers being allocated a portion of the shortfall, with applicable interest (if any), once the dispute is resolved with the funds in such escrow account or with other amounts provided by the Participant or Non-Participant Transmission Customer losing such dispute.
3.4 Amendment to Section 3.3(e) of the Billing Policy. The second and third sentences of Section 3.3(e) of the Billing Policy is amended to read as follows:
Amounts withdrawn from the Late Payment Account and applied toward any shortfall resulting from the Default Amount shall not relieve the defaulting Participant, defaulting Non-Participant Transmission Customer or defaulting Non-Participant FTR Customer of its obligation to pay such Default Amount. If and to the extent that such Default Amount, interest thereon and/or late charges with respect thereto are subsequently collected (including as a result of the use of a financial assurance under the Financial Assurance Policies or through actions or proceedings against the defaulting Participant, Non-Participant Transmission Customer or Non- Participant FTR Customer), such amounts shall first be used to pay Participants and Non-Participant FTR Customers for the amount of such Default Amount allocated to them under clause (f) below, with interest thereon, and then, after all such amounts have been paid to the Participants and Non-Participant FTR Customers, such Default Amount, interest and/or late charges shall be deposited into the Late Payment Account in accordance with the provisions of the Financial Assurance Policy for NEPOOL Members that are applicable to late payment charges.
3.5 Amendment to Section 3.3(f) of the Billing Policy. Section 3.3(f) of the Billing Policy is amended to read as follows:
f) Reduction of Payments and Increases in Charges. (i) If and to the extent that the procedures described in clauses (b), (c), (d) and (e) above do not yield sufficient funds to pay all Remittance Advice amounts in full (after payment of amounts due to the ISO and to the entity or entities that develop, administer, operate and maintain the GIS for those services, in accordance with clause (a) above) on the date such Payments are due, the ISO shall reduce Payments to those Participants and Non- Participant FTR Customers owed monies for that billing period (the "Default Period"), pro rata based on the amounts owed to such Participants and Non-Participant FTR Customers, to the extent necessary to clear its accounts by the close of banking business on the date such Payments are due. As funds attributable to a Default Amount are received by the ISO (including amounts received through financial assurances provided under the Financial Assurance Policies or through actions or proceedings commenced against the defaulting Participant, Non-Participant Transmission Customer or Non-Participant FTR Customer) prior to the next billing period's Statements being distributed, such funds, together with any interest and late charges collected on the applicable Default Amount, shall be distributed pro rata to the Participants and Non-Participant FTR Customers that did not receive the full amount of their Payments as a result of such Default Amount not being paid, up to the full amount that such Participants and Non-Participant FTR Customers did not receive as a result of such Default Amount not being paid, with interest thereon.
(ii) To the extent that any amount remains unpaid to Participants and Non-
Participant FTR Customers on the date that Statements are distributed to
Participants and Non-Participant FTR Customers in the billing period
immediately following the Default Period, the Default Amount remaining
unpaid shall be reallocated among all of the Participants and Non-
Participant FTR Customers receiving Statements for the Default Period
(other than the Participant, Non-Participant Transmission Customer or
Non-Participant FTR Customer defaulting on its payment obligations),
pro rata based, for each Participant and Non-Participant FTR Customer
being allocated a share of the Default Amount remaining unpaid, on the
sum of (i) all Charges due from such Participant or Non-Participant FTR
Customer that are reflected on its Statement for the Default Period and
(ii) all Payments due to such Participant or Non-Participant FTR
Customer that are reflected on its Statement for the Default Period,
without giving any effect to the process of netting Charges against
Payments on each Statement that is the result of the ISO's single billing
system. Thus, by way of example, a Participant or Non-Participant FTR
Customer with $2,000 of Charges and no Payments on its Statement for the
Default Period and a Participant or Non-Participant FTR Customer with
$1,000 of Charges and $1,000 of Payments on its Statement for the Default
Period would be allocated an equal share of the unpaid Default Amount
under this clause (f)(ii). Each Participant and Non-Participant FTR
Customer that received a Statement for the Default Period shall have
the amount of its Invoice or Remittance Advice in the billing period
immediately following the Default Period adjusted as necessary to reflect
its obligation for the Default Amount remaining unpaid under this clause
(f)(ii). As funds attributable to a Default Amount are received by
the ISO (including amounts received through financial assurances provided
under the Financial Assurance Policies or through actions or proceedings
commenced against the defaulting Participant, Non-Participant Transmission
Customer or Non-Participant FTR Customer) after such adjusted Statements
are distributed, such funds, together with any interest and late charges
collected on the applicable Default Amount, shall be distributed to the
Participants and Non-Participant FTR Customers pro rata based on their
allocation of the Default Amount under this clause (f)(ii), up to the
full amount of such Default Amount allocated to each such Participant or
Non-Participant FTR Customer, with interest thereon.
3.6 Amendment to Section 3.3(j) of the Billing Policy. Section 3.3(j) of the Billing Policy is amended to read as follows:
j) Notice and Suspension. Without limiting any of the other remedies described above, in the event that the ISO, in its reasonable opinion, believes that all or any part of any amount due to be paid by any Participant, any Non-Participant Transmission Customer or any Non- Participant FTR Customer will not be or has not been paid when due (a "Payment Default"), the ISO (on its own behalf or on behalf of NEPOOL) may (but shall not be required to) notify such Participant, Non- Participant Transmission Customer or Non-Participant FTR Customer in writing, electronically and by first class mail sent in each case to such Participant's member or alternate on the Participants Committee or billing contact (it being understood that the ISO will use reasonable efforts to contact all three) or such Non-Participant Transmission Customer's or Non-Participant FTR Customer's billing contact, of such Payment Default. If a Payment Default is not cured within five days after when such payment was originally due, the ISO shall notify each member and alternate on the NEPOOL Participants Committee, each Participant's billing contact and each of the New England governors and utility regulatory agencies of (i) the identity of the Participant, Non-Participant Transmission Customer or Non- Participant FTR Customer receiving such notice, (ii) whether such notice relates to a Payment Default, (iii) whether the defaulting Participant has a registered load asset, and (iv) the actions the ISO plans to take and/or has taken in response to such Payment Default. In addition, the ISO will provide any additional information with respect to such Payment Default as may be required under the Information Policy. If a Payment Default is not cured within ten days after when such payment was originally due, the defaulting Participant, Non-Participant Transmission Customer or Non-Participant FTR Customer shall be suspended (if applicable) from: (a) the NEPOOL Market; (b) receiving transmission service under any existing or pending arrangement under the Tariff or scheduling any future transmission service under the Tariff; (c) voting on matters before the Participants Committee or any Technical Committee; and (d) entering into any future transactions in the FTR system, in each case until (x) in the case of activity in the NEPOOL Market, the scheduling and receipt of transmission services and entering future transactions in the FTR system, such Payment Default has been cured in full, and (y) in the case of voting on matters before the Participants Committee or any Technical Committee, such Payment Default has been cured in full at least three Business Days prior to such vote; provided, however, that any suspension of a Participant's authority to vote on matters before the Participants Committee or any Technical Committee hereunder shall not be effective while an appeal of such suspension is pending. The suspension of a Participant, a Non- Participant Transmission Customer or a Non-Participant FTR Customer, and any resulting annulment, termination or removal of OASIS reservations, removal from the settlement system and the FTR system and forfeiture of FTRs, shall not limit, in any way, NEPOOL's or the ISO's right to invoice or collect payment for any amounts owed (whether such amounts are due or becoming due) by such Participant, Non-Participant Transmission Customer or Non-Participant FTR Customer under the Documents. If the ISO has issued a notice that a Participant, a Non-Participant Transmission Customer or a Non-Participant FTR Customer has defaulted on a payment obligation and that Participant, Non-Participant Transmission Customer or Non-Participant FTR Customer subsequently cures that Payment Default, such Participant, Non-Participant Transmission Customer or Non- Participant FTR Customer may request the ISO to issue a notice stating such fact; provided, however, that the ISO shall not be required to issue that notice unless, in its sole discretion, the ISO determines that such Payment Default has been cured. If a Participant, a Non-Participant Transmission Customer or a Non-Participant FTR Customer is suspended in accordance with this Section 3.3(j), the provisions of this Section 3.3(j) shall control notwithstanding any other provision of the Market Rules, the NEPOOL Agreement or the NEPOOL Tariff to the contrary.
A suspended Participant shall have no ability so long as it is suspended to be reflected in the ISO's settlement system as either a purchaser or a seller of any Market Products under any Bilateral Transactions. Any Bilateral Transactions with a suspended Participant shall be deemed to be terminated for purposes of the ISO's settlement system. If a suspended Participant has the obligation under applicable Market Rules to bid any of its Entitlements to provide Market Products under the NEPOOL Agreement, that obligation shall continue notwithstanding the Participant's suspension and any transfers of Market Products occurring under the NEPOOL Agreement as a result of any such bid shall be effective. If a suspended Participant or Non-Participant Transmission Customer is receiving transmission or ancillary services under the NEPOOL Tariff, all such services shall be terminated as of the date of the suspension, except to the extent required (if at all) for the Interchange Transactions resulting from the bids of the suspended Participant. Except to the extent required (if at all) for the Interchange Transactions resulting from the bids of the suspended Participant, any approved reservations reflected in OASIS shall be annulled, any pending reservations shall be retracted, and the suspended Participant or Non-Participant Transmission Customer shall have no ability so long as it is suspended to make new reservations on OASIS. If a Participant or a Non-Participant FTR Customer is suspended from entering into future transactions in the FTR system and such suspension occurs at any time during an on- going FTR Auction, then unless such Participant or Non-Participant FTR Customer cures the default(s) providing the basis for such suspension prior to 4:00 p.m. on the Business Day immediately preceding the close of the next FTR Auction, all FTRs held by such Participant or Non- Participant FTR Customer (the "Default FTRs") shall be offered in the next FTR Auction, with an offer price of $0. If a Participant or Non- Participant FTR Customer is suspended from entering into future transactions in the FTR system and such suspension occurs at any time other than during an ongoing FTR Auction, then unless such Participant or Non-Participant FTR Customer cures the default(s) providing the basis for such suspension prior to 4:00 p.m. on the Business Day immediately preceding the close of the next FTR Auction, all Default FTRs held by such Participant or Non-Participant FTR Customer shall be offered in that next FTR Auction, with an offer price of $0. All Default FTRs that are offered in an FTR Auction and have a positive value in that FTR Auction shall be forfeited by such Participant or Non-Participant FTR Customer and will be sold at the applicable clearing price in that FTR Auction. The proceeds from the sale of those Default FTRs will first be used to satisfy all obligations of such Participant or Non-Participant FTR Customer to NEPOOL, the System Operator and the Non-Participant FTR Customers, and any amount remaining after all such obligations have been satisfied shall be paid over to such Participant or Non-Participant FTR Customer that formerly owned such Default FTRs. All Default FTRs that are offered in an FTR Auction and have a negative value in that FTR Auction will be retained by such Participant or Non-Participant FTR Customer, and such Participant or Non-Participant FTR Customer will remain subject to all of the requirements, including the requirements hereunder, with respect to such Default FTRs retained by it.
3.7 Addition of Section 4.5 to the Billing Policy. The following new section is added to the end of Section 4 of the Billing Policy:
Section 4.5 - Non-Participant FTR Customers. Non-Participant FTR Customers are not eligible for weekly billing arrangements.
3.8 Amendment to Section 5.5(c) of the Billing Policy. In the first sentence of Section 5.5(c) of the Billing Policy, the reference to "Participants, Non-Participant Transmission Customers" is changed to "Participants, Non-Participant Transmission Customers, Non-Participant FTR Customers."
SECTION 4 MISCELLANEOUS
4.1 This Eighty-Seventh Agreement shall become effective on September 16, 2002, or on such other date as the Commission shall provide that the amendments reflected herein shall become effective.
4.2 Terms used in this Eighty-Seventh Agreement that are not defined herein shall have the meanings ascribed to them in the NEPOOL Agreement.
<FN1> For purposes of the amount in clause (ii) for any Corporate Guaranty, such amount shall be the lesser of the unused portion of any stated limit in such Corporate Guaranty (where such a limit is stated) divided by three and one-half (3.5) or the Guarantor's Credit Limit or Guaranty Limit (each as defined below), as applicable, which Credit Limit or Guaranty Limit shall not be divided by three and one-half (3.5).
Exhibit 10.25.18
EIGHTY-EIGHTH AGREEMENT AMENDING
NEW ENGLAND POWER POOL AGREEMENT
(SCHEDULE 16 AMENDMENT)
THIS EIGHTY-EIGHTH AGREEMENT AMENDING NEW ENGLAND POWER POOL AGREEMENT, dated as of October 4, 2002 ("Eighty-Eighth Agreement"), amends the New England Power Pool Agreement (the "NEPOOL Agreement"), as amended.
WHEREAS, the NEPOOL Agreement as in effect on December 1, 1996 was amended and restated by the Thirty-Third Agreement Amending the New England Power Pool Agreement dated as of December 1, 1996 (the "Thirty-Third Agreement") in the form of the Restated New England Power Pool Agreement ("Restated NEPOOL Agreement") attached to the Thirty-Third Agreement as Exhibit A thereto, and the Thirty-Third Agreement also provided for the NEPOOL Open Access Transmission Tariff (the "NEPOOL Tariff") which is Attachment B to the Restated NEPOOL Agreement; and
WHEREAS, the Restated NEPOOL Agreement and the NEPOOL Tariff have subsequently been amended numerous times, the most recent amendment dated as of June 21, 2002; and
WHEREAS, the Participants desire to amend the Restated NEPOOL Agreement, including the NEPOOL Tariff, as heretofore amended, to reflect the revisions detailed herein.
NOW, THEREFORE, upon approval of this Eighty-Eighth Agreement by the NEPOOL Participants Committee in accordance with the procedures set forth in the NEPOOL Agreement, the Participants agree as follows:
SECTION 1 AMENDMENTS TO NEPOOL TARIFF
1.1 Schedule 16 to the NEPOOL Tariff is amended to read as set forth in Attachment A hereto.
SECTION 2 MISCELLANEOUS
2.1 This Eighty-Eighth Agreement shall become effective on January 1, 2003, or on such other date as the Commission shall provide that the amendments reflected herein shall become effective.
2.2 Terms used in this Eighty-Eighth Agreement that are not defined herein shall have the meanings ascribed to them in the NEPOOL Agreement.
Attachment A
SCHEDULE 16
System Restoration and Planning Service from Generators
System Restoration and Planning Service is necessary to ensure the continued reliable operation of the New England Transmission System. System Restoration and Planning Service enables the System Operator to designate specific generators interconnected to the transmission or distribution system at strategic locations capable of supplying load to re-energize the transmission system following a system-wide blackout. These designated generators are able to start without an outside electrical supply and are otherwise known as "Black Start Capable." The planning and maintenance of adequate capability for restoration of the NEPOOL Control Area following a blackout represents a benefit to all entities using the power system. Therefore, this service must be taken from the System Operator. In contrast to the System Restoration and Planning Service described herein, the actual supply of power that would allow a power producer to restart its own generating units may itself be self-supplied or purchased from another power producer independent of the NEPOOL Control Area arrangements formulated by the System Operator. The Black Start Capability intrinsic of System Restoration and Planning Service is to be provided by designated Participants through the System Operator.
I. Rate Formulas
A Transmission Customer Purchasing either Regional Network Service under Schedule 9 of this Agreement or Internal Point to Point Service under Schedule 10 of this Agreement, or a Transmission Customer making Unauthorized Use shall be required to pay NEPOOL for its share of Black Start Restoration and Planning Service ("Black Start Responsibility") as determined in accordance with the following formulas:
MRSR = (1/12) times 1 divided by the sum of (NL + IPP + UAU) times (C)
Where:
MRSR = The Transmission Customers' Monthly Restoration Service Rate.
NL = The aggregate of the individual sums of each Participant's or
Non-Participant's Network Load for the billing month.
IPP = The aggregate of the individual sums of each Participant's or
Non-Participant's maximum Reserved Capacity for Internal
Point-to-Point Service for each load served within a Local
Network or Network(s) during the billing month.
UAU = The aggregate of the individual sums of each Participant's or
Non-Participant's Maximum Unauthorized Use associated with
Internal Point-to-Point Service for each load served within a
Local Network or Network(s) during the month.
C = The sum of Ci for that month for each Black Start Generator, as
defined in Section II below.
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Each individual Participant's or Non-Participant's charge in any billing month would be calculated by the following formula:
MC = (MRSR)(NLi + IPPi + UAUi)
Where
MC = The Monthly Charge.
NLi = The sum of a Participant's or Non-Participant's Network Load for
the billing month.
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IPPi = The sum of a Participant's or Non-Participant's maximum Reserved Capacity for Internal Point-to-Point Service for each load served within a Local Network or Network(s) during the billing month.
UAUi = The sum of a Participant's or Non-Participant's Maximum Unauthorized Use associated with Internal Point-to-Point Service for each load served within a Local Network or Network(s) during the month.
A separate charge for this service based upon the above rates will be added to the Transmission Customer's monthly bill.
II. Compensation to Generators
A. Eligibility. In order to be designated as a "Black Start Generator" providing System Restoration Service and to be eligible for compensation under this Schedule 16 of the NEPOOL Open Access Transmission Tariff, a generator must meet the following criteria:
1. The unit is "Black Start Capable" in that it has the ability of being started without energy from other NEPOOL generating units in such a way that it meets all of the requirements stated in Operating Procedure 11 (Black Start Capability Eligibility & Testing Requirements); and
2. The unit owner, NEPOOL, and the System Operator agree that the unit should be designated Black Start Capable and accordingly is listed as a Black Start unit in Operating Procedure 11.
Each generator which is eligible for and seeks compensation under the NEPOOL Open Access Transmission Tariff for providing System Restoration Service shall execute an agreement with NEPOOL incorporating the terms and conditions of service set forth in this Schedule 16.
B. Compensation. A Black Start Generator shall be entitled to compensation in a month based on the following formula:
Ci = ($Y/kw-yr/12) x (the unit's Monthly Claimed Capability for that month)
Where "Y" = $3.75 for the period from the effective date as determined by the Commission through and including December 31, 2003; $4.00 for calendar year 2004, $4.25 for calendar year 2005; and $4.50 for calendar year 2006 and thereafter.
C. Terms and Conditions of Service
1. Generator Owner's commitment to provide System Restoration and Planning Service:
A. Generators need to commit initially for at least three years to provide System Restoration and Planning Service from the date of the last black-start/system restoration study. The most recent study was conducted in October 1998.
B. All succeeding commitments must be at least for three years.
C. Generators may, and are encouraged to, commit to provide System Restoration and Planning Service for periods greater than three years with System Operator and NEPOOL concurrence.
D. Generators need to give at least one-year notice that they will no longer be able to provide System Restoration and Planning Service. This one-year notice cannot truncate the generator's commitment to provide System Restoration and Planning Service except as noted in item 1(E) or 1(F) below.
E. If due to an event of Force Majeure a Generator Owner cannot provide System Restoration and Planning Service, the above notification requirements stated in items 1(A) and 1(B) are not binding.
F. If an owner of a generation unit that is designated Black Start Capable decides to retire that unit, then the three year requirement to provide System Restoration and Planning Service from that unit is not binding. The one-year notice, however, is binding.
2. Performance obligations of generators that are providing System Restoration and Planning Service:
A. Generators that are providing System Restoration and Planning Service will be tested in accordance with Operating Procedure 11 or its successor, which may be revised from time to time.
B. Units that are providing System Restoration and Planning Service must start-up within the prescribed time stipulated in Operating Procedure 11 (Black Start Capability Eligibility & Testing Requirements). Not all unmanned units that are providing System Restoration and Planning Service will be asked to start-up at the same time.
C. If a unit fails a System Restoration and Planning Service test, the owner must incur the necessary costs to make that unit capable of passing the test within a reasonable amount of time. Until the unit passes another System Restoration and Planning Service test, it would not be compensated for providing System Restoration and Planning Service. All costs associated with System Restoration and Planning Service unit re-tests are at the owner's expense.
3. Obligations by System Operator and NEPOOL to generators that are providing System Restoration and Planning Service:
A. Generators that commit to provide System Restoration and Planning Service will not have their Black Start Capable designation terminated within the time period of their commitment.
B. The System Operator and NEPOOL must provide at least one-year notice to the owner or owners of generation units that are providing System Restoration and Planning Service prior to terminating that unit's designation as Black Start Capable.
C. There are no additional restrictions on generation maintenance of designated Black Start Capable units beyond what exists for non-Black Start units except that designated Black Start generation units cannot take seasonal outages.
Exhibit 10.25.19
EIGHTY-NINTH AGREEMENT AMENDING
NEW ENGLAND POWER POOL AGREEMENT
(TECHNICAL COMMITTEE VOTING CHANGES)
THIS EIGHTY-NINTH AGREEMENT AMENDING NEW ENGLAND POWER POOL AGREEMENT, dated as of October 4, 2002 ("Eighty-Ninth Agreement"), amends the New England Power Pool Agreement (the "NEPOOL Agreement"), as amended.
WHEREAS, the NEPOOL Agreement as in effect on December 1, 1996 was amended and restated by the Thirty-Third Agreement Amending the New England Power Pool Agreement dated as of December 1, 1996 (the "Thirty-Third Agreement") in the form of the Restated New England Power Pool Agreement ("Restated NEPOOL Agreement") attached to the Thirty-Third Agreement as Exhibit A thereto, and the Thirty-Third Agreement also provided for the NEPOOL Open Access Transmission Tariff (the "NEPOOL Tariff") which is Attachment B to the Restated NEPOOL Agreement; and
WHEREAS, the Restated NEPOOL Agreement and the NEPOOL Tariff have subsequently been amended numerous times, the most recent amendment dated as of June 21, 2002; and
WHEREAS, the Participants desire to amend the Restated NEPOOL Agreement, as heretofore amended, to reflect the revisions detailed herein.
NOW, THEREFORE, upon approval of this Eighty-Ninth Agreement by the NEPOOL Participants Committee in accordance with the procedures set forth in the NEPOOL Agreement, the Participants agree as follows:
SECTION 1 AMENDMENTS TO RESTATED NEPOOL AGREEMENT
1.1 Section 6.9(d) is amended so that it reads as follows:
(d) Member Adjusted Voting Share: for a Committee voting member which casts an affirmative or negative vote on a proposed action or amendment and which has been appointed by a Participant or group of Participants which are members of a Sector satisfying its Sector Quorum requirement for the proposed action or amendment, is the quotient obtained by dividing (i) the Sector Voting Share of that Sector for the Participants Committee or the Adjusted Sector Voting Share of that Sector for the Technical Committees by (ii) the number of voting members appointed by members of that Sector which cast affirmative or negative votes on the matter, adjusted, if necessary, for End User Participants and group voting members as provided in the definition of "Member Fixed Voting Share".
1.2 Section 6.9(e) is amended so that it reads as follows:
(e) NEPOOL Vote:
(i) with respect to an amendment or proposed action of the Participants Committee is the sum of (x) the Member Adjusted Voting Shares of the voting members of the Committee which cast an affirmative vote on the proposed action or amendment and which have been appointed by a Participant or group of Participants which are members of a Sector satisfying its Sector Quorum requirements and (y) the Member Fixed Voting Shares of the voting members of the Committee which cast an affirmative vote on the proposed action or amendment and which have been appointed by a Participant or group of Participants which are members of a Sector which fails to satisfy its Sector Quorum requirements; and
(ii) with respect to a proposed action of a Technical Committee is the sum of the Member Adjusted Voting Shares of the voting members of the Committee which cast an affirmative vote on the proposed action.
1.3 New Section 6.9(g) is added as follows:
(g) Adjusted Sector Voting Share: applies only for votes of Technical Committees and shall be determined for each Technical Committee vote in accordance with the following formula:
A = S + (S * [(100%-P)/P])
Where:
A is the Sector's Adjusted Sector Voting Share.
S is (i) for each active Sector which has not satisfied its Sector Quorum requirements, the sum of the Member Fixed Voting Shares of the Sector members who vote on the proposed action, or on whose behalf a vote is properly cast, and (ii) for each active Sector which has satisfied its Sector Quorum requirements, that Sector's Sector Voting Share.
P is the sum of (A) for each active Sector which has not satisfied its Sector Quorum requirements, the Member Fixed Voting Shares of the members who voted on the proposed action or on whose behalf a vote is properly cast and (B) the Sector Voting Shares of all Sectors which have satisfied their Sector Quorum requirements.
The aggregate Adjusted Sector Voting Share for each vote shall equal one hundred percent (100%).
SECTION 2 MISCELLANEOUS
2.1 This Eighty-Ninth Agreement shall become effective on January 1, 2003, or on such other date as the Commission shall provide that the amendments reflected herein shall become effective.
2.2 Terms used in this Eighty-Ninth Agreement that are not defined herein shall have the meanings ascribed to them in the NEPOOL Agreement.
Exhibit 10.25.20
NINETIETH AGREEMENT AMENDING
NEW ENGLAND POWER POOL AGREEMENT
(EXCESS FINANCIAL ASSURANCE)
THIS NINETIETH AGREEMENT AMENDING NEW ENGLAND POWER POOL AGREEMENT, dated as of October 4, 2002 ("Ninetieth Agreement"), amends the New England Power Pool Agreement (the "NEPOOL Agreement"), as amended.
WHEREAS, the NEPOOL Agreement as in effect on December 1, 1996 was amended and restated by the Thirty-Third Agreement Amending the New England Power Pool Agreement dated as of December 1, 1996 (the "Thirty-Third Agreement") in the form of the Restated New England Power Pool Agreement ("Restated NEPOOL Agreement") attached to the Thirty-Third Agreement as Exhibit A thereto, and the Thirty-Third Agreement also provided for the NEPOOL Open Access Transmission Tariff (the "NEPOOL Tariff") which is Attachment B to the Restated NEPOOL Agreement; and
WHEREAS, the Restated NEPOOL Agreement and the NEPOOL Tariff have subsequently been amended numerous times, the most recent amendment dated as of June 21, 2002; and
WHEREAS, the Participants desire to amend the Restated NEPOOL Agreement, including the NEPOOL Tariff, as heretofore amended, to reflect the revisions detailed herein.
NOW, THEREFORE, upon approval of this Ninetieth Agreement by the NEPOOL Participants Committee in accordance with the procedures set forth in the NEPOOL Agreement, the Participants agree as follows:
SECTION 1
AMENDMENTS TO MEMBER FINANCIAL ASSURANCE POLICY
1.1 Amendment to Section II.B.4. of the Member Financial Assurance Policy. The first sentence in the first paragraph of Section II.B.4 of the Financial Assurance Policy for NEPOOL Members, which is included as Attachment L to the NEPOOL Tariff (the "Member Financial Assurance Policy"), is amended to read as follows:
When a Non-Municipal Participant's aggregate
outstanding obligations to NEPOOL, the System Operator
and the Non-Participant FTR Customers equal 80 percent
(80%) of the sum of (i) that Non-Municipal
Participant's then-effective Credit Limit and (ii) the
available amount of the additional financial assurance
provided by that Non-Municipal Participant (exclusive
of any Bid Financial Assurance (defined below) provided
by that Non-Municipal Participant for bids in the FTR
Auction that have not yet been accepted or rejected),
which available amount of additional financial
assurance shall be divided by two and sixth-tenths
(2.6) for purposes of this determination <FN1> (the sum
of item (i) and item (ii) being referred to herein as
the "Credit Test Amount"), the System Operator shall
issue notice thereof to such Non-Municipal Participant,
such notice to be given in the manner provided in
Section 21 of the Restated NEPOOL Agreement.
1.2 Amendment to Section II.B.4 of the Member Financial Assurance Policy.
The first clause (y) in the first sentence of the second paragraph of
Section II.B.4 of the Member Financial Assurance Policy is amended to
read as follows:
(y) in the case of activity in the NEPOOL Market, the scheduling and receipt of transmission service and entering future transactions in the FTR system, such Non-Municipal Participant has provided additional financial assurance (in addition to any other financial assurance required of such Non-Municipal Participant hereunder) equal to two and sixth-tenths (2.6) times the amount by which such Non-Municipal Participant's outstanding obligations to NEPOOL, the System Operator and the Non-Participant FTR Customers exceed 100 percent (100%) of its Credit Test Amount (the "Excess Financial Assurance") and, in the case of voting on matters before the Participants Committee or any Technical Committee, such Non-Municipal Participant has provided Excess Financial Assurance at least three (3) Business Days prior to any such vote;
SECTION 2
MISCELLANEOUS
2.1 This Ninetieth Agreement shall become effective on January 1, 2003, or on such other date as the Commission shall provide that the amendments reflected herein shall become effective.
2.2 Terms used in this Ninetieth Agreement that are not defined herein shall have the meanings ascribed to them in the NEPOOL Agreement.
<FN1> For purposes of the amount in clause (ii) for any Corporate Guaranty, such amount shall be the lesser of the unused portion of any stated limit in such Corporate Guaranty (where such a limit is stated) divided by two and sixth-tenths (2.6) or the Guarantor's Credit Limit or Guaranty Limit (each as defined below), as applicable, which Credit Limit or Guaranty Limit shall not be divided by two and sixth-tenths (2.6).
Exhibit 10.25.21
NINETY-FIRST AGREEMENT AMENDING
NEW ENGLAND POWER POOL AGREEMENT
(DEMAND RESPONSE PROVIDER CHANGES)
THIS NINETY-FIRST AGREEMENT AMENDING NEW ENGLAND POWER POOL AGREEMENT, dated as of November 1, 2002 ("Ninety-First Agreement"), amends the New England Power Pool Agreement (the "NEPOOL Agreement"), as amended.
WHEREAS, the NEPOOL Agreement as in effect on December 1, 1996 was amended and restated by the Thirty-Third Agreement Amending the New England Power Pool Agreement dated as of December 1, 1996 (the "Thirty-Third Agreement") in the form of the Restated New England Power Pool Agreement ("Restated NEPOOL Agreement") attached to the Thirty-Third Agreement as Exhibit A thereto, and the Thirty-Third Agreement also provided for the NEPOOL Open Access Transmission Tariff (the "NEPOOL Tariff") which is Attachment B to the Restated NEPOOL Agreement; and
WHEREAS, the Restated NEPOOL Agreement and the NEPOOL Tariff have subsequently been amended numerous times, the most recent amendment dated as of October 4, 2002; and
WHEREAS, the Participants desire to amend the Restated NEPOOL Agreement, as heretofore amended, to reflect the revisions detailed herein.
NOW, THEREFORE, upon approval of this Ninety-First Agreement by the NEPOOL Participants Committee in accordance with the procedures set forth in the NEPOOL Agreement, the Participants agree as follows:
SECTION 1 AMENDMENTS TO RESTATED NEPOOL AGREEMENT
1.1 The following definition is added to Section 1 and inserted in the appropriate alphabetical order:
DRP is a Participant that (1) is eligible and enrolls itself and/or enrolls one or more eligible end users ("Demand Resources") to provide a reduction in energy usage in the NEPOOL Control Area (whether through reduced energy consumption or the operation of on-site generation which when operated does not result in net electric export to the grid) pursuant to the Load Response Program set forth in Market Rule 1 ("Load Response Program"); (2) does not participate in the NEPOOL Market other than as permitted or required pursuant to the Load Response Program; and (3) elects to be treated as a DRP before its application is approved by NEPOOL.
1.2 The first paragraph of Section 6.2 is amended so that it reads as follows:
The members of each Principal Committee shall each belong to a single sector for voting purposes ("Sector"). Each Participant shall be obligated to designate in a notice to the Secretary of the Participants Committee a Sector that it or its Related Persons is eligible to join and that it elects to join for purposes of all of the Principal Committees; provided, however, that (i) a Participant and the Participants which are its Related Persons shall not be eligible to join the End User Sector if any one of them is not eligible to join the End User Sector and (ii) a DRP and the Participants which are its Related Persons shall not be represented by the DRP Group Member (as defined below) if any one of them is not a DRP. A Participant and its Related Persons shall together be entitled to join only one Sector and shall have no more than one vote on each Principal Committee.
1.3 Section 6.2(c) is amended so that it reads as follows:
a Supplier Sector, which a Participant shall be eligible to join if (i) it engages in, or is licensed or otherwise authorized by a state or federal agency with jurisdiction to engage in, power marketing, power brokering or load aggregation within the NEPOOL Control Area, or it had been engaged on and before December 31, 1998 solely in the distribution of electricity in the NEPOOL Control Area, or it is a DRP, and (ii) it is not a Publicly Owned Entity. A Participant which is not a DRP and joins the Supplier Sector shall be entitled to designate a voting member of each Principal Committee, and an alternate to the member.
A Participant which joins the Supplier Sector as a DRP shall be represented by a group voting member and an alternate to that member for each Principal Committee (collectively, the "DRP Group Member"). The DRP Group Member shall be appointed by a majority of the DRPs. The DRP Group Member shall have the same percentage of the Sector vote as the individual voting members designated by other Participants in the Supplier Sector. The DRP Group Member shall be entitled to split his or her vote.
1.4 Subsections (c) and (d) of Section 19.1 is re-designated as subsections
(d) and (e) and the following new subsection is inserted immediately after
Section 19.1(b)
(c) Each Participant which is a DRP shall pay an annual fee of $5,000; plus, beginning January 1, 2004, an additional fee of $20 per megawatt month for each megawatt month of ICAP credit given to such DRP in the preceding year pursuant to the Load Response Program.
1.5 Section 19.1(e) (formerly Section 19.1(d)) is amended to read as follows:
(e) Each Participant other than an End User Participant, a DRP or a Publicly Owned Entity shall pay an annual fee of $5,000.
1.6 The third paragraph of Section 19.2 is amended so that it reads as follows:
Commencing as of July 1, 1999, such balance of NEPOOL expenses for July and subsequent months shall be divided equally into as many shares as there are active Sectors pursuant to Sector 6.2 (other than an End User Sector) and each Sector's share shall be paid monthly by the Participants in each such Sector (other than an End User Sector) in such manner as the Participants in each Sector may determine by unanimous vote and advise the ISO, provided that if the Participants in a Sector fail to agree unanimously on the allocation of their Sector's share, the Participants in the Sector shall pay for such Sector share as follows: (x) in the Supplier Sector, equally among all non-DRPs voting members and (y) in all other Sectors (other than an End User Sector), in the same proportion as the vote they are entitled to in the Sector. Participants in the Sector that are represented by a group voting member shall subdivide their portion of the Sector's share of expenses in such a manner as they may determine by unanimous agreement; provided that if there is not unanimous agreement among the Participants represented by a group member as to how to allocate their portion of the Sector's share of expenses, such portion shall be allocated among the Participants represented by that group member as follows: (i) for each Participant in the Generation Sector represented by a group voting member, the portion will be allocated in the same proportion that the Megawatts of generation owned by the Participants represents of the total Megawatts owned by Participants represented by the group voting member; and (ii) for Participants in the Transmission Sector, the portion will be allocated equally among the Participants represented by the group member. Notwithstanding the foregoing, no portion of such balance shall be paid by End User Participants or DRPs and, until such time as an End User Sector is activated, the monthly share allocated to the Publicly Owned Entity Sector shall be reduced by one- twelfth of the aggregate annual fees paid by End Users for the year pursuant to Section 19.1 and one-third of the amount of such reduction shall be allocated to each of the other three Sectors.
1.7 Section 19.3(c) is amended so that it reads as follows:
The Restructuring Expense incurred on the Second Effective Date and to but not including January 1, 2000 or thereafter shall be funded each month by the Participants in proportion to the Member Fixed Voting Shares (as defined in Section 6.9(c)) of each Participant as in effect at the beginning of the month provided, however, that in calculating the allocation of this portion of the Restructuring Expense, the Member Fixed Voting Shares of End User Participants that participate in NEPOOL for governance purposes only in accordance with NEPOOL's Standard Membership Conditions, Waivers and Reminders ("Governance Only End User Participants") and DRPs shall not be included in such calculations and the amounts that would otherwise have been payable by such Governance Only End User Participants and DRPs will be allocated to all of the other Participants on the basis of their Member Fixed Voting Shares.
SECTION 2 MISCELLANEOUS
2.1 This Ninety-First Agreement shall become effective on January 1, 2003, or on such other date as the Commission shall provide that the amendments reflected herein shall become effective.
2.2 Terms used in this Ninety-First Agreement that are not defined herein shall have the meanings ascribed to them in the NEPOOL Agreement.
2.3 The Participants Committee shall receive a report from the Membership Subcommittee at its November 2003 meeting addressing the experience with demand response provider participation in NEPOOL and whether any adjustment should be made with respect to the charges paid by demand response providers for their participation in NEPOOL.
EXHIBIT 10.25.22
NINETY-SECOND AGREEMENT AMENDING
NEW ENGLAND POWER POOL AGREEMENT
(NEPOOL SMD - CONFORMING RNA CHANGES)
THIS NINETY-SECOND AGREEMENT AMENDING NEW ENGLAND POWER POOL
AGREEMENT, dated as of November 1, 2002 ("Ninety-Second
Agreement"), amends the New England Power Pool Agreement (the
"NEPOOL Agreement"), as amended.
WHEREAS, the NEPOOL Agreement as in effect on December 1, 1996 was amended and restated by the Thirty-Third Agreement Amending the New England Power Pool Agreement dated as of December 1, 1996 (the "Thirty-Third Agreement") in the form of the Restated New England Power Pool Agreement ("Restated NEPOOL Agreement" or "RNA") attached to the Thirty-Third Agreement as Exhibit A thereto, and the Thirty-Third Agreement also provided for the NEPOOL Open Access Transmission Tariff (the "NEPOOL Tariff") which is Attachment B to the Restated NEPOOL Agreement; and
WHEREAS, the Restated NEPOOL Agreement and the NEPOOL Tariff have subsequently been amended numerous times, the most recent amendment dated as of October 4, 2002; and
WHEREAS, the Participants desire to amend the Restated NEPOOL Agreement, as heretofore amended, to reflect the revisions detailed herein.
NOW, THEREFORE, upon approval of this Ninety-Second Agreement by the NEPOOL Participants Committee in accordance with the procedures set forth in the NEPOOL Agreement, the Participants agree as follows:
SECTION 1
NEPOOL TARIFF AMENDMENTS
1.1 The Restated NEPOOL Agreement is amended as set forth in Appendix A hereto.
SECTION 2
MISCELLANEOUS
2.1 Effective Dates. The amendments provided in this Ninety-Second Agreement shall become effective as of the SMD Effective Date as defined in NEPOOL FERC Electric Rate Schedule No. 7, NEPOOL Market Rule 1.
2.2 Defined Terms. Terms used in this Ninety-Second Agreement that are not defined herein shall have the meanings ascribed to them in the Restated NEPOOL Agreement, NEPOOL Tariff, and NEPOOL Market Rule 1.
Appendix A Ninety-Second Agreement
AMENDMENTS TO THE RESTATED NEPOOL
AGREEMENT
1.1 The first paragraph of Section 1 is amended to read as follows:
Whenever used in this Agreement, in either the singular or
plural number, the following terms shall have the following
respective meanings (an asterisk (*) indicates that the
definition may be modified in certain cases pursuant to
Section 1.109, a single caret (^) indicates that the
definition is no longer effective for service on and after
the SMD Effective date, and a double caret (^^) indicates
that the definition is no longer effective for service on
and after the ICAP Effective Date):
1.2 The following definitions are deleted in their entirety:
"Market Products" and "Third Effective Date"
1.3 The following definitions are amended to be identified by a single caret (^):
Adjusted Net Interchange;
AGC Capability;
AGC Entitlement;
Bid Price;
Dispatch Price;
Electrical Load;
Energy Entitlement;
Firm Contract;
HQ Contracts;
HQ Energy Banking Agreement;
HQ Phase II Percentage;
Monthly Peak;
Operable Capability;
Operating Reserve Entitlement;
Other HQ Energy;
Scheduled Dispatch Period;
System Contract;
Unit Contract; and
Minute Spinning Reserve.
1.4 In addition, the heading of the last Subsection of Section 1 is amended to be identified by a single caret (^) so that it reads as follows:
Modification of Certain Definitions When a Participant Purchases a Portion of Its Requirements from Another Participant Pursuant to a Firm Contract ^
1.5 The following definitions are amended to be identified by a double caret (^^):
Adjusted Load;
Adjusted Monthly Peak;
HQ Phase I Energy Contract;
HQ Phase I Percentage;
HQ Phase II Gross Transfer Responsibility;
HQ Phase II Net Transfer Responsibility;
Installed Capability Entitlement;
Installed Capability Responsibility;
Installed System Capability;
NEPOOL Installed Capability Responsibility;
New Unit;
Pool-Planned Unit;
Proxy Unit; and
Target Availability Rate.
1.6 The following definitions are inserted in the appropriate alphabetical order:
ICAP Effective Date is a date fixed by the ISO and posted on
its website as the effective date for the Installed Capacity
arrangements contemplated by Section 8 of Market Rule 1,
that is (i) the first day of a calendar month; (ii) at least
one full calendar month after the SMD Effective Date; and
(iii) at least thirty (30) days after the ISO has provided
notice to the Commission that NEPOOL System Rules and
computer programs necessary to implement the Installed
Capacity arrangements contemplated by Section 8 of Market
Rule 1 are fully in place and functional.
Installed Capacity Requirement is defined in Market Rule 1 and represents the level of capacity required to meet the reliability requirements defined for the NEPOOL Control Area.
Load Asset is a physical load that has been registered with the System Operator in accordance with the asset registration process contained in the NEPOOL System Rules.
Market Rule 1 is NEPOOL Market Rule 1 and attachments as filed with the Commission on July 15, 2002 as NEPOOL FERC Electric Rate Schedule No. 7, as it may be amended from time to time.
NEPOOL Transmission System is the system of transmission facilities within the NEPOOL Control Area under the ISO's operational jurisdiction.
Ownership Share is a term to be effective on and after the SMD Effective Date that is a right or obligation, for purposes of settlement, to a percentage share of all credits or charges associated with a generating unit or Load Asset, where such unit or load is interconnected to the NEPOOL Transmission System.
Settlement Obligation is, on and after the SMD Effective Date, an obligation for Energy, Operating Reserve or Regulation as defined in Market Rule 1.
SMD Effective Date is the date fixed by the ISO and posted on its website as the effective date for the market provisions of Sections 1-7 of Market Rule 1. The SMD Effective Date may not occur until (i) a date after a Commission order is issued permitting Market Rule 1 to go into effect; (ii) at least two weeks after the ISO has given the Commission written notice that the NEPOOL System Rules and computer programs necessary to implement Market Rule 1 are fully in place and functional; and (iii) at least 48 hours after the ISO has posted the date on its website.
Transmission Congestion Revenue is defined in Section 5.2.5 of Market Rule 1.
1.7 The definition for "Administrative Procedures" is renamed to read "ISO Administrative Procedures" and wherever "Administrative Procedures" is used in the Restated NEPOOL Agreement, the references are amended prospectively to read "ISO Administrative Procedures".
1.8 The definition for "Automatic Generation Control or AGC" in
Section 1 is amended to read as "Automatic Generation
Control or AGC or Regulation".
1.9 The following sentence is added to the end of the definition of "Entitlement":
"On or after the SMD Effective Date, references to an `Entitlement' shall be deemed to refer to an `Ownership Share' as defined in this Agreement."
1.10 The definition of "Entity" is amended by replacing the reference to "AGC" in subsection (a) with a reference to "AGC/Regulation".
1.11 The definition of "Excepted Transaction" is amended to read as follows:
Excepted Transaction is a transaction specified in Section 25 of the Tariff or the applicable period specified in that Section.
1.12 The definitions for "Facilities Study" and "System Impact Study" are amended by replacing the phrase "NEPOOL Transmission System" with the term "PTF".
1.13 The following sentence is added to the end of the definition of "NEPOOL Objective Capability":
"On and after the SMD Effective Date, references to NEPOOL Objective Capability shall be deemed to mean `Installed Capacity Requirement' as defined in this Agreement."
1.14 The definition of "NEPOOL System Rules" is amended to read as follows:
NEPOOL System Rules are the Market Rules, the NEPOOL Information Policy, ISO Administrative Procedures and any other system rules, manuals, procedures, criteria or Reliability Standards for the operation of the System and administration of the NEPOOL Market, the NEPOOL Agreement and the NEPOOL Tariff.
1.15 The definition of "NEPOOL Transmission System" is amended to read as follows:
NEPOOL Transmission System is the system of transmission facilities within the NEPOOL Control Area under the ISO's operational jurisdiction.
1.16 The definition of "Operating Reserve" is amended to read as follows:
Operating Reserve, until the SMD Effective Date, is any or a combination of 10-Minute Spinning Reserve, 10-Minute Non- Spinning Reserve, and 30-Minute Operating Reserve, as the context requires. On and after the SMD Effective Date, Operating Reserve shall have the meaning expressed in Market Rule 1.
1.17 Clause (ii) in the definition of "Transmission Customer" is amended by inserting the parenthetical "(as defined in the Tariff)" immediately after the phrase "Designated Agent".
1.18 The definition of 10-Minute Spinning Reserve is amended to read as follows:
10-Minute Spinning Reserve in an hour are the following resources that are dispatched by the System Operator in accordance with the NEPOOL System Rules, to be available to provide contingency protection for the system: (1) the Kilowatts of operable capability of an electric generating unit or units that are synchronized to the system, unloaded during all or part of the hour, and capable of providing contingency protection by loading to supply Energy immediately on demand, increasing the Energy output over no more than ten minutes to the full amount of generating capacity so designated, and sustaining such Energy output for so long as the System Operator determines in accordance with the NEPOOL System Rules is necessary; and (2) any portion of the electrical load of a Participant that the System Operator is able to verify as capable of providing contingency protection by immediately on demand reducing Energy requirements within ten minutes and maintaining such reduced Energy requirements for so long as the System Operator determines in accordance with the NEPOOL System Rules is necessary.
1.19 The definition of 10-Minute Non-Spinning Reserve is amended to read as follows:
10-Minute Non-Spinning Reserve in an hour are the following resources that are dispatched by the System Operator in accordance with the NEPOOL System Rules to be available to provide contingency protection for the system: (1) the Kilowatts of operable capability of an electric generating unit or units that are not synchronized to the system, during all or part of the hour, and capable of providing contingency protection by loading to supply Energy within ten minutes to the full amount of generating capacity so designated, and sustaining such Energy output reducing Energy requirements within ten minutes and maintaining such reduced Energy requirements for so long as the System Operator determines in accordance with the NEPOOL System Rules is necessary; (2) any portion of a Participant's electrical load that the System Operator is able to verify as capable of providing contingency protection by reducing Energy requirements within ten minutes and maintaining such reduced Energy requirements for so long as the System Operator determines in accordance with the NEPOOL System Rules is necessary; and (3) any other resources and requirements that were able to be designated for the hour as 10-Minute Spinning Reserve but were not designated by the System Operator for such purpose in the hour.
1.20 The definition of 30-Minute Operating Reserve is amended to read as follows:
30-Minute Operating Reserve in an hour are the following resources that are dispatched by the System Operator in accordance with the NEPOOL System Rules to be available to provide contingency protection for the system: (1) the Kilowatts of operable capability of an electric generating unit or units that are any portion of the electrical load of a Participant that the System Operator is able to verify as capable of providing contingency protection by reducing Energy requirements within thirty minutes and maintaining such reduced Energy requirements for so long as the System Operator determines in accordance with the NEPOOL System Rules is necessary; (2) any portion of the electrical load of a Participant that the System Operator is able to verify as capable of providing contingency protection by reducing Energy requirements within thirty minutes and maintaining such reduced Energy requirements for so long as the System Operator determines in accordance with the NEPOOL System Rules is necessary; and (3) any other resources and requirements that were able to be designated for the hour as 10-Minute Spinning Reserve or 10-Minute Non-Spinning Reserve but were not designated by the System Operator for such purposes in the hour.
1.21 The third paragraph of Section 2.2 is amended to read as follows:
As provided in Section 14, certain portions of Section 14 which became effective on the Second Effective Date will be superseded on the SMD Effective Date by Market Rule 1.
1.22 A new fourth paragraph of Section 2.2 is added to read as follows:
As provided in Section 12, certain portions of Section 12 which became effective on or after the Second Effective Date will be superseded on the ICAP Effective Date by Market Rule 1.
1.23 The following two new sentences are added to the end of
Section 12.1:
Sections 12.2, 12.5 and 12.7 of this Agreement which became effective on or after the Second Effective Date will cease to be effective and be superseded on the ICAP Effective Date by Market Rule 1. On and after the ICAP Effective Date, each Participant shall be obligated to satisfy each month its capacity obligation pursuant to Section 8.2.2 of Market Rule 1.
1.24 Section 13.4 is amended to read as follows:
Objectives of Day-to-Day System Operation.
(a) Until the SMD Effective Date, the day-to-day scheduling and coordination through the System Operator of the operation of generating units and other resources shall be designed to assure the reliability of the bulk power system of the NEPOOL Control Area. Such activity shall:
(i) satisfy the NEPOOL Control Area's Operating Reserve requirements, including the proper distribution of those Operating Reserves;
(ii) satisfy the Automatic Generation Control requirements of the NEPOOL Control Area; and
(iii) satisfy the Energy requirements of all Electrical Loads of the Participants, all at the lowest practicable aggregate dispatch cost to the NEPOOL Control Area in light of available Bid Prices and Participant-directed schedules.
(b) On and after the SMD Effective Date, the System Operator shall satisfy the energy and ancillary service requirements of the NEPOOL Control Area in accordance with Market Rule 1 on the basis of least-cost, security- constrained dispatch and the prices and operating characteristics offered by Participants.
1.25 The following introductory paragraph is added following the heading to Section 14 so that it reads as follows:
Section 14 of this Agreement, which became effective on the Second Effective Date, will cease to be effective and will be superceded on the SMD Effective Date by Section 14A and Market Rule 1.
1.26 A new Section 14A is added so that it reads as follows:
SECTION 14A
PARTICIPANT MARKET TRANSACTIONS
ON AND AFTER THE SMD EFFECTIVE DATE
14A.1 NEPOOL Market Rights and Obligations.
(a) Energy and Operating Reserve Settlement. The
rights and Settlement Obligations of the
Participants with respect to the furnishing and
receipt of Energy and Operating Reserve shall be
determined in accordance with this Section 14A and
Market Rule 1.
(b) Regulation Settlement Obligation. Settlement
Obligations for Regulation for each hour are
established by allocating the total Regulation
designated for the hour in the Real-Time Market by
the System Operator to Participants under the
Agreement and Non-Participants under the Tariff.
Each Participant or non-Participant Transmission
customer shall have for each hour a Settlement
Obligation for Regulation in accordance with
Market Rule 1. A Settlement Obligation for
Regulation shall require the Participant to pay
its share of the Regulation costs in accordance
with Market Rule 1.
14A.2 Right to Receive Service and Payment. Except as
emergency circumstances may result in the System
Operator requiring load curtailments by Participants,
and subject to the availability of transmission
capacity and ICAP Resources, or other generation or
other resources available to the ISO, each Participant
shall be entitled to receive from other Participants
such amounts, if any, of Energy, Operating Reserve,
ICAP and Regulation as it purchases, and each
Participant or Non-Participant shall be entitled to
receive payment for all services provided, in
accordance with the NEPOOL System Rules.
14A.3 Contract and Scheduling Authority. The Participants
Committee is authorized to enter into agreements
between the NEPOOL Control Area and another Control
Area on behalf of and in the names of all Participants
with Non-Participants to purchase or furnish emergency
Energy that is available for the System Operator to
schedule in order to ensure reliability in the NEPOOL
Control Area or neighboring Control Areas. Emergency
purchases from another Control Area pursuant to this
Section 14A.3 should not be implemented unless the
Participants have been unable to furnish such Supply
Offers (as defined in Market Rule 1) as the System
Operator determines are required to ensure reliability.
For emergency purchases and sales pursuant to this
Section 14A.3, the treatment of the transaction with
the Non-Participant in the determination of a
Locational Marginal Price (as defined in Market Rule 1)
shall be in accordance with Market Rule 1. Energy (and
related services) from any such emergency purchases
shall be deemed to be furnished to and shall be paid
for by Participants, in accordance with Market Rule 1.
Energy (and related services) from any such emergency
sales shall be deemed to be furnished to and shall be
paid for by the Non-Participant, in accordance with
this Section 14A.3 and the terms of any such
contractual arrangement with the Non-Participant.
14A.4 Bilateral Transactions and Participant Transactions
with Non-Participants.
(a) Participants may enter into internal bilateral
transactions and External Transactions (as defined
in Market Rule 1) for the purchase or sale of
Energy or other products to or from each other or
any other entity, subject to the obligations of
Participants to make ICAP Resources available for
dispatch by the System Operator. External
Transactions that contemplate the physical
transfer of Energy or obligations to or from a
Participant shall be reported to and coordinated
with the System Operator in accordance with Market
Rule 1.
(b) In the event a Participant has the right to
receive Energy, Operating Reserve and/or
Regulation from a Non-Participant under a
bilateral transaction, such Energy, Operating
Reserve and/or Regulation may be submitted by the
Participant to the System Operator in a Supply
Offer (as defined in Market Rule 1) as a proposal
to furnish Energy, Operating Reserve, and/or
Regulation to the extent the contract permits in
accordance with the Market Rule 1.
14A.5 Losses. The cost of losses and the recovery
thereof shall be determined in accordance with Market
Rule 1.
14A.6 Congestion Cost and Revenues. Congestion Cost and
the recovery and disbursement thereof shall be
determined in accordance with Market Rule 1.
14A.7 Operating Reserve and RMR.
(a) Operating Reserve. The calculation, payment and
recovery of Operating Reserve amounts shall be
determined in accordance with Market Rule 1.
(b) RMR Operating Reserve Charges. The designation of
Reliability Must Run Resources and the calculation
and recovery of RMR Operating Reserve Charges
shall be determined in accordance with Market Rule
1.
|
1.27 Sections 15.1, 16.6, and Section17.7 are amended by substituting the term "PTF" in place of the phrase "NEPOOL Transmission System" at each occurrence.
1.28 The headings in the first row of the schedule set forth in
Section 16.6.A are clarified by identifying the time period
associated with the corresponding year so that they read as
follows:
Year One Year Two Year Three Year Four Year Five Year Six [2/1/97- [2/1/98- [2/1/99- [2/1/00- [2/1/01- [2/1/02- 1/31/98] 1/31/99] 1/31/00] 1/31/01] 1/31/02] 1/31/03] |
1.29 The following new sentence is added to the end of Section 16.6.D:
The revenues received by NEPOOL pursuant to Schedules 3-6 to the Tariff for service rendered on or after the SMD Effective Date shall be distributed in accordance with Market Rule 1.
1.30 Section 16.6.E is amended to read as follows:
Congestion Payments. Until the SMD Effective Date, any
congestion uplift charge received as a payment for
transmission service pursuant to Section 24 of the
Tariff for any hour shall be applied in accordance with
Section 14.5(a) in payment for Energy service. On or after
the SMD Effective Date, Transmission Congestion Revenue
received for service provided shall be applied in accordance
with Market Rule 1.
1.31 The formula set forth in Section 19.3(b) used to determine the percentage to be paid for a month by a Participant of the aggregate amount payable pursuant to Section 19.3(b) is amended to read as follows:
W = LO + GO divided by LO(1) + GO(1) all times 0.50
+
POL + GOP DIVIDED BY POL(1) + GOP(1) all times 0.50 in which
W is the percentage to be paid for the month by a Participant of the aggregate amount payable pursuant to this subsection (b) by all Participants for the month.
LO is the Participant's total Real Time Load Obligation as defined and determined in accordance with Market Rule 1 for the month.
GO is the Participant's Real Time Generation Obligation as defined and determined in accordance with Market Rule 1.
PLO is the maximum Real Time Load Obligation of the Participant during any hour in the month (the "Peak Real Time Load Obligation").
GOP is the maximum Real Time Generation Obligation of the Participant during any hour in the month (the "Real Time Generation Obligation Peak").
LO(1) is the aggregate Real Time Load Obligation of all Participants for the month.
GO(1) is the aggregate Real Time Generation Obligation of all Participants for the month.
PLO(1) is the aggregate Peak Real Time Load Obligation of all Participants for the month.
GOP(1) is the aggregate Real Time Generation Obligation Peak of all Participants for the month.
EXHIBIT 10.25.23
NINETY-THIRD AGREEMENT AMENDING
NEW ENGLAND POWER POOL AGREEMENT
(NEPOOL SMD - CONFORMING TARIFF CHANGES)
THIS NINETY-THIRD AGREEMENT AMENDING NEW ENGLAND POWER POOL
AGREEMENT, dated as of November 1, 2002 ("Ninety-Third
Agreement"), amends the New England Power Pool Agreement (the
"NEPOOL Agreement"), as amended.
WHEREAS, the NEPOOL Agreement as in effect on December 1, 1996 was amended and restated by the Thirty-Third Agreement Amending the New England Power Pool Agreement dated as of December 1, 1996 (the "Thirty-Third Agreement") in the form of the Restated New England Power Pool Agreement ("Restated NEPOOL Agreement") attached to the Thirty-Third Agreement as Exhibit A thereto, and the Thirty-Third Agreement also provided for the NEPOOL Open Access Transmission Tariff (the "NEPOOL Tariff") which is Attachment B to the Restated NEPOOL Agreement; and
WHEREAS, the Restated NEPOOL Agreement and the NEPOOL Tariff have subsequently been amended numerous times, the most recent amendment dated as of October 4, 2002; and
WHEREAS, the Participants desire to amend the Restated NEPOOL Agreement, as well as the NEPOOL Tariff, as heretofore amended, to reflect the revisions detailed herein.
NOW, THEREFORE, upon approval of this Ninety-Third Agreement by the NEPOOL Participants Committee in accordance with the procedures set forth in the NEPOOL Agreement, the Participants agree as follows:
SECTION 1
NEPOOL TARIFF AMENDMENTS
1.1 The NEPOOL Tariff is amended as set forth in Appendix A hereto.
SECTION 2
MISCELLANEOUS
2.1 Effective Dates. The amendments provided in this Ninety-Third Agreement shall become effective as of the SMD Effective Date as defined in NEPOOL FERC Electric Rate Schedule No. 7, NEPOOL Market Rule 1.
2.2 Defined Terms. Terms used in this Ninety-Third Agreement that are not defined herein shall have the meanings ascribed to them in the Restated NEPOOL Agreement, NEPOOL Tariff, and NEPOOL Market Rule 1.
APPENDIX A
Ninety-Third Agreement
AMENDMENTS TO THE NEPOOL TARIFF
General
1.1 The following Sections are deleted in their entirety: 3
(Initial Allocation and Renewal Procedures), 3.1 (Initial
Allocation of Available Transmission Capacity), 3.2
(Reservation Priority for Existing Firm Service Customers),
3.3 (Initial Election of Optional Internal Point-To-Point
Service), 4.7 (Operating Reserve - 30 Minute Reserve
Service), 14.1 (Rules for Import Transactions Conducted in
Conjunction with Regional Network Service), 24 (Congestion
Costs and Congestion Revenue), 25A (Phase I Credit and
Uplift Charge with Respect to Excepted Transactions), 25B
(Phase II Credit and Uplift Charge with Respect to Certain
Excepted Transactions), 27.7(b), 33.7 (Partial Interim
Service), 40.4 (Secondary Service), 49(d), and 52 (Quick
Fix Measures).
Part I - Common Service Provisions
2.1 Section 1 is amended by deleting the following definitions:
"Entitlement", "Firm Contract", "HQ Phase II Firm Energy
Contract", "Import Transaction", "Interruption", "Load Ratio
Share", "Short-Term Firm Service", "System Contract", "Third
Effective Date", "Ties" and "Unit Contract"; and by adding
in the appropriate alphabetical order and assigning the
appropriate definition numbers the following new
definitions:
Auction Revenue Rights: Are as defined and determined pursuant to Market Rule 1.
Congestion: Is a condition of the NEPOOL Transmission System in which transmission limitations prevent unconstrained regional economic dispatch of the power system. Congestion is the condition that results in the Congestion Component of the Locational Marginal Price at one Location being different from the Congestion Component of the Locational Marginal Price at another Location during any given hour of the Dispatch Day in the Day-Ahead Market or Real-Time Market.
Congestion Component: Is as defined and calculated pursuant to Market Rule 1.
Congestion Cost: Is as defined and calculated pursuant to Market Rule 1.
Day-Ahead Energy Market: Is as defined and determined pursuant to Market Rule 1.
External Node: Is as defined and determined pursuant to Market Rule 1.
External Transaction: Is as defined pursuant to Market Rule 1.
Financial Transmission Right (FTR): A financial instrument that evidences the rights and obligations specified in Sections 5 and 7 of Market Rule 1.
FTR Auction: The periodic auction of FTRs conducted by the ISO in accordance with Section 7 of Market Rule 1.
Locational Marginal Price (LMP): Is as defined and calculated pursuant to Market Rule 1.
Loss Component: Is as defined and calculated pursuant to Market Rule 1.
Market Rule 1: Is NEPOOL Market Rule 1 and appendices as filed with the Commission on July 15, 2002 as NEPOOL FERC Electric Rate Schedule No. 7, as it may be amended from time to time.
NEPOOL Manuals: Are as defined pursuant to Market Rule 1.
NEPOOL Market: Is as defined pursuant to Market Rule 1.
NEPOOL Transmission Plan: The plan developed under the process specified in Section 51 of this Tariff.
NEPOOL System Rules: Are as defined pursuant to Market Rule 1.
Node: Is as defined pursuant to Market Rule 1.
Operating Day: Is as defined pursuant to Market Rule 1.
Operating Reserve - Spinning Reserve Service: This service is the form of Ancillary Service described in Schedule 5.
Operating Reserve - Supplemental Reserve Service: This service is the form of Ancillary Service described in Schedule 6.
Ownership Share: Is as defined pursuant to Market Rule 1.
Pool-Supported PTF: (i) PTF first placed in service prior to January 1, 2000; (ii) Generator Interconnection Related Upgrades with respect to Category A and B projects (as defined in Schedule 11), but only to the extent not paid for by the interconnecting Generator Owner; and (iii) other PTF upgrades, but only to the extent the costs therefore are determined to be Pool-Supported PTF in accordance with Schedule 12.
Qualified Upgrade Award: Is as defined and determined pursuant to Market Rule 1.
Real-Time Energy Market: Is as defined and determined pursuant to Market Rule 1.
Reliability Committee: The committee whose responsibilities are specified in Section 8 of the Agreement and which may have additional responsibilities under a proper delegation of authority by the Participants Committee. To the extent practicable, references in the Tariff to the Reliability Committee shall include the prior Market Reliability Planning Committee or the prior Regional Transmission Planning Committee as the predecessor of the Reliability Committee.
Reliability Region: Is as defined pursuant to Market Rule 1.
Resource: Is as defined pursuant to Market Rule 1.
SMD Effective Date: Is as defined and determined pursuant to Market Rule 1.
Tariff Committee: The committee whose responsibilities are specified in Section 9 of the Agreement and which may have additional responsibilities under a proper delegation of authority by the Participants Committee. To the extent practicable, references in the Tariff to the Tariff Committee shall include the prior Regional Transmission Operations Committee as the predecessor of the Tariff Committee.
Transmission Congestion Revenue: Transmission Congestion Revenue is defined and calculated pursuant to Section 5 of Market Rule 1.
Transmission Owner: A Transmission Provider which makes its PTF available under the Tariff and owns a Local Network listed in Attachment E to the Tariff which is not a Publicly Owned Entity, including any affiliate of a Transmission Provider that owns facilities that are made available as part of the Transmission Provider's Local Network; provided that if a Transmission Provider is not listed in Attachment E to the Tariff on May 10, 1999, the Transmission Provider must also (1) own, or lease with rights equivalent to ownership, PTF with an original capital investment in its PTF as of the end of the most recent year for which figures are available from annual reports submitted to the Commission in Form 1 or any similar form containing comparable annualized data of at least $30,000,000, and (2) provide transmission service to non- affiliated customers pursuant to an open access transmission tariff on file with the Commission.
2.2 The definition for "Ancillary Services" is amended by deleting the phrase "and/or MTF".
2.3 The definition for "Curtailment" is amended by substituting the phrase "the dispatch of a transaction that was scheduled, using" for the phrase "firm or non-firm". In addition, a comma is inserted immediately following the word "service".
2.4 The definition for "Elective Transmission Upgrade" is amended by deleting each occurance of the phrase "and/or MTF". In addition, the phrase "Quick Fix Upgrade" is also deleted.
2.5 The definition for "Excepted Transaction" is amended by substituting a period for the comma appearing after the word "Section" and removing the phrase "or in Sections 25A and 25B".
2.6 The definition for "Facilities Study" is amended to read as follows:
Facilities Study: An engineering study conducted pursuant to the Agreement or this Tariff by the System Operator and/or one or more affected Participants to determine the required modifications to the PTF and indirectly affected MTF, including the cost and scheduled completion date for such modifications, that will be required to provide a requested transmission service or interconnection on the PTF.
2.7 The definition for "Firm Transmission Service" is amended
Firm Transmission Service: Service for Native Load Customers, firm Regional Network Service (Network Integration Transmission Service), service for Excepted Transactions and certain other transactions listed in Attachment G-3, Firm Internal Point-To-Point Transmission Service, or Firm MTF Service.
2.8 The definition for "Interchange Transactions" is amended to read as follows:
Interchange Transactions: Transactions deemed to be effected under Market Rule 1.
2.9 The definition for "Internal Point-To-Point Service" is amended by adding the phrase "over the PTF provided by the Participants" after the word "Service" and by replacing the phrase "Transmission System" with the phrase "Control Area".
2.10 The definition for "Load Zone" is amended to read as follows:
Load Zone: Is as defined and determined pursuant to Market Rule 1.
2.11 The definitions for "Local Network" and "Second Effective Date" are amended by replacing the references to "Management Committee" to read "Participants Committee".
2.12 The definitions for "Local Point-To-Point Service", "NEMA", "Network Integration Transmission Service", "Network Upgrades", "Regional Network Service", "Reserved Capacity" and "Through or Out Service" are amended by replacing each occurrence of the phrase "NEPOOL Transmission System" with the term "PTF".
2.13 The definition for "NEPOOL Transmission System" is amended by replacing the term "PTF" with the phrase "system of", and adding the phrase "within the NEPOOL Control Area under the ISO's operational jurisdiction" after the word "facilities".
2.14 The definition for "Network Operating Committee" is amended by replacing the references to "Regional Transmission Operations Committee" to read "Tariff Committee" and the references to "Regional Transmission Planning Committee" to read "Reliability Committee".
2.15 The definition for "Network Resource" is amended by replacing the term "Entitlement" with the phrase "Ownership Share".
2.16 The definition for "Non-PTF" is amended by adding the phrase "or by Non-Participants" after the word "Participants".
2.17 The definitions for "Point(s) of Delivery" and "Point(s) of Receipt" are amended to read as follows:
Point(s) of Delivery: Point(s) where capacity and/or energy transmitted by the Participants will be made available to the Receiving Party under this Tariff.
Point(s) of Receipt: Point(s) of interconnection where capacity and/or energy to be transmitted by the Participants will be made available to NEPOOL by the Delivering Party under this Tariff.
2.18 The definition for the term "Point-To-Point Transmission Service" is amended by adding the phrase "pursuant to Internal Point-To-Point Service or MTF Service; and the transmission of capacity and/or energy from the Point(s) of Receipt to the Point(s) of Delivery under this Tariff pursuant to Through or Out Service", and by deleting the last sentence.
2.19 The definition for "System Impact Study" is amended by deleting the phrase "and/or MTF" after the word "System" in subsection (i), deleting the comma after the Phrase "Regional Network Service" and inserting the word "or" in subsection (i), and replacing the phrase "Through or Out Service" with the phrase "an Elective Upgrade".
2.20 The introductory language after Section 2 (Purpose of this Tariff) is amended by replacing all references to the phrase "NEPOOL Transmission System" with the term "PTF", and by replacing the word "five" with the word "six" in the sixth sentence.
2.21 The following new Section 2A is added immediately following
Section 2:
Market Rule 1: This Tariff is intended to provide for transmission service in conjunction with the NEPOOL Standard Market Design as provided for in Market Rule 1. The provisions of Market Rule 1 are incorporated by reference as a part of this Tariff, and shall apply to all entities that receive service under this Tariff.
2.22 Section 4 is amended to read as follows:
Ancillary Services: Ancillary Services are needed with transmission service to maintain reliability within the NEPOOL Control Area. The Participants are required to provide through NEPOOL, and the Transmission Customer is required to purchase from NEPOOL, Scheduling, System Control and Dispatch Service, and Reactive Supply and Voltage Control from Generation Sources Service. The Participants offer to provide or arrange for, through NEPOOL, the following Ancillary Services, but only to a Participant with a load obligation in the NEPOOL Market pursuant to Market Rule 1: (i) Regulation and Frequency Response (Automatic Generator Control), (ii) Energy Imbalance, (iii) Operating Reserve - Spinning, and (iv) Operating Reserve - Supplemental. A Participant or other Transmission Customer with a load obligation in the NEPOOL Market pursuant to Market Rule 1 is required to provide these Ancillary Services, whether from the System Operator, from a third party, or by self-supply. A Transmission Customer may not decline NEPOOL's offer of these Ancillary Services unless the Transmission Customer demonstrates to the System Operator that the Transmission Customer has acquired Ancillary Services of equal quality from another source. The Transmission Customer that is not a Participant must list in its Application which Ancillary Services it will purchase through NEPOOL. Ancillary Services for MTF shall be allocated and paid for in accordance with Schedule 18 of the Tariff. In the event of an unauthorized use of any Ancillary Service by the Transmission Customer taking Internal Point-To-Point Service, the Transmission Customer will be required to pay 200% of the charge which would otherwise be applicable.
The specific Ancillary Services, prices and/or compensation methods are described on the Schedules that are attached to and made a part of this Tariff and in Market Rule 1.
Sections 4.1 through 4.9 below list the Ancillary Services.
2.23 Section 4.3 (Regulation and Frequency Response Service) is amended by inserting the phrase "that shall apply to Transmission Customers for this service" after the word "methodology" and "of this Tariff and Market Rule 1" after the phrase "Schedule 3".
2.24 Section 4.4 (Energy Imbalance Service) is amended by inserting the phrase "that shall apply to Transmission Customers for this service" after the word "methodology" and "of this Tariff and Market Rule 1" after the phrase "Schedule 4".
2.25 Section 4.5 (Operating Reserve - 10 Minute Spinning Reserve Service) is amended by deleting the phrase "10 Minute", by inserting the phrase "that shall apply to Transmission Customers" after the word "methodology", and by inserting the phrase "of this Tariff and Market Rule 1" after the phrase "Schedule 5".
2.26 Section 4.6 (Operating Reserve - 10 Minute Non-Spinning Reserve Service" is amended by substituting the phrase "10 Minute Non-Spinning" with the word "Supplemental", inserting the phrase "that shall apply to Transmission Customers" after the word "methodology", and by inserting the phrase "of this Tariff and Market Rule 1" after the phrase "Schedule 6".
2.27 Section 4.8 (System Restoration and Planning Service) is amended by substituting the phrase "Where applicable, the" with the word "The", and inserting the phrase "that shall apply to Transmission Customers" after the word "methodology" and by inserting the phrase "of this Tariff" after the phrase "Schedule 16".
2.28 New Section 4.9 is added to the Tariff and reads as follows:
Special Constraint Resource Service: The rates and/or methodology that shall apply to Transmission Customers for this service are described in Schedule 19 of this Tariff and Market Rule 1.
2.29 Section 5 (Open Access Same-Time Information System) is amended by substituting the phrase "Firm Internal Point-To- Point Service, for the interconnection of a new or materially changed generating unit or a new or materially changed interconnection to another Control Area or new Regional Network Service or an Elective Upgrade" for the phrase "firm transmission service" and by substituting the phrase "33, 44 and 50" for the phrase "33 and 44".
2.30 In Sections 6.2 (Alternative Procedures for Requesting
Transmission Service - Local Furnishing Bonds), 6.3
(Alternative Procedures for Requesting Transmission Service
- Other Tax-Exempt Bonds), and 12.1 (Internal Dispute
Resolution Procedures), the references to "Management
Committee" are amended to read "Participants Committee".
2.31 Section 11 (Creditworthiness) is amended by inserting the phrase ", and the Financial Assurance Policy for Non- Participant FTR Customers set forth in Attachment O," immediately after the phrase "Attachment M", and by inserting the phrase ", and shall be binding upon Non- Participant Transmission Customers and Non-Participant FTR Customers" immediately after the phrase "non-payment" in the final sentence.
Part II -
Regional Network Service
(Network Integration Transmission Service)
3.1 Section 14 is amended to read as follows:
Nature of Regional Network Service: Regional Network Service or Network Integration Transmission Service is the service over the PTF pursuant to Parts II and VI of this Tariff which is provided to Network Customers to serve their loads. It includes transmission service for the delivery to a Network Customer of its energy and capacity in Network Resources and delivery to or by Network Customers of energy and capacity in NEPOOL Market transactions. When an External Transaction purchase is submitted by the Transmission Customer and is scheduled in the Real-Time Energy Market, the submission shall be deemed a request for Transmission Service and the System Operator shall generate a reservation for the Transmission Service over the PTF equal to the transaction's schedule set at the beginning of the scheduling period. This reservation amount shall be the basis for the Reserved Capacity. Each Participant or Non- Participant which has a load in the NEPOOL Control Area shall pay for such Regional Network Service under the terms of Section 16.
3.2 Section 16 (Payment for Regional Network Service) is amended by replacing the phrase "applicable congestion or other uplift charge" with the phrase "charges and/or costs", and by replacing the phrase "Sections 24, 25A and 25B of this Tariff" with the phrase "Market Rule 1".
Part III -
Through or Out Service; Internal
Point-To-Point Service; MTF Service
4.1 The introductory paragraph following the heading for Part III is amended to read as follows:
Point-To-Point Transmission Service as Through or Out Service or Internal Point-To-Point Service or MTF Service will be provided during and after the Transition Period pursuant to the applicable terms and conditions of Part III, Part V and Schedule 18 of the Tariff. When an External Transaction sale or a Through Service transaction is submitted by the Transmission Customer and is scheduled in the Real-Time Energy Market, the submission shall be deemed a request for Point-To-Point Transmission Service and the System Operator shall generate a reservation for the Transmission Service over the PTF equal to the transaction's schedule set at the beginning of the scheduling period. This reservation amount shall be the basis for the Reserved Capacity. The Transmission Customer shall pay for its Reserved Capacity under the terms of Section 20, Section 21 or Section 22A, whichever is applicable.
4.2 Section 18.2 (Use of Through or Out Service) is amended by deleting the phrase "as Firm or Non Firm Point-To-Point Transmission Service" immediately after the phrase "Through or Out Service" and deleting the phrase "Unit Contract Entitlement or System Contract transaction with respect to a" immediately after the phrase "for the transmission of any".
4.3 Section 20 is amended to read as follows:
Payment for Through or Out Service: Each Participant or Non- Participant which takes Through or Out Service shall pay to NEPOOL a charge per Kilowatt of Reserved Capacity based on an annual rate (the "T or O Rate") which shall be the Pool PTF Rate. The Transmission Customer shall also be obligated to pay any ancillary service charges and any charges required to be paid pursuant to Market Rule 1. The rate per hour for Through or Out Service shall be the annual Pool PTF Rate divided by 8760. The Pool PTF Rate shall be the Rate determined annually in accordance with paragraph (2) of Schedule 8.
4.4 The first paragraph of Section 21 (Payment for Internal Point-To-Point Service) is amended to read as follows:
Each Participant or Non-Participant which takes firm or non- firm Internal Point-To-Point Service shall pay to NEPOOL a charge per Kilowatt of Reserved Capacity based on an annual rate (the "IPTP Charge") which shall be the Internal Point- To-Point Service Rate; provided that if a rate which is derived from the annual incremental cost, not otherwise borne by the Transmission Customer or a Generator Owner, of any new facilities or upgrades that would not be required but for the need to provide the requested service is greater than the Pool PTF Rate, the IPTP Charge shall be the higher of such amounts. The Transmission Customer shall also be obligated to pay any ancillary service charges and any other charges required to be paid pursuant to Market Rule 1. The charge for firm Internal Point-To-Point Service shall be as follows:
Part IV - Service During the Transition Period; Excepted Transactions
5.1 The heading for Part IV is amended to read as follows:
Service During the Transition Period; Excepted Transactions
5.2 Section 25 (Excepted Transactions) is amended by: (1)
replacing each reference to the "NEPOOL Transmission System"
to read "PTF"; (2) deleting the phrase "but except as
otherwise provided in Section 25A or 25B of this Tariff" in
the first sentence; (3) changing the reference to
"Management Committee" to read "Participants Committee"; (4)
substituting the word "The" in place of the phrase "Except
as otherwise provided in Section 25A or 25B below, the" in
the third sentence of subsection (3)(c); (5) deleting the
phrase "except as otherwise provided in Sections 25A or 25B
below, and" from the fourth sentence in subsection (3)(c);
(6) replacing the fifth sentence in subsection (3)(c) with
the sentence "For the purpose of determining transmission
priorities under this Tariff, (i) internal Excepted
Transactions shall have the same transmission priority as
Firm Point-To-Point Transmission Service transactions for
resources in existence on the effective date of this Tariff
which are effected as Regional Network Service or as
Internal Point-To-Point Service (ii) and Excepted
Transactions which are External Transactions listed in
Attachment G-3 shall have transmission priority in
accordance with Section 25F"; (7) deleting the phrase
"except as therein provided in Sections 25A or 25B below"
from the sixth sentence in subsection (3)(c); (8) inserting
the word "transmission" in front of the first occurrence of
the word "priority" in the sixth sentence in subsection
(3)(c); and (9) by inserting the sentence "Section 25 F
shall apply for the purposes of scheduling and curtailment
of Excepted Transactions that are also External
Transactions" at the end of the Section.
Part IVA - Congestion Management on the NEPOOL Transmission System
6.1 A new Part IVA is added to read as follows:
IVA. CONGESTION MANAGEMENT ON THE NEPOOL TRANSMISSION SYSTEM
25A Congestion Costs and Congestion Revenue
When Congestion exists, the Congestion Costs shall be reflected in Locational Marginal Prices calculated in accordance with Market Rule 1. Congestion Cost shall be recovered from Non-Participant Transmission Customers taking service under the Tariff and from Participants pursuant to Market Rule 1. Transmission Congestion Revenue shall be collected and disbursed in accordance with Market Rule 1.
25B Financial Transmission Rights
A system of Financial Transmission Rights shall be implemented pursuant to Sections 5 and 7 of Market Rule 1.
25C Auction Revenue Rights and Qualified Upgrade Awards
A system of Auction Revenue Rights and Qualified Upgrade Awards shall be implemented pursuant to Appendix C of Market Rule 1.
25D Scheduling and Curtailment Rules for External Transactions
For purposes of scheduling and curtailment of External Transactions over interconnections between the NEPOOL Control Area and neighboring Control Areas, the following rules shall apply:
(a) External Transaction sales and purchases that
(i) are supported by those service agreements
referenced in Attachment G-3 of this Tariff, (ii)
have not opted for Auction Revenue Rights
consideration under applicable NEPOOL System
Rules, and (iii) have been submitted into the Real-
Time Energy Market prior to noon the day before
the Operating Day as a Self-scheduled External
Transaction ("real-time without price") at an
External Node referenced in Attachment G-3 shall
be assigned the highest transmission priority when
compared to other External Transaction purchases
or sales at that node having the same offer price
or bid price. In the event that the transfer
limit for a given external interface does not
allow all Excepted Transactions submitted over
that interface to flow, they shall be scheduled or
curtailed on a pro-rata basis. For External
Transactions referenced in Attachment G-3 that
also require an advance physical reservation
associated with a MTF or Non-PTF external
interface, the MTF or Non-PTF transmission
priority shall take precedence over the above
language for the purposes of scheduling and
curtailment under Sections 25F(c) and 25F(d),
respectively;
(b) For external interfaces where advance physical reservations are not required (i.e., external interfaces solely made up of PTF, such as the AC facilities that make up the New York/ New England interface), scheduling and curtailment of External Transactions shall be based on economic merit order in accordance with NEPOOL System Rules. In the case of a tie within economic merit, transmission priority and then Real-Time Energy Market timestamp shall be used as tiebreakers. With the exception of Section 25F(a), all transactions crossing external interfaces not requiring advance physical reservations shall have equal transmission priority;
(c) For external interfaces where advance physical reservations are required (i.e., external interfaces made up of MTF or Non-PTF), scheduling of External Transactions which satisfy the reservation requirements for service shall be based on economic merit order in accordance with NEPOOL System Rules. In the case of a tie within economic merit, transmission priority shall be used as a tiebreaker. Relative to a given interface, transmission priority is based on the priority rights of the associated MTF or Non-PTF transmission reservation. In the case of a tie within a category of transmission service: (i) transactions within a given sub-category of non- firm transmission priority shall be scheduled on the basis of their Real-Time Energy Market timestamp order, and (ii) transactions with firm transmission priority shall be scheduled on a pro- rata basis;
(d) For external interfaces where advance physical reservations are required (i.e., external interfaces made up of MTF or Non-PTF), curtailments resulting from a reduction in total transfer capability shall be based on transmission priority of the associated MTF or Non-PTF transmission reservation to the extent possible. In the case of a tie within a category of transmission service, (a) transactions within a given sub-category of non-firm transmission service shall be curtailed on the basis of Real- Time Energy Market timestamp order, and (b) transactions with firm transmission service shall be curtailed on a pro-rata basis;
(e) In instances of an External Transaction scheduled against multiple reservations on a MTF or Non-PTF external interface, the lowest transmission priority of the associated reservations shall apply;
(f) The transmission priority for wheel-through transactions will be based on the transmission service utilized at the restricted external interface as indicated by the transmission reservation;
(g) Transmission Customers wishing to schedule External Transactions shall comply with applicable NEPOOL System Rules;
(h) Scheduling and curtailment of External Transactions shall be conducted in accordance with the specifications of the NEPOOL System Rules and all applicable tariffs;
(i) External Transactions scheduled in the Real- Time Energy Market shall continue to be implemented during periods of Congestion, except as may be necessary to respond to emergencies;
(j) The System Operator will redispatch all Resources subject to its control, pursuant to Market Rule 1, in order to meet load and to accommodate External Transactions. Participants and Transmission Customers will be charged for the Congestion Cost and any other costs associated with such redispatch in accordance with Market Rule 1. Pursuant to such redispatch, in the event the System Operator exercises its right to effect a Curtailment, in whole or part, of Through or Out Service or Internal Point-To-Point Transmission Service or MTF Service, no credit or other adjustment shall be provided as a result of the Curtailment with respect to the charge payable by the customer;
(k) The System Operator will furnish to the Delivering Party's system operator hour-to-hour schedules equal to those furnished by the Receiving Party (unless reduced for losses) and will deliver the capacity and energy provided by such schedules;
(l) Should the Transmission Customer, Delivering Party or Receiving Party revise or terminate any schedule, such party shall immediately notify the System Operator, and the System Operator will have the right to adjust accordingly the schedule for capacity and energy to be received and to be delivered;
(m) The System Operator shall apply the above-listed rules consistent with maintaining the reliability of the NEPOOL Transmission System; and
(n) The System Operator shall develop and post procedures on its Internet website reflecting the above-listed External Transaction rules.
Part V - Point-To-Point Transmission Service
7.1 The preamble to Part V is amended to read as follows:
Point-To-Point Transmission Service whether by Participants or Non-Participants, for all new transfers to be effected as Internal Point-To-Point Service, MTF Service or as Through or Out Service, shall be carried out pursuant to the applicable terms and conditions of Part III, Part V and Schedule 18 of the Tariff. Point-To-Point Transmission Service is the service required for the receipt of capacity and/or energy at designated Point(s) of Receipt and the transmission of such capacity and/or energy to designated Point(s) of Delivery. MTF Service shall be reserved on the OASIS separately pursuant to Schedule 18. Priority of MTF Service shall be in accordance with the provisions of Schedule 18 of the Tariff and as provided below.
7.2 Section 26 (Scope of Application of Part V) is amended by replacing the reference to Section "31.3" with a reference to Section "32.4", and by deleting the last sentence.
7.3 The following new Section 26A is added:
26A Nature of Through or Out Service
Preamble: Advance reservations will not be required for Through or Out Service under this Tariff. However, other advance reservations are required for Internal Point-To-Point Service and MTF Service and may be required under other tariffs applicable to certain external interfaces within the NEPOOL Control Area. When an External Transaction sale or Through Service transaction is submitted by the Transmission Customer and is scheduled in the Real-Time Energy Market, the submission shall be deemed a request for Through or Out Service and the System Operator shall generate a reservation for Through or Out Service equal to the transaction's schedule set at the beginning of the scheduling period; this reservation amount shall be the basis for the Reserved Capacity. The Transmission Customer shall pay for its Reserved Capacity under the terms of Section 20.
26A.1 Term: The term of Through or Out Service
shall be one hour increments in conjunction with
External Transactions scheduled in the Real-Time
Energy Market.
26A.2 Transmission Priority: All Through or Out
Service offered under this Tariff will be deemed
to have the same transmission priority. Through
or Out Service will have transmission priority
equal to Long-Term Firm Internal Point-To-Point
Service, Native Load Customers, Network Customers
and customers for Excepted Transactions. In the
event the PTF and MTF are constrained,
transmission priorities shall be established
separately for the PTF and MTF, respectively.
26A.3 Use of Through or Out Service by the
Participants That Own PTF: A Transmission
Provider that owns PTF will be subject to the
rates, terms and conditions of this Tariff when
making Third-Party Sales to be transmitted as
Through or Out Service under (i) agreements
executed after November 1, 1996 or (ii) agreements
executed on or before November 1, 1996 to the
extent that the Commission requires them to be
unbundled, by the date specified by the
Commission. A Transmission Provider that owns PTF
will maintain separate accounting, pursuant to
Section 8, for any use of Through or Out Service
to make Third-Party Sales to the extent not paid
for under this Tariff.
26A.4 Service Agreements: A standard form Point-To-
Point Transmission Service Agreement (Attachment
A) will be offered to an Eligible Customer when it
submits a Completed Application for Point-To-Point
Transmission Service to be transmitted pursuant to
this Tariff. Executed Service Agreements that
contain the information required under this Tariff
will be filed with the Commission in compliance
with applicable Commission regulations.
26A.5 Transmission Customer Obligations for
Facility Additions or Redispatch Costs: The
System Operator will redispatch all Resources
subject to its control, pursuant to Market Rule 1,
in order to meet load and to accommodate External
Transactions. Participants and Transmission
Customers will be charged for the Congestion Costs
and any other costs associated with such
redispatch in accordance with Market Rule 1.
26A.6 Classification of Through or Out Service:
Deliveries will be provided from the Point(s) of
Receipt to the Point(s) of Delivery. Each Point
of Receipt at which transmission capacity is
reserved for Through or Out Service by the
Transmission Customer shall be set forth in the
schedule submitted in accordance with Market Rule
1 and NEPOOL System Rules. When an External
Transaction sale or a Through Service transaction
is submitted by the Transmission Customer and is
scheduled in the Real-Time Energy Market, the
submission shall be considered deemed a request
for Through or Out Service and the System Operator
will generate a reservation for the Through or Out
Service equal to the transaction's schedule set at
the beginning of the scheduling period; this
reservation amount shall be the basis for the
Reserved Capacity. The Transmission Customer will
be billed and shall pay for its Reserved Capacity
under the terms of Section 20.
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7.4 The heading for Section 27 is amended to read as follows:
Nature of Firm Internal Point-To-Point Service and Firm MTF Service
7.5 Section 27.1 (Term) is amended by inserting the word "Internal" immediately before, and deleting the word "Transmission" and inserting the phrase "Service and Firm MTF" immediately after, the term "Point-To-Point".
7.6 Section 27.2 (Reservation Priority) is amended by inserting the word "transmission" immediately before the word "priority" at each occurrence in the heading and the section, by replacing the phrase "NEPOOL Transmission System" with the term "PTF", by replacing the phrase "Point- To-Point Transmission" with the phrase "Internal Point-To- Point" at each occurrence, and by deleting the ninth sentence in its entirety.
7.7 Section 27.3 (Use of Firm Point-To-Point Service by the Participants That Own PTF) is amended by inserting the word "Internal" before the phrase "Point-To-Point" in the heading and at each occurrence in the Section, and by deleting the word "Transmission" after the phrase "Point-To-Point" at each occurrence.
7.8 Section 27.4 (Service Agreements) is amended by inserting the word "Internal" before the phrase "Point-To-Point" at each occurrence, by replacing the word "Transmission" with the phrase "Service Agreement of Firm MTF" after the first occurrence of the phrase "Point-To-Point", and by replacing the word "Transmission" with the phrase "Service or Long-Term or Short- Term Firm MTF" after the second occurrence of the phrase "Point- to-Point".
7.9 Section 27.5 is amended to read as follows:
Transmission Customer Obligations for Facility Additions or Redispatch Costs: In cases where it is determined that the PTF is not capable of providing new Firm Internal Point-To- Point Service without (1) degrading or impairing the reliability of service to Native Load Customers, Network Customers, customers taking service for Excepted Transactions and other Transmission Customers taking Firm Internal Point-To-Point Service, or (2) interfering with a Participant's ability to meet prior firm contractual commitments to others, the Transmission Providers will be obligated to arrange to expand or upgrade PTF for Long-Term Firm Internal Point-To-Point Service pursuant to the terms of Section 33. The Transmission Customer must agree to compensate the Transmission Providers or any other entity designated to effect construction through the System Operator for any necessary transmission facility additions or upgrades pursuant to the terms of Section 39. The System Operator will redispatch all Resources subject to its control, pursuant to Market Rule 1, in order to meet load and to accommodate External Transactions. Participants and Transmission Customers will be charged for the Congestion Costs and any other costs associated with such redispatch in accordance with Market Rule 1. Any addition or upgrade or Direct Assignment Facilities costs to be charged to the Transmission Customer on an incremental basis under this Tariff will be specified in the Service Agreement prior to initiating service.
7.10 Section 27.6 is amended to read as follows:
Curtailment of Firm Transmission Service: The System Operator will redispatch all Resources subject to its control, pursuant to Market Rule 1, in order to meet load and to accommodate External Transactions. Resources within the NEPOOL Control Area using Firm Internal Point-to- Point Service shall be curtailed based economic merit order in accordance with NEPOOL System Rules, and shall have no physical scheduling or dispatch rights. External Transactions using Firm MTF Service shall be curtailed pursuant to Section 25F of this Tariff. Participants and Transmission Customers will be charged for the Congestion Cost and any other costs associated with such redispatch in accordance with Market Rule 1. Pursuant to such redispatch, in the event the System Operator exercises its right to effect a Curtailment, in whole or part, of Firm Internal Point-To-Point Transmission Service or Firm MTF Service, no credit or other adjustment shall be provided as a result of the Curtailment with respect to the charge payable by the Customer.
7.11 Section 27.7 is amended to read as follows:
Classification of Firm Internal Point-To-Point Service and Firm MTF Service:
(a) A Transmission Customer taking Firm Internal Point- To-Point Service may (1) change its Points of Receipt and Delivery to obtain service on a non- firm basis consistent with the terms of Section 36.1 or (2) request a modification of the Points of Receipt or Delivery on a firm basis pursuant to the terms of Section 36.2; provided that if any Transmission Provider or its designee constructed new facilities or upgraded facilities to accommodate the original firm service, such Transmission Provider or its designee shall continue to be compensated for its facility costs by the Transmission Customer.
(b) [OMITTED]
(c) Parties requesting Firm Internal Point-To-Point
Service and Firm MTF Service for the transmission
of firm power do so with the full realization that
such service is subject to Curtailment under the
terms of this Tariff and that the System Operator
will redispatch all Resources subject to its
control, pursuant to Market Rule 1, in order to
meet load and to accommodate External
Transactions. Participants and Transmission
Customers will be charged for the Congestion Costs
and any other costs associated with such
redispatch in accordance with Market Rule 1. Each
Point of Receipt at which firm transmission
capacity is reserved for Long-Term Firm Internal
Point-To-Point Service or Long-Term Firm MTF
Service by the Transmission Customer shall be set
forth in the Service Agreement for such Service
along with a corresponding capacity reservation
associated with each Point of Receipt. Points of
Receipt and corresponding capacity reservations
shall be as mutually agreed upon by the System
Operator and the Transmission Customer for Short-
Term Firm Internal Point-To-Point Service or Short-
Term Firm MTF Service. Each Point of Delivery at
which firm transmission capacity is reserved for
Long-Term Firm Internal Point-To-Point Service or
Short-Term Firm MTF Service by the Transmission
Customer shall be set forth in the Service
Agreement for such Service along with a
corresponding capacity reservation associated with
each Point of Delivery. Points of Delivery and
corresponding capacity reservations shall be as
mutually agreed upon by the System Operator and
the Transmission Customer for Short-Term Firm
Internal Point-To-Point Service or Short-Term Firm
MTF Service. The greater of either (1) the sum of
the capacity reservations at the Point(s) of
Receipt, or (2) the sum of the capacity
reservations at the Point(s) of Delivery shall be
the Transmission Customer's Reserved Capacity.
The Transmission Customer will be billed for its
Reserved Capacity under the terms of Section 21 or
Section 22A, whichever is applicable. The
Customer's Use may not exceed its firm capacity
reserved at each Point of Receipt and each Point
of Delivery except as otherwise specified in
Section 36. In the event that the Use by a
Transmission Customer (including Third-Party Sales
by the Participants) exceeds that Transmission
Customer's Reserved Capacity at any Point of
Receipt or Point of Delivery in any hour, it shall
pay 200% of the charge which is otherwise
applicable for each Kilowatt of the excess. In
addition, the System Operator will record all
instances in which a Transmission Customer's Use
exceeds that Transmission Customer's firm Reserved
Capacity, and if in any calendar year more than 10
such instances occur with respect to any single
Transmission Customer, then the System Operator
may require such Transmission Customer to apply
for additional Firm Internal Point-To-Point
Service under the Tariff in an amount equal to the
greatest amount of the excess of such Transmission
Customer's Use over its firm Reserved Capacity for
the remainder of that calendar year. Charges for
such additional Firm Internal Point-To-Point
Service will relate back to the first day of the
month following the month in which the System
Operator notifies such Transmission Customer that
it is subject to the provisions of this paragraph.
7.12 Section 27.8 is amended to read as follows:
Scheduling of Firm Transmission Service: The System
Operator will dispatch all Resources subject to its control,
pursuant to Market Rule 1, in order to meet load and to
accommodate External Transactions. Resources within the
NEPOOL Control Area using Firm Internal Point-To-Point
Service shall be dispatched based on economic merit order in
accordance with NEPOOL System Rules and shall have no
physical scheduling or dispatch. External Transactions
using Firm MTF Service shall be dispatched pursuant to
Section 25F of this Tariff. Participants and Transmission
Customers will be charged for the Congestion Costs and any
other costs associated with such dispatch in accordance with
Market Rule 1.
7.13 The heading of Section 28 is amended to read as follows:
Nature of Non-Firm Internal Point-To-Point Service and Non- Firm MTF Service
7.14 Section 28.2 "Reservation Priority" is amended to read as follows:
Reservation and Transmission Priority: Non-Firm Internal Point-To-Point Service and Non-Firm MTF Service shall be available from transmission capability in excess of that needed for reliable service to Native Load Customers, Network Customers, customers for Excepted Transactions and other Transmission Customers taking Through or Out Service, Long-Term and Short-Term Firm Internal Point-To-Point Service and Long-Term and Short-Term Firm MTF Service. A higher reservation priority will be assigned to reservations with a longer duration of service. In the event the PTF and MTF are constrained, reservation priorities shall be established separately for the PTF and MTF, respectively. Competing requests of equal duration over PTF will be prioritized based on the highest price offered by the Eligible Customer for the Transmission Service, or in the event the price for all Eligible Customers is the same, will be prioritized on a first-come, first-served basis i.e., in the chronological sequence in which each Customer has reserved service. Eligible Customers that have already reserved shorter term service over PTF have the right of first refusal to match any longer term reservation before being preempted. A longer term competing request over PTF for Non-Firm Internal Point-To-Point Service will be granted if the Eligible Customer with the right of first refusal does not agree to match the competing request: (a) immediately for hourly Non-Firm Internal Point-To-Point Service after notification by the System Operator; and (b) within 24 hours (or earlier if necessary to comply with the scheduling deadlines provided in Section 28.6) for Non-Firm Internal Point-To-Point Service other than hourly transactions using Non-Firm Internal Point-To-Point Service after notification by the System Operator.
Non-Firm Internal Point-To-Point Service over PTF to secondary Point(s) of Receipt and Point(s) of Delivery will have the lowest transmission priority under this Tariff. As between or among transactions that require the use of both the PTF and MTF, the transmission priority for such competing Internal Point-To-Point Service requests over the PTF shall be determined by the transmission priority held by the Transmission Customers over MTF.
7.15 Section 28.3 is amended by inserting the word "Internal" immediately after the phrase "Non-Firm".
7.16 Section 28.4 (Service Agreements) is amended by inserting the word "Internal" immediately before the phrase "Point-To- Point" and by deleting the word "Transmission" at each occurrence.
7.17 Section 28.5 is amended to read as follows:
Classification of Non-Firm Internal Point-To-Point Service and Non-Firm MTF Service: Non-Firm Internal Point-To-Point Service and Non-Firm MTF Service shall be offered under applicable terms and conditions contained in Part III of this Tariff. The NEPOOL Participants undertake no obligation under this Tariff to plan the PTF in order to have sufficient capacity for Non-Firm Internal Point-To- Point Service. Parties requesting Non-Firm Internal Point- To-Point Service and Non-Firm MTF Service for the transmission of firm power do so with the full realization that such service is subject to availability and to Curtailment under the terms of this Tariff and that the System Operator will redispatch all Resources subject to its control, pursuant to Market Rule 1, in order to meet load and to accommodate External Transactions. Participants and Transmission Customers will be charged for the Congestion Costs and any other costs associated with such redispatch in accordance with Market Rule 1. In the event that the Use by a Transmission Customer (including Third-Party Sales by a Participant) exceeds that Transmission Customer's non- Reserved Capacity at any Point of Receipt or Point of Delivery, it shall pay 200% of the charge which is otherwise applicable for each Kilowatt of the excess. In addition, the System Operator will record all instances in which a Transmission Customer's Use exceeds that Transmission Customer's non-firm Reserved Capacity, and if in any calendar year more than 10 such instances occur with respect to any single Transmission Customer, then the System Operator may require such Transmission Customer to apply for additional Non-Firm Internal Point-To-Point Service under the Tariff in an amount equal to the greatest amount of the excess of such Transmission Customer's Use over its non-firm Reserved Capacity for the remainder of that calendar year. Charges for such additional Non-Firm Internal Point-To-Point Service will relate back to the first day of the month following the month in which the System Operator notifies such Transmission Customer that it is subject to the provisions of this paragraph.
(a) Non-Firm Internal Point-To-Point Service and Non-Firm MTF Service shall include transmission of energy on an hourly basis and transmission of scheduled short-term capacity and energy on a daily, weekly or monthly basis, but not to exceed one month's reservation for any one Application.
(b) Each Point of Receipt at which non-firm transmission capacity is reserved by the Transmission Customer shall be set forth in the Application along with a corresponding capacity reservation associated with each Point of Receipt.
7.18 Section 28.6 is amended to read as follows:
Scheduling of Non-Firm Internal Point-To-Point Service and Non-Firm MTF Service: The System Operator will dispatch all Resources subject to its control, pursuant to Market Rule 1, in order to meet load and to accommodate External Transactions. Resources within the NEPOOL Control Area using Non-Firm Internal Point-To-Point Service shall be dispatched based on economic merit order in accordance with NEPOOL System Rules and shall have no physical scheduling or dispatch rights. External Transactions using Non-Firm MTF Service shall be dispatched pursuant to Section 25F of this Tariff. Participants and Transmission Customers will be charged for the Congestion Costs and any other costs associated with such dispatch in accordance with Market Rule 1.
7.19 Section 28.7 is amended to read as follows:
Curtailment of Non-Firm Internal Point-To-Point Service and Non-Firm MTF Service: The System Operator will redispatch all Resources subject to its control, pursuant to Market Rule 1, in order to meet load and to accommodate External Transactions. Resources within the NEPOOL Control Area using Non-Firm Internal Point-To-Point Service shall be curtailed based on economic merit order in accordance with NEPOOL System Rules and shall have no physical scheduling or dispatch rights. External Transactions using Non-Firm MTF Service shall be curtailed pursuant to Section 25F of this Tariff. Participants and Transmission Customers will be charged for the Congestion Costs and any other costs associated with such redispatch in accordance with Market Rule 1. Pursuant to such redispatch, in the event the System Operator exercises its right to effect a Curtailment, in whole or in part, of Non-Firm Internal Point- To-Point Transmission Service, or Non-Firm MTF Service, no credit or other adjustment shall be provided as a result of the Curtailment with respect to the charge payable by the Customer.
7.20 Section 29.1 is amended to read as follows:
General Conditions: Firm Internal Point-To-Point Service on the PTF is available to any Transmission Customer that has met the applicable requirements of Section 31. Through or Out Service on the PTF shall be available to any Transmission Customer that has met the applicable requirements of Section 31A.
7.21 Section 29.2 (Determination of Available Transmission Capability) is amended by deleting the last sentence.
7.22 Section 29.4 is amended to read as follows:
Obligation to Provide Transmission Service that Requires Expansion or Modification of the Transmission System: If a Transmission Customer requests that the PTF be expanded or modified, one or more Transmission Providers or other entities will be designated to use due diligence to expand or modify the PTF to increase transfer capability, provided that the Transmission Customer agrees to compensate the Transmission Providers or other entities that will be responsible for the construction of any new facilities or upgrades for the costs of such new facilities or upgrades pursuant to the terms of Section 39. The System Operator and the designated Transmission Providers or other entities will conform to Good Utility Practice in determining the need for new transmission facilities or upgrades and in coordinating the design and construction of such facilities. This obligation applies only to those facilities that the designated Transmission Providers or other entities have the right to expand or modify.
7.23 Section 29.5 is amended to read as follows:
Deferral of Service: Any Qualified Upgrade Award associated with new transmission facilities or upgrades shall be subject to completion of construction of those transmission facilities and upgrades and to such upgrades being placed in service.
7.24 Section 29.6 is amended to read as follows:
Real Power Losses: Real power losses are associated with all transmission service. The Transmission Provider is not obligated to provide real power losses. The cost of PTF losses shall be recovered through the Loss Component of the Locational Marginal Prices pursuant to Market Rule 1. Real power losses across MTF shall be allocated in accordance with Schedule 18 of this Tariff.
7.25 Section 29.7 (Load Shedding) is amended by replacing the phrase "NEPOOL Transmission System" with the term "PTF".
7.26 Section 30.1 is amended to read as follows:
Conditions Required of Transmission Customers: Through or Out Service, Firm Internal Point-To-Point Service and Firm MTF Service will be provided only if the following conditions are satisfied by the Transmission Customer:
a. The Transmission Customer has pending a Completed
Application for service;
b. In the case of a Non-Participant, the Transmission
Customer meets the creditworthiness criteria set
forth in Section 11 and the financial assurance
requirements set forth in Attachment M of this Tariff;
c. The Transmission Customer will have arrangements
in place for any other transmission service
necessary to effect the delivery from the generating
source to the Point of Receipt prior to the time service
under the Tariff commences;
d. The Transmission Customer agrees to pay for any
facilities or upgrades constructed or any
Congestion Costs or other redispatch costs chargeable
to such Transmission Customer under this Tariff and
Market Rule 1, whether or not the Transmission Customer
takes service for the full term of its reservation;
e. The Transmission Customer has executed a Service
Agreement or has agreed to receive service
pursuant to Section 29.3; and
f. The Transmission Customer must submit External
Transactions in accordance with the
applicable NEPOOL System Rules and will receive
Transmission Service in conjunction with the scheduled
energy in the Real-Time Energy Market in accordance with
Market Rule 1.
7.27 Section 31 (Procedures for Arranging Firm Point-To-Point Transmission) is amended by inserting the word "Internal" before the phrase "Point-To-Point" and replacing the word "Transmission" with the phrase "Service and Firm MTF".
7.28 Section 31.1 (Application) is amended by inserting the word "Internal" before the first occurrence of the phrase "Point- To-Point", by replacing the word "Transmission" with the phrase "Service and Firm MTF", by replacing the word "NEPOOL" with the phrase "the System Operator", and by inserting the word "reservation" before the word "priority" in the final sentence.
7.29 Section 31.2(viii) is amended by replacing the phrase "NEPOOL Transmission System" with the word "PTF".
7.30 Section 31.3 (Deposit) is amended by inserting the word "Internal" before the phrase "Point-To-Point" at each occurrence, by replacing the word "Transmission" after the phrase "Point-To-Point" with the phrase "Service or Firm MTF" at each occurrence, and by replacing the phrase "Administrative Costs" with the phrase "administrative costs".
7.31 Section 31.4 (Notice of Deficient Application) is amended by replacing the phrase "Administrative Costs" with the phrase "administrative costs", and by inserting the word "reservation" immediately before the word "priority" in the last sentence.
7.32 Section 31.5 (Response to a Completed Application) is amended by inserting the word "Internal" before the phrase "Point-To-Point" and by replacing the word "Transmission" after the phrase "Point-To-Point" with the phrase "Service or Firm MTF".
7.33 Section 31.6 (Execution of Service Agreement) is amended by replacing the phrase "Administrative Costs" with the phrase "administrative costs".
7.34 Section 31.7 (Extensions for Commencement of Service) is amended by inserting the word "Internal" before the phrase "Point-To-Point" throughout, and by replacing the word "Transmission" after the phrase "Point-To-Point" with the phrase "Service or Firm MTF" throughout.
7.35 The heading for Section 32 is amended to read as follows:
Procedures for Arranging Non-Firm Internal Point-To-Point Service and Non-Firm MTF Service
7.36 Section 32.1 (Application) is amended by inserting the word "Internal" before the phrase "Point-To-Point" and by replacing the word "Transmission" after the phrase "Point-To-Point" with the phrase "Service or Non-Firm MTF".
7.37 The heading for Section 32.3 is amended to read as follows:
Reservation of Non-Firm Internal Point-To-Point Service and Non-Firm MTF Service
7.38 The following new sections are added in the appropriate numerical order:
32A Procedures for Arranging Through or Out Service:
Through or Out Service shall be provided in conjunction
with hourly scheduled External Transactions submitted
to the Real-Time Energy Market and in accordance with
Section 25F of the Tariff and the applicable NEPOOL
System Rules. Non-Participants intending to request
Transmission Service through the submittal of an
External Transaction shall first complete the
requirements in this Section 32A of the Tariff.
32A.1 Application: A request for Through or Out Service
for a Non-Participant shall be made in an Application,
delivered to ISO New England Inc., One Sullivan Road,
Holyoke, MA 01040-2841 or such other address as may be
specified from time to time. The request should be
delivered at least sixty days in advance of the
calendar month in which service is requested to
commence. The System Operator will consider requests
for such service on shorter notice when practicable.
Transmission Service requests should be submitted by
transmitting the Completed Application to the System
Operator by mail or telefax. Each of these methods
will provide a time-stamped record for establishing the
reservation priority of the Application.
32A.2 Completed Application: A Completed Application
for Through or Out Service for a Non-Participant shall
provide all of the information included in 18 C.F.R.
2.20 including but not limited to the following:
(i) The identity, address, telephone number and
facsimile number of the entity requesting service;
(ii) A statement that the entity requesting service is,
or will be upon commencement of service, an
Eligible Customer under this Tariff;
(iii) The location of the Point(s) of Receipt and
Point(s) of Delivery and the identities of the
Delivering Parties and the Receiving Parties;
(iv) The location of the generating facility(ies)
supplying the capacity and energy, and the
location of the load ultimately served by the
capacity and energy transmitted. The System
Operator will treat this information as
confidential in accordance with the NEPOOL
information policy except to the extent that
disclosure of this information is required by this
Tariff, by regulatory or judicial order, or for
reliability purposes pursuant to Good Utility
Practice. The System Operator will treat this
information consistent with the standards of
conduct contained in 18 C.F.R. Part 37 of the
Commission's regulations;
(v) A description of the supply characteristics of the
capacity and energy to be delivered;
(vi) An estimate of the capacity and energy expected to
be delivered to the Receiving Party;
(vii) The Service Commencement Date and the term of
the requested transmission service; and
(viii) The transmission capacity requested for each
Point of Receipt and each Point of Delivery on the
PTF and/or MTF; customers may combine their
requests for service in order to satisfy the
minimum transmission capacity requirement.
The System Operator will treat this information
consistent with the standards of conduct contained in
18 C.F.R. Part 37 of the Commission's regulations.
32A.3 Deposit: A Completed Application for Through or Out
Service by a Non-Participant shall also include a
deposit of one month's charge based on the estimate of
the capacity and energy expected to be delivered to the
Receiving Party. If the Application is rejected by the
System Operator because it does not meet the conditions
for service as set forth herein, or in the case of
requests for service arising in connection with losing
bidders in a request for proposals ("RFP"), the deposit
will be returned with Interest, less any reasonable
administrative costs incurred by the System Operator or
any affected Participants in connection with the review
of the Application. The deposit also will be returned
with Interest less any reasonable administrative costs
incurred by the System Operator or any affected
Participants if the new facilities or upgrades needed
to provide the service cannot be completed. If an
Application is withdrawn or the Eligible Customer
decides not to enter into a Service Agreement for the
Service, the deposit will be refunded in full, with
Interest, less reasonable administrative costs incurred
by the System Operator or any affected Participants to
the extent such costs have not already been recovered
from the Eligible Customer. The System Operator will
provide to the Eligible Customer a complete accounting
of all costs deducted from the refunded deposit, which
the Eligible Customer may contest if there is a dispute
concerning the deducted costs. Deposits associated
with construction of new facilities or upgrades are
subject to the provisions of Section 33. If a Service
Agreement for Through or Out Service is executed, the
deposit, with interest, will be returned to the
Transmission Customer upon expiration or termination of
the Service Agreement. Applicable Interest will be
calculated from the day the deposit is credited to the
System Operator's account.
32A.4 Notice of Deficient Application: If an
Application fails to meet the requirements of this
Tariff, the System Operator will notify the entity
requesting service within fifteen days of the System
Operator's receipt of the Application of the reasons
for such failure. The System Operator will attempt to
remedy minor deficiencies in the Application through
informal communications with the Eligible Customer. If
such efforts are unsuccessful, the System Operator will
return the Application, along with any deposit (less
the reasonable administrative costs incurred by the
System Operator or any affected Participants in
connection with the Application), with Interest. Upon
receipt of a new or revised Application that fully
complies with the requirements of this Tariff, the
Eligible Customer will be assigned a new reservation
priority based upon the date of receipt by the System
Operator of the new or revised Application.
32A.5 Execution of Service Agreement: The System
Operator will notify the Eligible Customer as soon as
practicable but no later than thirty days after receipt
of the Completed Application, and will tender a Service
Agreement to the Eligible Customer. The service
agreement will allow the Eligible Non-Participant
Customer to submit External Transactions in accordance
with Market Rule 1 and the applicable NEPOOL System
Rules. Failure of an Eligible Customer to execute and
return the Service Agreement or request the filing of
an unexecuted Service Agreement pursuant to Section
29.3, within fifteen days after it is tendered by the
System Operator shall be deemed a withdrawal and
termination of the Application and any deposit (less
the reasonable administrative costs incurred by the
System Operator and any affected Participants in
connection with the Application) submitted will be
refunded with Interest. Nothing herein limits the
right of an Eligible Customer to file another
Application after such withdrawal and termination.
|
7.39 Section 33.1 is amended to read as follows:
Notice of Need for System Impact Study: A request for Through or Out Service will not normally require a System Impact Study. A request for Firm Internal Point-To-Point Service may require a System Impact Study. Also, an Eligible Customer may specifically request that the System Operator conduct a System Impact Study for an Elective Transmission Upgrade pursuant to Section 50.2 (a "Study Request"). After receiving a request for Firm Internal Point-To-Point Service or a request to study an Elective Transmission Upgrade, the System Operator will review the effect of the proposed service or upgrade on the reliability requirements of the PTF and the indirectly affected MTF facilities pursuant to meet existing and pending obligations of the Participants and Non-Participants, and the obligations of the particular Participants whose PTF or MTF facilities will be impacted by the proposed service and determine on a non-discriminatory basis whether a System Impact Study is needed. If the System Operator determines that a System Impact Study is necessary to accommodate the requested Firm Internal Point-To-Point Service, the System Operator will treat the request for Firm Internal Point-To- Point Service as a "Study Request". A description of the methodology for completing a System Impact Study is provided in Attachment D. After receiving a Request, the System Operator will within thirty days of receipt of a Study Request, tender a System Impact Study agreement in the form of Exhibit I to this Tariff, or in any other form that is mutually agreed to, pursuant to which the Eligible Customer shall agree to reimburse the System Operator and any affected Participants for performing the required System Impact Study. Before a Study Request is evaluated, the Eligible Customer shall execute the System Impact Study agreement and return it to the System Operator within fifteen days. If the Eligible Customer elects not to execute a System Impact Study agreement, its request shall be deemed withdrawn and its deposit (less the reasonable administrative costs incurred by the System Operator and any affected Participants in connection with the Application), will be returned with Interest.
7.40 Section 33.2 (System Impact Study Agreement and Cost Reimbursement) is amended by replacing the phrase "NEPOOL Transmission System and/or" with the phrase "PTF and indirectly affected", by inserting the phrase "of the customer request for Internal Point-To-Point Service or for an Elective Upgrade" after the term "MTF", by replacing the first occurrence of the word "service" with the phrase "a similar study" in subsection (ii), and by deleting the phrase "for service" immediately after the word "requests" in subsection (ii).
7.41 Section 33.3 is amended to read as follows:
System Impact Study Procedures: Upon receipt of an executed System Impact Study agreement, the System Operator and any affected Participants will use due diligence to complete the required System Impact Study within a sixty-day period. The System Impact Study shall identify the need for additional Direct Assignment Facilities or facility additions or upgrades required to comply with the Eligible Customer's request. In the event that the required System Impact Study cannot be completed within such time period, the System Operator will so notify the Eligible Customer and provide an estimated completion date along with an explanation of the reasons why additional time is required to complete the required study and an estimate of any increase in cost which will result from the delay. A copy of the completed System Impact Study and related work papers shall be made available to the Eligible Customer. The System Operator will use the same due diligence in completing the System Impact Study for an Eligible Customer that is a Non-Participant as it uses when completing studies for the Participants. The System Operator will notify the Eligible Customer immediately upon completion of the System Impact Study.
7.42 Section 33.4 is amended to read as follows:
Facilities Study Procedures: After a System Impact Study indicates that additions or upgrades to the PTF or indirectly affected MTF are needed to accommodate the Eligible Customer's Study Request, the System Operator, within thirty days of the completion of the System Impact Study, will tender to the Eligible Customer a Facilities Study agreement in the form of Attachment J to this Tariff, or in any other form that is mutually agreed to, which is to be entered into by the Eligible Customer and the System Operator and, if deemed necessary by the System Operator, by one or more affected Transmission Provider(s) and pursuant to which the Eligible Customer shall agree to reimburse the System Operator and any affected Transmission Providers or other entity designated by the System Operator for performing any required Facilities Study. If the Eligible Customer wants the System Operator to undertake the Facilities Study, the Eligible Customer shall execute the Facilities Study agreement and return it to the System Operator within fifteen days. If the Eligible Customer elects not to execute the Facilities Study agreement, its Study Request shall be deemed withdrawn and its deposit, if any (less the reasonable administrative costs incurred by the System Operator and any affected Participants in connection with the Application), will be returned with Interest. Upon receipt of an executed Facilities Study agreement, the System Operator and any affected Transmission Provider(s) or other designated entity will use due diligence to cause the required Facilities Study to be completed within a sixty-day period. If a Facilities Study cannot be completed in the allotted time period, the System Operator will notify the Eligible Customer and provide an estimate of the time needed to reach a final determination and any resulting increase in the cost, along with an explanation of the reasons that additional time is required to complete the study. When completed, the Facilities Study shall include a good faith estimate of (i) the cost of Direct Assignment Facilities to be charged to the Eligible Customer, or (ii) the Eligible Customer's appropriate share of the cost of any required additions or upgrades, and (iii) the time required to complete such construction. The Eligible Customer shall provide a letter of credit or other reasonable form of security acceptable to the Transmission Providers or other entities that will be responsible for the construction of the new facilities or upgrades equivalent to the costs of the new facilities or upgrades and consistent with relevant commercial practices, as established by the Uniform Commercial Code. In addition to the foregoing, each Facilities Study performed on or after the SMD Effective Date shall, if requested by the Transmission Customer, contain a non-binding estimate from the System Operator of the Qualified Upgrade Awards, if any, resulting from the construction of the new facilities. After completion of the transmission upgrade or expansion, the System Operator shall determine the Qualified Upgrade Awards, if any, resulting from the upgrade or expansion. The Transmission Customer shall be responsible for the cost of any study required to determine the Qualified Upgrade Awards.
7.43 Section 33.5 is amended by substituting the word Eligible in place of the second occurrence of the word "Transmission".
7.44 Section 33.6 is amended by replacing the phrase "NEPOOL Transmission System" with the term "PTF", and by deleting the phrase "in order to provide the requested Firm Point-To- Point Transmission Service" from the second sentence.
7.45 Section 33.8 is amended by replacing the phrase "Service Agreement" with the phrase "Study Request" at each occurrence.
7.46 The heading for Section 34 is amended by deleting the word "Firm".
7.47 Section 34.1 is amended by deleting the phrase "for Firm Point-To-Point Service" from the first sentence.
7.48 Section 34.2 (Alternatives to the Original Facility Additions) is amended by deleting the phrase "with its Completed Application" from the second sentence and by deleting the third sentence in its entirety.
7.49 Section 34.3 (Refund Obligation for Unfinished Facility Additions) is amended by deleting the phrase "and the requested service cannot be provided out of existing capability under the conditions of this Tariff" from the first sentence, and by replacing the phrase "Firm Point-To- Point Transmission Service" in the first sentence with the phrase "construction of additional facilities".
7.50 Section 35.2 (Coordination of Third-Party System Additions) is amended by replacing the phrase "NEPOOL Transmission System" with the term "PTF".
7.51 The heading for Section 36 is amended to read as follows:
Changes in Service Specifications of Internal Point-To Point Service and MTF Service
7.52 Section 36.1 is amended to read as follows:
Modification on a Non-Firm Basis: The Transmission Customer taking Firm Internal Point-To-Point Service and Firm MTF Service may submit a request to the System Operator for transmission service on a non-firm basis over Point(s) of Receipt and Point(s) of Delivery other than those specified in the Service Agreement ("Secondary Receipt and Delivery Points"), in amounts not to exceed the Transmission Customer's firm capacity reservation, without incurring an additional Non-Firm Internal Point-To-Point Service charge or an additional Non-Firm MTF Service charge or executing a new Service Agreement, subject to the following conditions:
(a) service provided over Secondary Receipt and Delivery Points will be non-firm only, on an as-available basis, and will not displace any firm or non-firm service reserved or scheduled by Participants or Non- Participants under this Tariff or by the Participants on behalf of their Native Load Customers or Excepted Transactions;
(b) the sum of all Firm Internal Point-To-Point Service and Non-Firm Internal Point-To-Point Service or Firm MTF Service and Non-Firm MTF Service provided to the Transmission Customer at any time pursuant to this section shall not exceed the Reserved Capacity specified in the relevant Service Agreement under which such services are provided;
(c) the Transmission Customer shall retain its right to schedule Firm Internal Point-ToPoint Service and Firm MTF Service at the Point(s) of Receipt and Point(s) of Delivery specified in the relevant Service Agreement in the amount of the Transmission Customer's original capacity reservation; and
(d) service over Secondary Receipt and Delivery Points on a non-firm basis shall not require the filing of an Application for Non-Firm Internal Point-To-Point Service or Non-Firm MTF Service under the Tariff. However, all other requirements of this Tariff (except as to transmission rates) shall apply to transmission service on a non-firm basis over Secondary Receipt and Delivery Points.
7.53 Section 36.2 (Modification on a Firm Basis) is amended by inserting the word "reservation" before the word "priority" in the second sentence.
7.54 The heading for Section 37 is amended to read as follows:
Sale, Assignment or Transfer of Internal Point-to Point Service and MTF Service
7.55 Section 37.1 (Procedures for Sale, Assignment or Transfer of Service) is amended by inserting the word "transmission" immediately before the word "priority" in the fourth sentence.
7.56 The following new section 37.4 is added in the appropriate numerical order:
Transfer of FTRs: The sale, resale, or assignment of FTRs shall be conducted pursuant to Market Rule 1.
7.57 Section 39 is amended to read as follows:
Compensation for New Facilities and Redispatch Costs:
Whenever a System Impact Study performed in connection with
a Study Request identifies the need for new facilities or
upgrades, the Transmission Customer shall be responsible for
such costs to the extent they are consistent with Commission
policy and Schedules 11 and 12. The System Operator will
redispatch all Resources subject to its control, pursuant to
Market Rule 1, in order to meet load and to accommodate
External Transactions. Participants and Transmission
Customers will be charged for the Congestion Costs and any
other costs associated with such redispatch in accordance
with Market Rule 1. The Transmission Customer shall be
responsible for costs of new facilities or upgrades required
to provide the requested service to the extent they are
consistent with Commission policy and Schedules 11 and 12.
Part VI - Regional Network Service
(Network Integration Transmission Service)
8.1 Sections 40.2 (Transmission Provider Responsibilities), 40.3 (Network Integration Transmission Service), 41.3 (Technical Arrangements to be Completed Prior to Commencement of Service), 41.4 (Network Customer Facilities), 42.5 (Transmission Arrangements for Network Resources Not Physically Interconnected With the NEPOOL Transmission System), 42.7 (Use of Interface Capacity by the Network Customer), 43.3 (Network Load Not Physically Interconnected with the NEPOOL Transmission System), 43.4 (New Interconnection Points), 44.2 (System Impact Study Agreement and Cost Reimbursement), 45.1 (Procedures), 45.4 (Curtailments of Scheduled Deliveries), 45.6 (Load Shedding), 45.7 (System Reliability), 47.2 (Network Operating Agreement), 50.2 (Interconnection of Elective Transmission Upgrades), 51.1 (General), 51.6 (Request for Proposals ("RFP") Process for Upgrades), and 51.8 (Merchant Transmission Facilities; Compliance), including, as appropriate, headings for those sections, are amended by replacing the phrase "NEPOOL Transmission System" with the term "PTF" at each occurrence.
8.2 Section 40.5 is amended to read as follows:
Real Power Losses: Real Power Losses are associated with all transmission service. The Transmission Provider is not obligated to provide Real Power Losses. The cost of PTF losses shall be recovered through the Loss Component of the Locational Marginal Prices provided for in Market Rule 1.
8.3 Section 41.2 (Application Procedures) is amended by inserting the word "reservation" before the word "priority" at the first and third occurrence of the word "priority", and by replacing the word "Interruption" with the word "interruption" at each occurrence.
8.4 Section 42.4 is amended to read as follows:
Network Customer Redispatch Obligation: As a condition to
receiving Network Integration Transmission Service, the
Network Customer agrees to redispatch its Network Resources
as requested by the System Operator pursuant to Section
45.2. The System Operator will redispatch all Resources
subject to its control, pursuant to Market Rule 1, in order
to meet load and to accommodate External Transactions.
Participants and Transmission Customers will be charged for
the Congestion Costs and any other costs associated with
such redispatch in accordance with Market Rule 1.
8.5 Section 42.6 (Limitation on Designation of Resources) is amended by replacing the word "Entitlement" with the phrase "Ownership Share" and by replacing the phrase "NEPOOL Transmission System" with the term "PTF".
8.6 Section 43.2 (New Network Loads Connected With the NEPOOL Transmission System) is amended by replacing the phrase "NEPOOL Transmission System" with the term "PTF", and by replacing the reference to "Schedule 11" with a reference to "Schedules 11 and 12".
8.7 Section 44.1 (Notice of Need for System Impact Study) is amended by replacing the phrase "Administrative Costs" with the phrase "administrative costs".
8.8 Section 44.2(ii) (System Impact Study Agreement and Cost Reimbursement) is amended to read as follows:
If in response to multiple Eligible Customers requesting the service in relation to the same competitive solicitation, a single System Impact Study is sufficient for the System Operator and the affected Participants to accommodate the service, the costs of that study shall be prorated among the Eligible Customers.
8.9 Section 44.3 (System Impact Study Procedures) is amended by inserting the phrase "and indirectly affected MTF owners" after the word "Participants" in the first sentence, and by deleting the phrase ", redispatch options," in the second sentence.
8.10 Section 44.4 (Facilities Study Procedures) is amended by replacing the phrase "NEPOOL Transmission Service" with the term "PTF", by replacing the word "request" with the phrase "or to mitigate indirect impacts on the MTF facilities" in the first sentence, by deleting the word "and" from the final sentence, and by adding the following text to the end of the Section:
In addition to the foregoing, each Facilities Study performed on or after the SMD Effective Date shall, if requested by the Transmission Customer, contain a non- binding estimate from the System Operator of the Qualified Upgrade Awards, if any, resulting from the construction of the new facilities. After completion of the transmission upgrade or expansion, the System Operator shall determine the Qualified Upgrade Awards, if any, resulting from the upgrade or expansion. The Transmission Customer shall be responsible for the cost of any study required to determine the Qualified Upgrade Awards.
8.11 Section 45.2 (Transmission Constraints) is amended by replacing the phrases "NEPOOL Transmission System" and "Transmission System" with the term "PTF".
8.12 Section 45.3 is amended to read as follows:
Cost Responsibility for Relieving Transmission Constraints:
Whenever the System Operator implements least-cost
redispatch procedures in response to a transmission
constraint, the Non- Participant Transmission Customers and
Participants will bear the costs of such redispatch in
accordance with Market Rule 1.
8.13 Section 45.5 (Allocation of Curtailments) is amended by replacing the word "Import" with the word "External" and by replacing "14.1" with "25F".
8.14 Section 46 (Rates and Charges) is amended by replacing the term Schedule 11," with the term "Schedules 11 and 12".
8.15 Section 48 (Scope of Application of Part VI to Participants)
is amended by deleting the phrase ", unless they elect in
accordance with Section 3.3 of this Tariff to receive
Internal Point-To-Point Service at one or more Point(s) of
Delivery from one or more Point(s) of Receipt" in subsection
(a), and by replacing the phrase "NEPOOL Transmission
System" with the term "PTF".
Part VII - Transmission Planning, Additions and Modifications
9.1 Section 49 (General) is amended by replacing the phrase
"NEPOOL Transmission System" with the term "PTF", by
omitting subsection (d), by adding the word "Costs" after
the word "Congestion" in the first sentence of subsection
(e), by inserting the word "transmission" before the word
"priorities" in the seventh sentence of subsection (e), by
replacing the term "ARRs" with the phrase "Qualified Upgrade
Awards" in the eighth sentence of subsection (e), by
replacing the phrase "Schedules 14 and 15" with the phrase
"Appendix C of Market Rule 1" in the eighth sentence of
subsection (e), by replacing the term "FCRs" with the term
"FTRs" and by replacing the phrase "Schedule 14" with the
phrase "Section 7 of Market Rule 1".
9.2 Section 50.1 (Interconnection of Generating Unit Under the Minimum Interconnection Standard) is amended by replacing the phrase "NEPOOL Transmission System" with the term "PTF", and by replacing the term "CMS" with the term "SMD", by inserting the word "Cost" after the term "Congestion" in the third full sentence of subsection (f), by inserting the word "cost" after the term "RMR" in the fifth full sentence of subsection (f), and by replacing the word "cost" with the word "Cost" after the word "Congestion" in the fifth full sentence of subsection (f).
9.3 Section 51.4 (Procedures for Developing a NEPOOL Transmission Plan) is amended by replacing the phrase "NEPOOL Transmission System" with the term "PTF", and by replacing the phrase "Schedule 11 or 12" with the phrase "Schedules 11, 12 or 18" in subsection (j).
9.4 Section 51.8(c) is amended to read as follows:
Merchant Transmission Facilities, including those defined as MTF, shall be subject to the operational control, scheduling and maintenance coordination of the System Operator.
Schedules, Attachments, and Implementation Rules
10.1 The reference in the last sentence of Schedule 1 to "Regional Transmission Operations Committee" is amended to read "Participants Committee".
10.2 The following parenthetical is added after each occurance of the phrase "NEPOOL Transmission System" in the first paragraph of Section I of Schedule 2:
(for voltage constraints that are reflected in the System Operator's systems for operating the NEPOOL Transmission System or in the System Operator's operating procedures)
10.3 Section 1.8 under Part II of Schedule 2 is amended to read as follows:
A Qualified Generator's VAR Payment shall equal the (1/12) *
(VAR Rate*Qualified VARs)
10.4 Section 2.1 under Part II of Schedule 2 is amended to read as follows:
The Lost Opportunity Cost for hydro, pumped storage and thermal generating units that are dispatched down by the ISO, a NEPOOL satellite or a NEPOOL Participant dispatch center for the purpose of providing reactive supply and voltage control will be calculated pursuant to Market Rule 1.
10.5 Section 3.1 under Part II of Schedule 2 is amended to read as follows:
Motoring Hydro or Pumped Storage Generating Units. The SCL associated with hydro and pumped storage generating units that are motoring at the request of the ISO, a NEPOOL satellite or a NEPOOL Participant dispatch center for the purpose of providing reactive supply and voltage control will equal the cost of energy to motor and will be calculated in each hour as follows: SCL = (MWhUnit * (ECP or LMP or Actual energy cost), where the MwhUnit are calculated pursuant to the Schedule 2 Business Procedure. Actual energy cost applies only if motoring energy is purchased through a bilateral contract.
10.6 Sections 4.1 and 4.2 under Part II of Schedule 2 are amended by replacing the phrase "applicable Market Rules" with "Market Rule 1 and NEPOOL System Rules".
10.7 Schedule 3 is amended to read as follows:
Regulation and Frequency Response Service (Automatic Generation Control)
Regulation and Frequency Response Service (Automatic Generator Control) is necessary to provide for continuous balancing of resources (generation and interchange) with Load, and for maintaining scheduled interconnection frequency at sixty cycles per second (60 Hz). Regulation and Frequency Response Service (Automatic Generation Control) is accomplished by committing on-line generation whose output is raised or lowered (predominantly through the use of automatic generating control equipment) as necessary to follow the moment-by-moment changes in load. The obligation to maintain this balance between resources and load lies with the System Operator and this service will be available to all Participants that have a load obligation in the NEPOOL Market pursuant to Market Rule 1. The Transmission Customer must either take this service from the System Operator through the NEPOOL Market or make alternative comparable arrangements to satisfy its Regulation and Frequency Response Service (Automatic Generator Control or AGC) obligation.
Charges for this Service shall be determined on the basis of offers submitted by Participants in accordance with Market Rule 1. The per unit charge for this Service to Non- Participants shall be the same as the charge to Participants. The transmission service required with respect to Regulation and Frequency Response Service (Automatic Generator Control) will be paid for as part of Regional Network Service, Internal Point-To-Point Service or Through or Out Service by all Participants and other entities that have a load obligation in the NEPOOL Market Pursuant to Market Rule 1. The charge for Regional Network Service is determined in accordance with Schedule 9 of the Tariff. The charge for Internal Point-To-Point Service is determined in accordance with Schedule 10 of the Tariff. The charge for Through or Out Service is determined in accordance with Schedule 8 of the Tariff.
10.8 Schedule 4 is amended to read as follows:
Energy Imbalance Service
Energy Imbalance Service is the service provided when a difference occurs between the scheduled and the actual delivery of energy to a load obligation in the NEPOOL Market in accordance with Market Rule 1 during a single hour. The Transmission Customer may either supply its load obligation from its own resources or through bilateral transactions or obtain the service through the NEPOOL Market. This service will be available to all Participants that have a load or generation obligation in the NEPOOL Market pursuant to Market Rule 1. The prices for such service will be the applicable Locational Marginal Prices determined pursuant to Market Rule 1.
The transmission service required with respect to Energy Imbalance Service will be furnished as part of Regional Network Service, Internal Point-To-Point Service or Through or Out Service to all Participants and other entities that have a load or generation obligation in the NEPOOL Market in accordance with Market Rule 1. The charge for Regional Network Service is determined in accordance with Schedule 9 of the Tariff. The charge for Internal Point- to-Point Service is determined in accordance with Schedule 10 of the Tariff. The charge for Through or Out Service is determined in accordance with Schedule 8 of the Tariff.
10.9 Schedule 5 is amended to read as follows:
Operating Reserve - Spinning Reserve Service
Spinning Reserve Service is a service needed to serve
load immediately in the event of a system contingency. This
service will be available to all Participants that have a
load obligation in the NEPOOL Market in accordance with
Market Rule 1. The Transmission Customer may either supply
this service with its own resources or through bilateral
arrangements, or obtain the service through the NEPOOL
Market.
The total of each category of Operating Reserve
requirements for the NEPOOL Control Area in each hour is
determined by the System Operator in accordance with
applicable NEPOOL System Rules.
The amount of and charges for Spinning Reserve Service
will be accounted and paid for as part of the Operating
Reserves pursuant to Section 3.2.3 of Market Rule 1. The
transmission service required with respect to Operating
Reserve will be paid for as part of Regional Network
Service, Internal Point-To-Point Service or Through or Out
Service by all Participants and other entities that have a
load obligation in the NEPOOL Market in accordance with
Market Rule 1. The charge for Regional Network Service is
determined in accordance with Schedule 9 of the Tariff. The
charge for Internal Point-To-Point Service is determined in
accordance with Schedule 10 of the Tariff. The charge for
Through or Out Service is determined in accordance with
Schedule 8 of the Tariff.
10.10 Schedule 6 is amended to read as follows:
Operating Reserve - Supplemental Reserve Service
Supplemental Reserve Service is a service needed to
serve load in the event of a system contingency; however, it
is not available immediately to serve load but rather within
a short period of time. Supplemental Reserve Service may be
provided by generating units that are on-line but unloaded,
by quick-start generation or by interruptible load. This
service will be available to all Participants that have a
load obligation in the NEPOOL Market in accordance with
Market Rule 1. The Transmission Customer may either supply
this service with its own resources or through bilateral
arrangements, or obtain the service through the NEPOOL
Market.
The total of each category of Operating Reserve
requirements for the NEPOOL Control Area in each hour is
determined by the System Operator in accordance with
applicable NEPOOL System Rules.
The amount of and charges for Supplemental Reserve
Service will be accounted and paid for as part of the
Operating Reserves pursuant to Section 3.2.3 of Market Rule
1.
The transmission service required with respect to
Operating Reserve will be paid for as part of Regional
Network Service, Internal Point-To-Point Service or Through
or Out Service by all Participants and other entities that
have a load obligation in the NEPOOL Market pursuant to
Market Rule 1. The charge for Regional Network Service is
determined in accordance with Schedule 9 of the Tariff. The
charge for Internal Point-To-Point Service is determined in
accordance with Schedule 10 of the Tariff. The charge for
Through or Out Service is determined in accordance with
Schedule 8 of the Tariff.
10.11 Schedule 7 is deleted in its entirety.
10.12 Schedule 8 is amended to read as follows:
Through or Out Service - The Pool PTF Rate
(1) A Transmission Customer shall pay to NEPOOL for Through
or Out Service reserved for it in accordance with
Section 18 of the Tariff the the Pool PTF Rate. The
Transmission Customer shall also be obligated to pay
any applicable ancillary service charges and any
charges required to be paid pursuant to Market Rule 1.
(2) The Pool PTF Rate in effect at any time shall be
determined annually on the basis of the information for
the most recent calendar year contained in Form 1
filings (or similar information on the books of
Transmission Providers that are not required to submit
a Form 1 filing) and shall be changed annually
effective as of June 1 in each year. The Pool PTF rate
shall be equal to (i) the sum for all Participants of
Annual Transmission Revenue Requirements determined in
accordance with Attachment F divided by (ii) the sum of
the coincident Monthly Peaks (as defined in Section
46.1) of all Local Networks, excluding from the Monthly
Peak for each Local Network as applicable the loads at
each applicable Point of Delivery of each Participant
or Non-Participant which has elected to take Internal
Point-To-Point Service in lieu of Regional Network
Service at one or more Points of Delivery; plus the
Long-Term Firm Reserved Capacity amount for each such
Participant or Non-Participant which has elected to
take Firm Internal Point-To-Point Service in lieu of
Regional Network Service at one or more Points of
Delivery plus any Long-Term Reserved Capacity amount
reserved prior to the SMD Effective Date for each
Participant or Non-Participant for Firm Through or Out
Service. Revenues associated with Short-Term Point-To-
Point reservations will be credited to the sum of all
Participants' Annual Transmission Revenue Requirements
referred to in (i) above.
(3) Discounts: Three principal requirements apply to
discounts for Through or Out Service as follows (1) any
offer of a discount made by the Participants must be
announced to all Eligible Customers solely by posting
on the OASIS, (2) any customer-initiated requests for
discounts (including requests for use by one's
wholesale merchant or an affiliate's use) must occur
solely by posting on the OASIS, and (3) once a discount
is negotiated, details must be immediately posted on
the OASIS. For any discount agreed upon for service on
a path, from Point(s) of Receipt to Point(s) of
Delivery, the Participants must offer the same
discounted transmission service rate for the same time
period to all Eligible Customers on all unconstrained
transmission paths that go to the same Point(s) of
Delivery on the PTF.
10.13 Schedule 9 is amended by replacing the phrase
"applicable congestion or other uplift charge" with the word
"charges" in subsection (1), by replacing the phrase
"Sections 24, 25A and 25B of this Tariff" with the phrase
"Market Rule 1" in subsection (1), by inserting the word
"any" before the second occurrence of the phrase "Long-Term"
in subsection (6) and by inserting the phrase "reserved
prior to the SMD Effective Date" after the last occurrence
of the phrase "Reserved Capacity amount" in subsection (8).
10.14 Schedule 10 is amended to read as follows:
Internal Point-To-Point Service
(1) A Transmission Customer shall pay to NEPOOL for firm or
non-firm Internal Point-To-Point Service reserved for
it in accordance with Section 19 of the Tariff a charge
per Kilowatt, as determined for the period of the
service in accordance with Section 21 of this Tariff,
equal to the Internal Point-To-Point Service Rate;
provided that if, a rate which is derived from the
annual incremental cost not otherwise borne by the
Transmission Customer or a Generator Owner, of any new
facilities or upgrades that would not be required but
for the need to provide the requested service is
greater than the Pool PTF Rate, the charge shall be the
higher of such amounts.. The Customer shall also be
obligated to pay any ancillary service charges and any
other charges required to be paid pursuant to Market
Rule 1.
(2) Discounts: Three principal requirements apply to
discounts for Internal Point-To-Point Service as
follows (1) any offer of a discount made by the
Participants must be announced to all Eligible
Customers solely by posting on the OASIS, (2) any
customer-initiated requests for discounts (including
requests for use by one's wholesale merchant or an
affiliate's use) must occur solely by posting on the
OASIS, and (3) once a discount is negotiated, details
must be immediately posted on the OASIS. For any
discount agreed upon for service on a path, from
Point(s) of Receipt to Point(s) of Delivery, the
Participants must offer the same discounted
transmission service rate for the same time period to
all Eligible Customers on all unconstrained
transmission paths that go to the same Point(s) of
Delivery on the PTF.
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10.15 Subsection (3) of Schedule 12 is amended by replacing the phrase "NEPOOL Transmission System" with the term "PTF".
10.16 Section 3.1 of Schedule 18 is amended to read as follows:
Availability of MTF Service: To the extent that transmission capability over MTF has not been fully allocated in accordance with Section 2 of this Schedule 18, a Participant or Non-Participant that is an Eligible Customer (except as provided below) may reserve Firm or Non- Firm MTF Service. Such service shall be provided by the MTF Provider(s) and shall be reserved pursuant to the applicable terms and conditions of this Schedule 18. MTF Service shall be reserved through the System Operator separately pursuant to Schedule 18. Service on the MTF requires advance reservations. MTF Service is available to any Eligible Customer unless an MTF Provider has informed the System Operator that MTF Service shall not be made available to such Eligible Customer due to that Customer's failure to make necessary payments for previously assessed MTF Service Charges or failure to meet the creditworthiness or operational requirements posted by the MTF Provider on the NEPOOL OASIS.
10.17 Section 3.3 of Schedule 18 is amended to read as follows:
Use of MTF Service By a Transmission Customer: If a
Transmission Customer elects to take MTF Service it may
reserve transmission capability for such service to cover
both the delivery to it over the MTF of Energy and capacity
(to the extent permitted under applicable Market Rules)
covered by the Ownership Share designated by it in Completed
Applications and the delivery to or from it over the MTF in
Interchange Transactions of Energy and/or capacity (to the
extent permitted under applicable Market Rules). In order
to fulfill its obligations to serve load or to consummate a
transaction, a Transmission Customer which takes MTF Service
must also take service under the Tariff for use of the PTF
and under any applicable Local Network Service tariff for
use of the Non-PTF. Any load-serving entity may use MTF
Service to effect sales in bilateral arrangements, whether
or not it elects to take Internal Point-To-Point Service on
the PTF to serve its load.
10.18 Section 5 of Schedule 18 is amended to read as follows:
MTF Service Reservation, interruption and Curtailment priorities: The MTF Provider shall furnish to the System Operator for posting on NEPOOL OASIS, and the System Operator shall post on the NEPOOL OASIS, rules setting reservation, interruption and Curtailment priorities for Firm and Non-Firm MTF Service. Such rules shall be non- discriminatory and consistent with the Commission's approval of the rights to charge negotiated rates (i.e., rates established pursuant to market mechanisms as recognized for merchant transmission projects and not included in NEPOOL Tariff rates). If an MTF Provider fails to furnish to the System Operator such rules, reservation, interruption and Curtailment priorities for Firm and Non-Firm MTF Service shall be the same as those established under the Tariff for Firm and Non-Firm Internal Point-To-Point Transmission Service over the PTF. The reservation priority for Long- Term Firm Transmission Service and Short-Term Firm Transmission Service based upon an award of transmission capability of MTF pursuant to a Commission-approved rights allocation process shall be the date of the issuance of such award.
When the System Operator determines that an electrical
emergency exists on the NEPOOL Transmission System and
implements emergency procedures to effect a Curtailment of
MTF Service, the Transmission Customer shall make the
required reductions upon the System Operator's request. The
System Operator reserves the right to effect a Curtailment,
in whole or in part, of any MTF Service provided under this
Tariff when, in the System Operator's sole discretion, an
emergency or other unforeseen condition impairs or degrades
the reliability of the NEPOOL Transmission System. The
System Operator will notify all affected Transmission
Customers in a timely manner of any scheduled Curtailments.
In the event the System Operator exercises its right to
effect a Curtailment, in whole or part, of Firm MTF Service,
no credit or other adjustment shall be provided as a result
of the Curtailment with respect to the charge payable by the
Customer, unless provided for by the MTF Provider under
arrangements between the MTF Provider and the Transmission
Customer. To the extent not otherwise provided for in this
Section 5, Curtailments Interruptions of MTF Service shall
be in accordance with Sections 27.6 and 28.7of the Tariff.
10.19 Section 6 of Schedule 18 is amended to read as follows:
Real Power Losses: Real power losses across MTF shall be
allocated solely to Transmission Customers that use MTF.
Such allocation for transactions across MTF shall be
pursuant to Market Rule 1.
10.20 Section 8 of Schedule 18 is amended to read as follows:
No Effect on Rates; No Allocation of Revenues: MTF and MTF
Service shall not affect rates for service on the PTF under
the Tariff and MTF Providers shall not be allocated any
revenues collected under the Tariff for such service.
10.21 Section 9 of Schedule 18 is amended to read as follows:
Ancillary Services: Congestion Costs and Ancillary Services
costs associated with MTF Service Shall be assessed pursuant
to Market Rule 1.
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10.22 A new Schedule 19 is added to reads as follows:
Special Constraint Resource Service
In order to maintain area reliability, Transmission Owners or distribution companies may request the System Operator to change the commitment of a generating Resource or the incremental loading on a previously committed generating Resource to provide relief for constraints not reflected in the System Operator's systems for operating the NEPOOL Transmission System or the System Operator's operating procedures. Requests will normally be made to the System Operator via the appropriate Satellite unless emergency conditions justify immediate communications with the Resources.
Such out of merit operation of units for any reliability purposes to provide relief for constraints (thermal, voltage or stability) not reflected in the System Operator's systems or procedures will result in the Resource(s) being designated as a Special Constraint Resource and administered in accordance with the provisions of this Schedule. However, in the event a SCR is requested on by a Participant and the System Operator also requires that unit to be on-line in accordance with the System Operator's systems and procedures, the System Operator will apply the appropriate flag to reflect the System Operator's need for the unit and will only flag the unit as SCR when the System Operator does not require the Resource (or when changed dispatch of the unit is requested by the Participant). When a unit would not be operating above its Economic Minimum Limit (as defined in Market Rule 1) but for the request of the Participant, it shall be flagged as SCR. In the event that the System Operator requires that a unit, previously designated and flagged as SCR, becomes a unit required by the System Operator to be on-line in accordance with the System Operator's systems and procedures (including economic dispatch or for purposes of RMR, first contingency or capacity), the SCR designation and flag will be removed.
I. DETERMINING THE AMOUNT TO BE PAID FOR SERVICE UNDER THIS SCHEDULE
Service under this Schedule is to be provided through the System Operator. The Transmission Owner or distribution company making a request or on whose behalf a Satellite makes a request to change the commitment of a generating Resource or the incremental loading on a previously committed generating Resource must purchase such service through the System Operator. The Transmission Owner or distribution company shall be charged an amount equal to the Operating Reserve Credits as calculated pursuant to Market Rule 1 related to the Real-Time operation of the Special Constraint Resource.
II. DETERMINING A GENERATOR'S COMPENSATION FOR PROVIDING SERVICE UNDER THIS SCHEDULE
The Special Constraint Resource is compensated pursuant
to Market Rule 1 in the same manner as other generating
Resources dispatched to provide relief for constraints
reflected in the System Operator's systems for operating the
NEPOOL Transmission System or the System Operator's
operating procedures. Operating Reserve Credits (as defined
in Market Rule 1) associated with the scheduling of Special
Constraint Resources compensate these Resources for helping
to maintain NEPOOL Control Area reliability requirements and
are collected as stated in the NEPOOL Manual for Market Rule
1 Accounting, M-28.
10.23 The reference in the last paragraph of Attachment F to
"Regional Transmission Operations Committee" is amended to
read "Participants Committee".
10.24 The introductory paragraphs to both Attachment G and
Attachment G-1 are amended by replacing the phrase "Sections
25, 25A and 25B" with the phrase "Section 25".
10.25 Attachment G-2 (List of Certain Arrangements over
External Ties) is amended to read as set forth in Exhibit 1.
10.26 A new Attachment G-3 (Complete List of Excepted
Transaction (Transmission) Agreements over External Ties) is
added to read as set forth in Exhibit 2.
10.27 The first paragraph in the Form of Facilities Study
Agreement set forth in Attachment J is amended by replacing
the phrase "NEPOOL Transmission System" with the term "PTF".
10.28 Section 8 in the Form of Facilities Study Agreement set
forth in Attachment J is amended to read as follows:
Nothing in this Agreement shall be interpreted to give the
Transmission Customer immediate rights to interconnect to or
wheel over the Pool Transmission Facilities. Such rights
shall be provided for under separate agreement.
10.29 The fourth sentence of Section II.E of Atachment L
(Financial Assurance Policy for NEPOOL Members) is amended
to replace the term "Entitlements" with the term "Ownership
Shares".
10.30 Section 2.3(f) of Attachment N (New England Power Pool
Billing Policy) is amended so that it reads as follows:
Sanctions Charges. Any Charges assessed on the Participant
pursuant to Appendix B of Market Rule 1.
10.31 The third sentence of the second paragraph of Section
3.3(j) of Attachment N is amended to read as follows:
If a suspended Participant has the obligation under
applicable Market Rules to bid any of its Ownership Shares
to provide Market Products under Market Rule 1, that
obligation shall continue notwithstanding the Participant's
suspension and any transfers of Market Products occurring
under the Market Rule 1 as a result of any such bid shall be
effective.
10.32 Attachment O (Financial Assurance Policy for Non-
Participant FTR Customers) is amended by replacing the
phrase "under the Tariff and the applicable Market Rules"
with the phrase "pursuant to Market Rule 1".
10.33 The reference Section K of the Attachment F
Implementation Rule to "Management Committee" is amended to
read "Participants Committee".
10.34 The reference to "Transmission network" in Appendix A
to the Attachment F Implementation Rule "Rules for
Determining Investment to be Included in PTF" is amended by
replacing the word "Transmission" with the word
"transmission" after "New England" in Section A.
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EXHIBIT 1
Ninety-Third Agreement
ATTACHMENT G-2: List of Certain Arrangements over External Ties
Attachment G-2 is a listing of agreements which relates to the use of
the tie lines to New York.
Description, Comments
Purpose of Effective End Amount FERC
Item# Provider Receiver Service Date Date (MW's) Docket #'s
1 VT Electric VT Public To import 03/01/90 10/2003 14 MW
Power Co. Systems NYPA power
2 VT Electric VT Public To import 02/16/95 10/2003 5 MW S
Power Co. Power Supply power from 7 MW W
Authority New York State
(VPPSA) Electric & Gas
Company
(NYSE&G)
3 VT Electric VPPSA To import 11/01/93 10/98 9 MW
Power Co. power from
Niagara Mohawk
4 VT Electric City of To import 05/01/98 12/2009 10 MW
Power Co. Burlington power from
NYSE&G -
signed
04/01/96
5 NRTG NEP TDUs FIRM Network 3/1/97 10/31/03 37 MW
& Norwood Service - NYPA
Power portion
of NEP-TDU
Network Loads
6 NU or CMEEC Comprehensive 11/29/90 1/1/09 21 MW ER91-209-000,
NRTG? Transmission ER93-297-000
Service
Agreement
7 NU or Chicopee Comprehensive 11/1/95 10/31/09 6 MW ER85-689-000,
NRTG? Transmission ER93-219-000
Service
Agreement
8 NU or South Hadley Comprehensive 11/1/95 7/1/10 2 MW EC90-10-000,
NRTG? Transmission ER85-689-000
Service ER720-000
Agreement
9 NU or Westfield Comprehensive 1/1/95 7/1/10 4 MW
NRTG? Transmission
Service
Agreement
10 NU or Holyoke FIRM Network ? 10/31/03 4 MW
NRTG? Service- NYPA
Power portion
of Holyoke
Network Load
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Exhibit 2
Ninety-Third Agreement
ATTACHMENT G-3: Complete list of Excepted Transaction (Transmission)
Agreements over External Ties
Attachment G-3 is a comprehensive list of Excepted Transaction
Agreements that relate to the use of ties with neighboring Control
Areas ("External Ties"). The party responsible for paying the
Congestion Cost associated with energy purchased under the Excepted
Transactions listed in Attachment G-3 will retain their existing
contract rights for physical scheduling of a transaction at the
External Node associated with the Excepted Transaction until such
party elects to be allocated Auction Revenue Rights pursuant to Market
Rule 1. Until the party responsible for paying the Congestion Cost
associated with energy purchased under an Excepted Transaction listed
in Attachment G-3 elects to be allocated Auction Revenue Rights, the
Excepted Transaction shall have physical scheduling and curtailment
rights in accordance with Section 25F(a) of this Tariff. Once the
party responsible for paying the Congestion Cost associated
with energy purchased under the Excepted Transaction elects to be
allocated Auction Revenue Rights, the party will not be able to
revert back to using their contract rights for physical scheduling and
curtailment.
Imports
Description, Transmission
Purpose of Effective Contract End Amount External
Item# Provider Receiver Service Date Date (MW's) Interface Reference
1 NRTG CMEEC To import
power from Various 10/31/03 20.9 NE/NY - Supported by agreements
NYPA to AC under the RNA,
Participants NOATT Attachments
and non- G and G-1, and NOATT
Participant Settlement agreement
Transmission (including "In-Service"
Customers - Settlement).
NYPA
2 NRTG MMWEC To import Various 10/31/03 81.8 NE/NY - Supported by agreements
power from AC under the RNA,
NYPA to NOATT Attachments
Participants G and G-1, and NOATT
and non- Settlement agreement
Participant (including NEPOOL
Transmission Absorption of NEP
Customers - Tariff No 9
NYPA obligations, certain
All Requirements
services of NEP, and
"In-Service"
Settlement).
3 NRTG Pascog To import Various 10/31/03 2.4 NE/NY - Supported by agreements
power from AC under the RNA,
NYPA to NOAA Attachments
Participants G and G-1, and NOATT
and non- Settlement agreement
Participant (including "In-
Transmission Service" Settlement).
Customers -
NYPA
4 NRTG VT To import Various 10/31/03 15 NE/NY - Supported by agreements
Public power from AC under the RNA,
Systems NYPA to NOAA Attachments
Participants G and G-1, and NOATT
and non- Settlement agreement
Participant (including "In-
Transmission Service" Settlement).
Customers -
NYPA
5 VELCO VT To import 02/16/95 10/31/03 5/6-S NE/NY - See attachment G-2,
Power power from 7 - W AC Item #2
Supply New York
Authority State
Electric
& Gas Company
(NYSE&G)
6 VELCO City of To import 05/01/98 12/31/09 10 NE/NY - See attachment G-2,
Burlington power from AC Item # 4
New York
State
Electric
& Gas Company
(NYSE&G)
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Notes: Summer (S) = March through October; Winter (W) = November
through February.
NRTG = NEPOOL Regional Transmission Group
Item #5 = Summer allocation increases from 5 MW to 6 MW on 4/1/2003
Exports
Description, Transmission
Purpose of Effective Contract End Amount External
Item# Provider Receiver Service Date Date (MW's) Interface Reference
7 NU NUSCO To export 10/1/96 09/30/06 200 NE/NY - See Attachment G,
power from AC Item # 28
NEPOOL into
the NY Power
Pool over the
1385 line
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Exhibit 10.33
TRUST UNDER SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN
This Agreement made this 2nd day of May, 1994, by and between Northeast Utilities Service Company, a corporation organized and existing under the laws of the State of Connecticut (Company) and Fleet Bank, N.A., a national banking association organized and existing under the laws of the United States (Trustee);
WHEREAS, Company has adopted the Supplemental Executive Retirement Plan for Officers of Northeast Utilities System Companies (the Plan);
WHEREAS, Company has incurred or expects to incur liability under the terms of the Plan with respect to the individuals participating in such Plan;
WHEREAS, Company wishes to establish a trust (hereinafter called "Trust") and to contribute to the Trust assets that shall be held therein, subject to the claims of Company's creditors in the event of Company's Insolvency, as herein defined, until paid to Plan participants and their beneficiaries in such manner and at such times as specified in the Plan;
WHEREAS, it is the intention of the parties that this Trust shall constitute an unfunded arrangement and shall not affect the status of the Plan as an unfunded plan maintained for the purpose of providing deferred compensation for a select group of management or highly compensated employees for purposes of Title I of the Employee Retirement Income Security Act of 1974;
WHEREAS, it is the intention of Company to make contributions to the Trust to provide itself with a source of funds to assist it in the meeting of its liabilities under the Plan;
NOW, THEREFORE, the parties do hereby establish the Trust and agree that the Trust shall be comprised, held and disposed of as follows:
SECTION 1. Establishment of Trust.
(a) Company hereby deposits with Trustee in trust the cash and other property described in Appendix A hereto, which shall become the principal of the Trust to be held, administered and disposed of by Trustee as provided in this Trust Agreement.
(b) The Trust hereby established shall be irrevocable.
(c) The Trust is intended to be a grantor trust, of which Company is the grantor, within the meaning of subpart E, part I, subchapter J, chapter 1, subtitle A of the Internal Revenue Code of 1986, as amended, and shall be construed accordingly.
(d) The principal of the Trust, and any earnings thereon shall be held separate and apart from other funds of Company and shall be used exclusively for the uses and purposes of Plan participants and general creditors as herein set forth. Plan participants and their beneficiaries shall have no preferred claim on, or any beneficial ownership interest in, any assets of the Trust. Any rights created under the Plan and this Trust Agreement shall be mere unsecured contractual rights of Plan participants and their beneficiaries against Company. Any assets held by the Trust will be subject to the claims of Company's general creditors under federal and state law in the event of Insolvency, as defined in Section 3(a) herein.
(e) Company, in its sole discretion, may at any time, or from time to time, make additional deposits of cash or other property in trust with Trustee to augment the principal to be held, administered and disposed of by Trustee as provided in this Trust Agreement. Neither Trustee nor any Plan participant or beneficiary shall have any right to compel such additional deposits.
SECTION 2. Payments to Plan Participants and Their Beneficiaries.
(a) Company shall deliver to Trustee a schedule (the "Payment Schedule") that indicates the amounts payable in respect of each Plan participant (and his or her beneficiaries), or that provides a formula or other instructions acceptable to Trustee for determining the amounts so payable, the form in which such amount is to be paid (as provided for or available under the Plan), and the time of commencement for payment of such amounts. Except as otherwise provided herein, Trustee shall make payments to the Plan participants and their beneficiaries in accordance with such Payment Schedule. The Trustee shall make provision for the reporting and withholding of any federal, state or local taxes that may be required to be withheld with respect to the payment of benefits pursuant to the terms of the Plan and shall pay amounts withheld to the appropriate taxing authorities or determine that such amounts have been reported, withheld and paid by Company.
(b) The entitlement of a Plan participant or his or her beneficiaries to benefits under the Plan shall be determined by Company or such party as it shall designate under the Plan, and any claim for such benefits shall be considered and reviewed under the procedures set out in the Plan.
(c) Company may make payment of benefits directly to Plan participants or their beneficiaries as they become due under the terms of the Plan. Company shall notify Trustee of its decision to make payment of benefits directly prior to the time amounts are payable to participants or their beneficiaries. In addition, if the principal of the Trust, and any earnings thereon, are not sufficient to make payments of benefits in accordance with the terms of the Plan, Company shall make the balance of each such payment as it falls due. Trustee shall notify Company where principal and earnings are not sufficient.
SECTION 3. Trustee Responsibility Regarding Payments to Trust Beneficiary When Company Is Insolvent.
(a) Trustee shall cease payment of benefits to Plan participants and their beneficiaries if the Company is Insolvent. Company shall be considered "Insolvent" for purposes of this Trust Agreement if (i) Company is unable to pay its debts as they become due, or (ii) Company is subject to a pending proceeding as a debtor under the United States Bankruptcy Code.
(b) At all times during the continuance of this Trust, as provided in Section 1(d) hereof, the principal and income of the Trust shall be subject to claims of general creditors of Company under federal and state law as set forth below.
(1) The Board of Directors and the Chief Executive Officer of Company shall have the duty to inform Trustee in writing of Company's Insolvency. If a person claiming to be a creditor of Company alleges in writing to Trustee that Company has become Insolvent, Trustee shall determine whether Company is Insolvent and, pending such determination, Trustee shall discontinue payment of benefits to Plan participants or their beneficiaries.
(2) Unless Trustee has actual knowledge of Company's Insolvency, or has received notice from Company or a person claiming to be a creditor alleging that Company is Insolvent, Trustee shall have no duty to inquire whether Company is Insolvent. Trustee may in all events rely on such evidence concerning Company's solvency as may be furnished to Trustee and that provides Trustee with a reasonable basis for making a determination concerning Company's solvency.
(3) If at any time Trustee has determined that Company is Insolvent, Trustee shall discontinue payments to Plan participants or their beneficiaries and shall hold the assets of the Trust for the benefit of Company's general creditors. Nothing in this Trust Agreement shall in any way diminish any rights, of Plan participants and their beneficiaries to pursue their rights as general creditors of Company with respect to benefits due under the Plan or otherwise.
(4) Trustee shall resume the payment of benefits to
Plan participants or their beneficiaries in accordance with
Section 2 of this Trust Agreement only after Trustee has
determined that Company is not Insolvent (or is no longer
Insolvent).
(c) Provided that there are sufficient assets, if Trustee
discontinues the payment of benefits from the Trust pursuant to
Section 3(b) hereof and subsequently resumes such payments, the
first payment following such discontinuance shall include the
aggregate amount of all payments due to Plan participants or
their beneficiaries under the terms of the Plan for the period of
such discontinuance, less the aggregate amount of any payments
made to Plan participants or their beneficiaries by Company in
lieu of the payments provided for hereunder during any such
period of discontinuance.
SECTION 4. Payments to Company.
(a) Except as provided in Section 3 hereof, Company shall have no right or power to direct Trustee to return to Company or to direct to others any of the Trust assets before all payment of benefits have been made to Plan participants and their beneficiaries pursuant to the terms of the Plan.
SECTION 5. Investment Authority.
(a) In no event may Trustee invest in securities (including stock or rights to acquire stock) or obligations issued by Company, other than a de minimis amount held in common investment vehicles in which Trustee invests. All rights associated with assets of the Trust shall be exercised by Trustee or the person designated by Trustee, and shall in no event be exercisable by or rest with Plan participants.
(b) Except as provided in Section 5(c) hereof, the Trustee shall have the power of investing and reinvesting the Trust assets and in its sole discretion:
1) To invest and reinvest in any personal property, wherever situated and whether or not productive of income or consisting of wasting assets, including without limitation, common and preferred stocks, bonds, notes, debentures (including convertible stocks and securities but not including any stock or security of the Trustee or any affiliate thereof), leaseholds, mortgages, certificates of deposit or demand or time deposits (including any such deposits with the Trustee or any of its affiliates), shares of investment companies and mutual funds, interests in partnerships and trusts, insurance policies and annuity contracts, without being limited to the classes of property in which trustees are authorized to invest by any law or any rule of court of any state and without regard to the proportion any such property may bear to the entire amount of the Trust; provided however, that the Trust shall be diversified so as to minimize the risk of large losses unless under the circumstances it is clearly prudent not to do so, in the sole discretion of the Trustee;
2) As directed by the Treasurer of the Company, to invest and reinvest in insurance contracts or policies, and, if so directed by the Treasurer of the Company, to hold such contracts and policies in the name of the Trustee or otherwise, and to pay all premiums and other costs in connection therewith from the Trust;
3) To invest and reinvest all or any portion of the Trust assets collectively with funds of other trusts in units of or through the medium of any common, collective, or commingled trust fund or mutual fund that may be established and maintained by the Trustee or any of its affiliates, the instrument or instruments establishing such trust or funds, as amended, being made part of this Trust Agreement so long as any portion of the Trust shall be invested through the medium thereof;
4) To retain any property at any time received by the Trustee;
5) To sell or exchange any property held by it at public or private sale, for cash or on credit, to grant and exercise options for the purchase or exchange thereof, to exercise all conversion or subscription rights pertaining to any such property and to enter into any covenant or agreement to purchase any property in the future;
6) To participate in any plan of reorganization, consolidation, merger, combination, liquidation or other similar plan relating to property held by it and to consent to or oppose any such plan or any action thereunder or any contract, lease, mortgage, purchase, sale, or other action by any person;
7) To deposit any property held by it with any protective, reorganization, or similar committee, to delegate discretionary power thereto, and to pay part of the expenses and compensation thereof and any assessments levied with respect to any such property so deposited;
8) To extend the time of payment of any obligation held by it;
9) To hold uninvested any moneys received by it, without liability for interest thereon, until such moneys shall be invested, reinvested, or disbursed;
10) To exercise all voting or other rights with respect to any property held by it and to grant proxies, discretionary or otherwise;
11) To cause any property held by it to be registered and held in the name of one or more nominees, with or without the addition of words indicating that such securities are held in a fiduciary capacity, and to hold securities in bearer form;
12) To settle, compromise, or submit to arbitration any claims, debts, or damages due or owing to or from the Trust, respectively, to commence or defend suits or legal proceedings to protect any interest of the Trust, and to represent the Trust in all suits or legal proceedings in any court or before any other body or tribunal; provided, however, that the Trustee shall not be required to take any such action unless it shall have been indemnified by the Company to its reasonable satisfaction against liability or expenses it might incur therefrom; and
13) Generally, to do all acts, whether or not expressly authorized, that the Trustee may deem necessary or desirable for the protection of the Trust.
c) If (i) a registered investment adviser under the Investment Advisers Act of 1940, (ii) a bank, as defined in that Act, or (iii) an insurance company qualified to perform investment management services under the laws of more than one state is duly appointed an "Investment Manager" with respect to the Plan, as that term is defined in Section 3 (38) of the Employee Retirement Income Security Act of 1974 (the "Act"), with the power to direct the investment and reinvestment of all or part of the Trust assets, the Investment Manager shall, unless its appointment provides otherwise, have the power to direct the Trustee in the exercise of the powers described in Paragraphs (1) through (10) inclusive of Section 5(b) hereof with respect to all or part of the Trust assets, as the case may be, and the Trustee shall, upon receipt of a copy of the Investment Manager's appointment and written acknowledgment of such appointment, satisfactory in form to the Trustee, exercise such powers as directed in writing by the Investment Manager, unless it knows that such direction is a breach of the Investment Manager's duty to act with care, skill, prudence, and diligence under the circumstances then prevailing that a prudent man acting in a like capacity and familiar with such matters would use in the conduct of an enterprise of a like character and with like aims. The Trustee shall not be liable for any diminution in the value of the Trust as a result of following any such direction or as a result of not exercising any such powers in the absence of any such direction.
If no such bank, insurance company, or registered investment adviser has been so appointed, the Trustee shall have full authority to invest and reinvest the Trust assets in accordance with the terms of this Trust Agreement and any investment guidelines promulgated by the Treasurer of the Company and the Trustee shall not be liable for any diminution in the value of the Trust as a result of the limitations of such guidelines.
(d) No person dealing with the Trustee shall be under any obligation to see to the proper application of any money paid or property delivered to the Trustee or to inquire into the Trustee's authority as to any transaction.
SECTION 6. Disposition of Income.
(a) During the term of this Trust, all income received by the Trust, net of expenses and taxes, shall be accumulated and reinvested.
SECTION 7. Accounting by Trustee.
Trustee shall keep accurate and detailed records of all investments, receipts, disbursements, and all other transactions required to be made, including such specific records as shall be agreed upon in writing between Company and Trustee. Within forty- five (45) days following the close of each calendar year and within thirty (30) days after the removal or resignation of Trustee, Trustee shall deliver to Company a written account of its administration of the Trust during such year or during the period from the close of the last preceding year to the date of such removal or resignation, setting forth all investments, receipts, disbursements and other transactions effected by it, including a description of all securities and investments purchased and sold with the cost or net proceeds of such purchases or sales (accrued interest paid or receivable being shown separately), and showing all cash, securities and other property held in the Trust at the end of such year or as of the date of such removal or resignation, as the case may be.
SECTION 8. Responsibility of Trustee.
(a) Trustee shall act with the care, skill, prudence and diligence under the circumstances then prevailing that a prudent person acting in like capacity and familiar with such matters would use in the conduct of an enterprise of a like character and with like aims, provided, however, that Trustee shall incur no liability to any person for any action taken pursuant to a direction, request or approval given by company which is contemplated by, and in conformity with, the terms of the Plan or this Trust and is given in writing by Company. In the event of a dispute between Company and a party, Trustee may apply to a court of competent jurisdiction to resolve the dispute.
(b) If Trustee undertakes or defends any litigation arising
in connection with this Trust, Company agrees to indemnify
Trustee against Trustee's costs, expenses and liabilities
(including, without limitation, attorneys' fees and expenses)
relating thereto and to be primarily liable for such payments.
If Company does not pay such costs, expenses and liabilities in a
reasonably timely manner, Trustee may obtain payment from the
Trust.
(c) Trustee may consult with legal counsel (who may also be counsel for Company generally) with respect to any of its duties or obligations hereunder.
(d) Trustee may hire agents, accountants, actuaries, investment advisors, financial consultants or other professionals to assist it in performing any of its duties or obligations hereunder.
(e) Trustee shall have, without exclusion, all powers conferred on Trustees by applicable law, unless expressly provided otherwise herein, provided, however, that if an insurance policy is held as an asset of the Trust, Trustee shall have no power to name a beneficiary of the policy other than the Trust, to assign the policy (as distinct from conversion of the policy to a different form) other than to a successor Trustee, or to loan to any person the proceeds of any borrowing against such policy.
(f) Notwithstanding any powers granted to Trustee pursuant to this Trust Agreement or to applicable law, Trustee shall not have any power that could give this Trust the objective of carrying on a business and dividing the gains therefrom, within the meaning of section 301.7701-2 of the Procedure and Administrative Regulations promulgated pursuant to the Internal Revenue Code.
SECTION 9. Compensation and Expenses of Trustee.
All Plan administrative and Trustee's fees and expenses shall be paid from the Trust unless paid by Company.
SECTION 10. Resignation and Removal of Trustee.
(a) Trustee may resign at any time by written notice to Company, which shall be effective thirty (30) days after receipt of such notice unless Company and Trustee agree otherwise.
(b) Trustee may be removed by Company on written notice to the Trustee.
(c) Upon resignation or removal of Trustee and appointment of a successor Trustee, all assets shall subsequently be transferred to the successor trustee. The transfer shall be completed within thirty (30) days after receipt of notice of resignation, removal or transfer, unless Company extends the time limit.
(d) If Trustee resigns or is removed, a successor shall be appointed, in accordance with Section 11 hereof, by the effective date of resignation or removal under paragraphs (a) or (b) of this section. If no such appointment has been made, Trustee may apply to a court of competent jurisdiction for appointment of a successor or for instructions. All expenses of Trustee in connection with the proceeding shall be allowed as administrative expenses of the Trust.
SECTION 11. Appointment of Successor.
(a) If Trustee resigns or is removed in accordance with
Section 10(a) or (b) hereof, Company may appoint any third party,
such as a bank trust department or other party that may be
granted corporate trustee powers under state law, as a successor
to replace Trustee upon resignation or removal. The appointment
shall be effective when accepted in writing by the new Trustee,
who shall have all of the rights and powers of the former
Trustee, including ownership rights in the Trust assets. The
former Trustee shall execute any instrument necessary or
reasonably requested by Company or the successor Trustee to
evidence the transfer.
SECTION 12. Amendment or Termination.
(a) This Trust Agreement may be amended by a written instrument executed by Trustee and Company. Notwithstanding the foregoing, no such amendment shall conflict with the terms of the Plan or shall make the Trust revocable.
(b) The Trust shall not terminate until the date on which Plan participants and their beneficiaries are no longer entitled to benefits pursuant to the terms of the Plan. Upon termination of the Trust any assets remaining in the Trust shall be returned to Company.
(c) Upon written approval of all participants or beneficiaries entitled to payment of benefits pursuant to the terms of the Plan, Company may terminate this Trust prior to the time all benefit payments under the Plan have been made. All assets in the Trust at termination shall be returned to Company.
SECTION 13. Miscellaneous.
(a) Any provision of this Trust Agreement prohibited by law shall be ineffective to the extent of any such prohibition, without invalidating the remaining provisions hereof.
(b) Benefits payable to Plan participants and their beneficiaries under this Trust Agreement may not be anticipated, assigned (either at law or in equity), alienated, pledged, encumbered or subjected to attachment, garnishment, levy, execution or other legal or equitable process.
(c) This Trust Agreement shall be governed by and construed in accordance with the laws of the State of Connecticut and the United States of America.
SECTION 14. Effective Date.
The effective date of this Trust Agreement shall be January 1, 1994.
Company: NORTHEAST UTILITIES SERVICE COMPANY
By:/s/ John B. Keane Name: John B. Keane Title |
Trustee: FLEET BANK, N.A.
By:/s/ Michael Callahan Name: Michael Callahan Title: Vice President |
Exhibit 10.39
Arrangement re: Use of Company Plane.
The Board of Trustees of Northeast Utilities has authorized Michael G. Morris, the Chairman, President and Chief Executive Officer and a Trustee of Northeast Utilities, to use the company plane for the purpose of commuting to and from his residences in Michigan and Florida.
Exhibit 10.41.5
CONSULTING AGREEMENT
This Consulting Agreement is entered into as of the 21st day of December, 2002, between Northeast Utilities Service Company ("the Company") and Bruce D. Kenyon ("Consultant").
1. Independent Contractor. Subject to the terms and conditions of this Consulting Agreement, the Company hereby engages Consultant as an independent contractor, within the scope and meaning of the Internal Revenue Code and Connecticut common law, to perform the services set forth herein, and the Consultant hereby accepts such engagement under these terms. This Consulting Agreement shall not render Consultant an employee, partner, agent of, or joint venturer with the Company for any purpose. Consultant is and will remain an independent contractor in his relationship to the Company.
2. Scope of Consulting Services. Pursuant to this Agreement, Consultant will serve as the Northeast Utilities ("NU") system's lead in managing NU's residual nuclear responsibilities, including, but not limited to, serving as Chairman of the Connecticut Yankee Atomic Power Company ("CY") and Yankee Atomic Electric Company ("YA") Boards of Directors and their Executive Committees, serving as a member of the Maine Yankee Atomic Power Company ("MY") Board of Directors and its Executive Committee, and serving as a member of the Vermont Yankee Nuclear Power Corporation ("VY") Board of Directors. Consultant will take direction from and provide a monthly written report suitable for review by NU's Board of Trustees, as well as providing verbal updates regarding significant matters to CEO and President - Utility Group, as appropriate. Finally, Consultant will be responsible for providing such services related to the NU system's nuclear responsibilities as may be requested from time to time by the NU CEO.
3. Term of Consulting Agreement. The Consultant agrees to provide the aforementioned services to the Company for a period of twenty-four months, beginning January 1, 2003, and ending December 31, 2004. The Company may extend this agreement for up to one additional year, with mutual agreement of Consultant, under the same terms and conditions set forth herein, by giving notice to Consultant at least 60 days in advance of December 31, 2004.
4. Consulting Fees. Consultant shall receive for his services $20,000 per month. If Consultant provides services for more than eight days per month in aggregate for a twelve month period (or shorter period if renewal is for fewer than twelve months), then Consultant shall receive for his services total payments excluding expenses at a rate of $2,500.00 per day or portion of a day. The Company will pay monthly $20,000 Consultant's fees within fifteen days after the end of each month and will pay for days exceeding ninety-six days per year within fifteen days of the receipt of the corresponding invoices from Consultant. The Company shall not be responsible for withholding taxes with respect to Consultant's fees hereunder and shall issue to the Consultant an IRS Form 1099 for any fees paid to Consultant hereunder. Consultant acknowledges and agrees that he shall remain fully responsible for the payment of any and all taxes arising out of the payment terms of this Consulting Agreement. Consultant shall have no claim against the Company hereunder for vacation pay, sick leave pay, retirement benefits, social security, worker's compensation, health or disability benefits, unemployment insurance benefits, or employee benefits of any kind.
5. Expenses. Within one month of the effective date of this Agreement, the Company shall pay to Consultant the sum of Twenty-Five Thousand Dollars ($25,000.00), which sum is intended to compensate Consultant for all expenses incurred in performance of his duties under this Agreement for the first year of its term, with the exception of travel costs to or from a location outside the New England region. A similar payment will be made in the first month of the second year of the term of this Agreement. For costs associated with travel outside the New England region, Consultant shall bill the Company for, and the Company shall reimburse him for, all reasonable and approved out-of-pocket expenses that are incurred in connection with such travel necessitated by the performance of Consultant's duties hereunder.
6. Use of Company Equipment. The Company will provide to Consultant, throughout the term of this Agreement, the use of a computer, telephone, facsimile machine, and copy machine, as well as other equipment that is reasonably necessary for Consultant to perform his duties under this Agreement. All such equipment will remain the property of the Company.
7. Confidentiality/Nondisclosure of Information: Consultant agrees that, during the term of this Agreement and at all times thereafter, the Consultant will not, either directly or indirectly, divulge, disclose or communicate to any person, firm, business, utility, association, partnership or corporation, any confidential or proprietary information or studies prepared by, for, or on behalf of the NU system, including, without limiting the generality of the foregoing, the names of any of the NU system's actual or prospective suppliers and/or customers, or the prices at which any company in the NU system sells or purchases, has sold or purchased, or potentially may sell or purchase power or fuel, marketing or financial studies, marketing or financial strategies, energy delivery or energy management studies, or any other information of, about, or concerning the business, business plans, or strategies of NU system companies that have been identified as confidential or proprietary and are not in the public forum, except with NU's prior, written consent. Consultant further agrees not to use any such information other than for the direct benefit of NU.
8. Conflicts of Interest. During the term of this Consulting Agreement, the Consultant shall devote as much of his productive time, energy and abilities to the performance of his duties hereunder as is necessary to perform the required duties in a timely and productive manner. The Consultant is expressly free to perform services for other parties while performing services for the Company.
9. Indemnification. The Company shall indemnify, defend, and hold Consultant harmless from and against any and all costs (including but not limited to reasonable litigation expenses and attorney's fees), settlements, judgments, liabilities, fines, penalties or damages whatsoever arising out of claims of third parties for which Consultant may become liable by reason of the performance of duties required by this Consulting Agreement, except, however, that such indemnification, duty to defend, and hold harmless obligations shall not extend or pertain to instances of gross negligence or intentional or willful misconduct. Except as covered in the preceding sentence, Consultant agrees to indemnify and forever hold the Company, its parent, and all other member companies of the Northeast Utilities holding company system and their respective trustees, officers, directors and employees, harmless for any damage and/or personal injury to Consultant resulting from or in any way connected with Consultant's work for the Company under this agreement.
10. Equitable Relief. The parties hereto acknowledge that the services to be rendered by Consultant under this Consulting Agreement and the rights and privileges granted to the Company under the Agreement are of a special, unique, unusual, and extraordinary character which gives them a peculiar value, the loss of which cannot be reasonably or adequately compensated by damages in any action at law, and the breach by Consultant of any of the provisions of this Agreement will cause the Company irreparable injury and damage.
11. Termination. The Company may terminate this Agreement and the engagement of Consultant hereunder upon written notice to Consultant at any time and for any reason. In the event of such termination other than for "cause" as set forth below, the Company will pay Consultant the remaining amounts due under this Consulting Agreement for the remainder of its term. If Consultant is convicted of any crime or offense, fails or refuses to comply with the written policies or reasonable directive of the Company, is guilty of serious misconduct in connection with performance hereunder, or materially breaches any provision of this Consulting Agreement, the Company may terminate this Consulting Agreement for cause and, after compensating Consultant for his services rendered through the termination date, will have no further obligations to Consultant under this Consulting Agreement. Consultant may terminate this agreement if, for reasons beyond Consultant's control, Consultant is unable to fulfill the obligations of this Agreement. In the event that Consultant terminates this Agreement, the Company, after compensating Consultant for his services rendered through the termination date, will have no further obligations to Consultant under this Consulting Agreement.
12. Successors and Assigns. All of the provisions of this Consulting Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective heirs, if any, successors, and assigns.
13. Choice of Law. The laws of the state of Connecticut shall govern the validity of this Consulting Agreement, the construction of its terms and the interpretation of the rights and duties of the parties hereto.
14. Arbitration. Any controversies arising out of the terms of this Consulting Agreement or its interpretation shall be submitted to binding arbitration pursuant to the rules and procedures of the American Arbitration Association in the State of Connecticut. The decision of the arbitrator shall be final and binding, and the arbitrator shall be authorized to award the prevailing party that party's reasonable attorneys' fees and costs, including that party's share of the arbitrator's fees, incurred in connection with the arbitration.
15. Waiver. Waiver by one party hereto of breach of any provision of this Consulting Agreement by the other shall not operate or be construed as a waiver of any other provision of this Consulting Agreement.
16. Assignment. Consultant shall not assign any of his rights under this Agreement, or delegate the performance of any of his duties hereunder, without the prior written consent of the Company.
17. Notices. Any and all notices, demands, or other communications required or desired to be given hereunder by any party shall be in writing and shall be validly given or made: (1) by the Company, if mailed certified mail, return receipt requested, to: Bruce D. Kenyon, 16 Sandpiper Point Road, Old Lyme, CT 06371; and (2) by Consultant, if mailed certified mail, return receipt requested, to Northeast Utilities Service Company, P.O. Box 270, Hartford, CT 06141.
18. Complete Agreement/Modification or Amendment. This is the complete agreement between the parties. No amendment, change or modification of this Agreement shall be valid unless in writing signed by the parties hereto.
19. Unenforceability of Provisions. If any provision of this Consulting Agreement, or any portion thereof, is held to be invalid and unenforceable, then the remainder of this Consulting Agreement shall nevertheless remain in full force and effect.
IN WITNESS WHEREOF, the undersigned have executed this Agreement as of the day and year first written above.
NORTHEAST UTILITIES BRUCE D. KENYON
SERVICE COMPANY
By: /s/ Michael G. Morris /s/ Bruce D. Kenyon
Its: Chairman, President
and CEO
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Exhibit 12
NORTHEAST UTILITIES
Ratio of Earnings to Fixed Charges
(Thousands of Dollars)
Year Year Year Year Year
1998 1999 2000 2001 2002
---- ---- ---- ---- ----
Earnings, as defined:
Net income/(loss) before extraordinary
item and cumulative effect................ $(146,753) $ 34,216 $205,295 $220,124 $152,109
Income taxes............................ 5,939 98,611 161,725 171,483 82,304
Equity in earnings of regional
nuclear generating and transmission
companies............................. (1,456) (2,905) 13,667 3,090 11,215
Minority interest....................... 9,300 9,300 9,300 3,100 -
Fixed charges, as below................. 292,622 279,851 311,175 295,141 273,711
--------- -------- -------- -------- --------
Total earnings, as defined.................. $ 159,652 $419,073 $701,162 $692,938 $519,339
========= ======== ======== ======== ========
Fixed Charges, as defined:
Interest on long-term debt.................. $ 273,824 $258,093 $200,696 $147,049 $134,471
Interest on rate reduction bonds............ - - - 87,616 115,791
Other interest.............................. (4,735) 5,558 98,605 44,993 20,249
Rental interest factor - capital............ 18,300 13,700 8,657 13,144 600
Rental interest factor -1/3 operating....... 5,233 2,500 3,217 2,339 2,600
--------- -------- -------- -------- --------
Total fixed charges, as defined............. $ 292,622 $279,851 $311,175 $295,141 $273,711
========= ======== ======== ======== ========
Ratio of earnings to fixed charges............ 0.55 1.50 2.25 2.35 1.90
========= ======== ======== ======== ========
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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. (formerly HEC 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
Select Energy, Inc. CT
Select Energy New York, Inc. DE
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 99.1
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 Company) on Form 10-K for the period ending December 31, 2002 as filed with the Securities and Exchange Commission (the Report), we, Michael G. Morris, Chairman, President and Chief Executive Officer of the Company and John H. Forsgren, Vice Chairman, Executive Vice President and Chief Financial Officer of the Company, 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 Company.
/s/ Michael G. Morris
(Signature)
Michael G. Morris
Chairman, President and Chief Executive Officer
/s/ John H. Forsgren
(Signature)
John H. Forsgren
Vice Chairman, Executive Vice President and
Chief Financial Officer
March 21, 2003
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Exhibit 99.2
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 Company) on Form 10-K for the period ending December 31, 2002 as filed with the Securities and Exchange Commission (the Report), we, Cheryl W. Grise, Chief Executive Officer of the Company and John H. Forsgren, Executive Vice President and Chief Financial Officer of the Company, 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 Company.
/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 21, 2003
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Exhibit 99.3
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 Company) on Form 10-K for the period ending December 31, 2002 as filed with the Securities and Exchange Commission (the Report), we, Cheryl W. Grise, Chief Executive Officer of the Company and John H. Forsgren, Executive Vice President and Chief Financial Officer of the Company, 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 Company.
/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 21, 2003
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Exhibit 99.4
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 Company) on Form 10-K for the period ending December 31, 2002 as filed with the Securities and Exchange Commission (the Report), we, Cheryl W. Grise, Chief Executive Officer of the Company and John H. Forsgren, Executive Vice President and Chief Financial Officer of the Company, 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 Company.
/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 21, 2003
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